10-K

____________________________________________________________________________________

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
	For the Fiscal Year Ended December 31, 2005
	OR
[  ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE      SECURITIES EXCHANGE ACT OF 1934
	For the transition period from ____________ to ____________

Commission File Number	Registrant; State of Incorporation; Address; and Telephone Number	I.R.S. Employer Identification No.
1-5324	NORTHEAST UTILITIES (a Massachusetts voluntary association) One Federal Street Building 111-4 Springfield, Massachusetts 01105 Telephone:  (413) 785-5871	04-2147929
0-00404	THE CONNECTICUT LIGHT AND POWER COMPANY (a Connecticut corporation) 107 Selden Street Berlin, Connecticut 06037-1616 Telephone:  (860) 665-5000	06-0303850
1-6392	PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE (a New Hampshire corporation) Energy Park 780 North Commercial Street Manchester, New Hampshire 03101-1134 Telephone:  (603) 669-4000	02-0181050
0-7624	WESTERN MASSACHUSETTS ELECTRIC COMPANY (a Massachusetts corporation) One Federal Street Building 111-4 Springfield, Massachusetts 01105 Telephone:  (413) 785-5871	04-1961130

____________________________________________________________________________________

Securities registered pursuant to Section 12(b) of the Act:

Registrant	Title of Each Class	Name of Each Exchange    on Which Registered
Northeast Utilities	Common Shares, $5.00 par value	New York Stock Exchange, Inc.

Securities registered pursuant to Section 12(g) of the Act:

Registrant	Title of Each Class
The Connecticut Light and Power Company	Preferred Stock, par value $50.00 per share, issuable in series, of which the following series are outstanding:

$1.90	Series	of 1947
$2.00	Series	of 1947
$2.04	Series	of 1949
$2.20	Series	of 1949
3.90%	Series	of 1949
$2.06	Series E	of 1954
$2.09	Series F	of 1955
4.50%	Series	of 1956
4.96%	Series	of 1958
4.50%	Series	of 1963
5.28%	Series	of 1967
$3.24	Series G	of 1968
6.56%	Series	of 1968

Indicate by check mark if the registrants are well-known seasoned issuers, as defined in Rule 405 of the Securities Act.

Yes	No
	Ö

Indicate by check mark if the registrants are not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes	No
	Ö

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.

Yes	No
	Ö *

*

SEC staff has granted Northeast Utilities a waiver from this requirement on November 1, 2005 with respect to its S-3 registration statement.

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.  [Ö]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer.  See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act.  (Check one):

	Large Accelerated Filer	Accelerated Filer	Non-accelerated Filer
Northeast Utilities	Ö
The Connecticut Light and Power Company			Ö
Public Service Company of New Hampshire			Ö
Western Massachusetts Electric Company			Ö

Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act).  

	Yes	No
Northeast Utilities		Ö
The Connecticut Light and Power Company		Ö
Public Service Company of New Hampshire		Ö
Western Massachusetts Electric Company		Ö

The aggregate market value of Northeast Utilities' Common Shares, $5.00 Par Value, held by non-affiliates, computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of Northeast Utilities' most recently completed second fiscal quarter (June 30, 2005) was $2,705,441,684 based on a closing sales price of $20.86 per share for the 129,695,191 common shares outstanding on June 30, 2005.  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.

Indicate the number of shares outstanding of each of the registrants' classes of common stock, as of the latest practicable date:

Company - Class of Stock	Outstanding at February 28, 2006
Northeast Utilities Common shares, $5.00 par value	153,430,063 shares
The Connecticut Light and Power Company Common stock, $10.00 par value	6,035,205 shares
Public Service Company of New Hampshire Common stock, $1.00 par value	301 shares
Western Massachusetts Electric Company Common stock, $25.00 par value	434,653 shares

Documents Incorporated by Reference:

Description		Part of Form 10-K into Which Document is Incorporated
Portions of Annual Reports of the following companies for the year ended December 31, 2005:
	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 24, 2006		Part III

GLOSSARY OF TERMS

The following is a glossary of frequently used abbreviations or acronyms that are found in this report:

COMPANIES

Acumentrics	Acumentrics Corporation
Baycorp	Baycorp Holdings, LTD
Bechtel	Bechtel Power Corporation
BMC	BMC Energy LLC
Boulos	E. S. Boulos Company
CL&P	The Connecticut Light and Power Company
Con Edison	Consolidated Edison, Inc.
CRC	CL&P Receivables Corporation
CVEC	Connecticut Valley Electric Company
CVPS	Central Vermont Public Service Corporation
CYAPC	Connecticut Yankee Atomic Power Company
DNCI	Dominion Nuclear Connecticut, Inc.
Entergy	Entergy Corporation
FPL	FPL Group, Inc.
Funding Companies	CL&P Funding LLC, PSNH Funding LLC, PSNH Funding LLC 2, and WMECO Funding LLC
Globix	Globix Corporation
HEC/CJTS	HEC/CJTS Energy Center, LLC
HEC/Tobyhanna	HEC/Tobyhanna Energy Project, LLC
HP&E	Holyoke Power and Electric
HWP	Holyoke Water Power Company
MGT	Meriden Gas Turbines, LLC
Mode 1	Mode 1 Communications
MYAPC	Maine Yankee Atomic Power Company
NAEC	North Atlantic Energy Corporation
NAESCO	North Atlantic Energy Service Corporation
NEON	NEON Communications, Inc.
NGC	Northeast Generation Company
NGS	Northeast Generation Services Company
NNECO	Northeast Nuclear Energy Company
NRG	NRG Energy, Inc.
NU or the company	Northeast Utilities
NU system	Northeast Utilities System
NU Enterprises or NUEI	NU Enterprises, Inc.
NUSCO	Northeast Utilities Service Company
PSNH	Public Service Company of New Hampshire
RMS	R.M. Services, Inc.
RRR	The Rocky River Realty Company
Select Energy	Select Energy, Inc.
SESI	Select Energy Services, Inc.
VYNPC	Vermont Yankee Nuclear Power Corporation
WMECO	Western Massachusetts Electric Company
Woods Electrical	Woods Electrical Co., Inc.
Woods Network	Woods Network Services, Inc.
YAEC	Yankee Atomic Electric Company
Yankee	Yankee Energy System, Inc.
Yankee Companies	CYAPC, MYAPC, VYNPC, and YAEC
Yankee Gas	Yankee Gas Services Company

GENERATING UNITS

Millstone 1	Millstone Unit No. 1, a 660 megawatt nuclear unit completed in 1970; Millstone 1 is currently in decommissioning status and was sold to a subsidiary of Dominion in March 2001.
Millstone 2	Millstone Unit No. 2, an 870 megawatt nuclear electric generating unit completed in 1975; Millstone 2 was sold to a subsidiary of Dominion in March 2001.
Millstone 3	Millstone Unit No. 3, a 1,154 megawatt nuclear electric generating unit completed in 1986; Millstone 3 was sold to a subsidiary of Dominion in March 2001.
Seabrook	Seabrook Unit No. 1, a 1,148 megawatt nuclear electric generating unit completed in 1986.  Seabrook 1 went into service in 1990.  Seabrook 1 was sold to a subsidiary of FPL in November 2002.

REGULATORS

CSC	Connecticut Siting Council
DEP	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 or PUHCA	Public Utility Holding Company Act of 1935
ABO	Accumulated Benefit Obligation
AFUDC	Allowance for Funds Used During Construction
ARO	Asset Retirement Obligation
BFA	Business Finance Authority
CAAA	Clean Air Act Amendments of 1990
CTA	Competitive Transition Assessment
District Court	United States District Court for the Southern District of New York
EDIT	Excess Deferred Income Taxes
EITF	Emerging Issues Task Force
EMF	Electric and Magnetic Fields
Energy Act	Energy Policy Act of 1992
EPS	Earnings Per Share
ESOP	Employee Stock Ownership Plan
ESPP	Employee Stock Purchase Plan
FASB	Financial Accounting Standards Board
FIN	FASB Interpretation No.
FMCC	Federally Mandated Congestion Charges
GSC	Generation Service Charge
Incentive Plan	Northeast Utilities Incentive Plan
IPP	Independent Power Producer
ISO-NE	New England Independent System Operator
ITC	Investment Tax Credits
kWh	Kilowatt-hour
kV	Kilovolt
LICAP	Locational Installed Capacity
LNG	Liquefied Natural Gas
LNS	Local Network Service
LOC	Letter of Credit
Merger Agreement	Agreement and Plan of Merger, as amended and restated as of January 11, 2000, between NU and Con Edison
MGP	Manufactured Gas Plant

MW	Megawatts
NEPOOL	New England Power Pool
NPDES	National Pollutant Discharge Elimination System
NYMEX	New York Mercantile Exchange
OCC	Office of Consumer Counsel
O&M	Operation and Maintenance
PBO	Projected Benefit Obligation
PBOP	Postretirement Benefits Other Than Pensions
PCRBs	Pollution Control Revenue Bonds
Money Pool or Pool	Northeast Utilities Money Pool
RNS	Regional Network Service
ROC	Risk Oversight Council
ROE	Return on Equity
RRBs	Rate Reduction Bonds
RRCs	Rate Reduction Certificates
RTO	Regional Transmission Organization
SBC	System Benefits Charge
SCRC	Stranded Cost Recovery Charge
SERP	Supplemental Executive Retirement Plan
SFAS	Statement of Financial Accounting Standards
SMD	Standard Market Design
SPE	Special Purpose Entity
TSO	Transitional Standard Offer

NORTHEAST UTILITIES

THE CONNECTICUT LIGHT AND POWER COMPANY

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE

WESTERN MASSACHUSETTS ELECTRIC COMPANY

2005 Form 10-K Annual Report
Table of Contents

	Part I		Page
Item 1.	Business		1
	The Northeast Utilities System		1
	Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995		1
	Regulated Electric Operations		2
		Distribution and Sales	2
		Regional and System Coordination	3
		FERC Regulatory Changes	3
	Rates - General		4
		Connecticut Retail Rates	4
		CL&P Rate Matters	4
		Connecticut Legislation	5
		CL&P Transmission Projects	6
		Massachusetts Retail Rates	6
		New Hampshire Retail Rates	7
	Competitive Energy Businesses		8
		Status of Divestitures	8
		Merchant Energy	9
		Retail Marketing	9
		Merchant Generation	9
		Wholesale Marketing	10
		Competitive Energy Subsidiaries' Market and Other Risks	10
		Energy Management Services and Other Businesses	11
	Regulated Gas Operations		11
	Financing Program		12
		2005 Financings	12
		2006 Financing Requirements	13
		2006 Financing Plans	13
		Financing Limitations	13
	Construction and Capital Improvement Program		17
	Nuclear Activities		17
		General	17
		Nuclear Fuel	18
		Decommissioning	18
	Other Regulatory and Environmental Matters		20
		Environmental Regulation	20
		Electric and Magnetic Fields	21
		FERC Hydroelectric Project Licensing	22

	Executive Officers of NU	23
	Employees	24
	Internet Information	24
Item 1.	Risk Factors	24
Item 1B.	Unresolved Staff Comments	28
Item 2.	Properties	28
Item 3.	Legal Proceedings	30
Item 4.	Submission of Matters to a Vote of Security Holders	34
	Part II
Item 5.	Market for Registrants' Common Equity and Related Stockholder Matters	35
Item 6.	Selected Financial Data	36
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	36
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	36
Item 8.	Financial Statements and Supplementary Data	38
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	39
Item 9A.	Controls and Procedures	39
Item 9B.	Other Information	39
	Part III
Item 10.	Directors and Executive Officers of the Registrants	40
Item 11.	Executive Compensation	43
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	50
Item 13.	Certain Relationships and Related Transactions	51
Item 14.	Principal Accountant Fees and Services	51
	Part IV
Item 15.	Exhibits and Financial Statement Schedules	53
Signatures		54

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 approximately 1.9 million customers in 419 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 199,000 residential, commercial and industrial customers in 71 cities and towns in Connecticut, including large portions of the central and southwest sections of the state.  

NU, through its wholly-owned subsidiary, NU Enterprises, Inc. (NUEI), owns a number of competitive energy and related businesses, including Northeast Generation Company (NGC), Northeast Generation Services Company (NGS), Select Energy, Inc. (Select Energy), Select Energy Services, Inc. (SESI) 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 with Select Energy.  In 2005, NU decided to exit all its competitive businesses and expects to complete the process in 2006.   

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 and, on a limited basis, to certain other New England utilities.  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).  Pursuant to the Energy Policy Act of 2005, the Public Utility Holding Company Act of 1935 (PUHCA or the 1935 Act), which regulated various aspects of the NU system's operations, was repealed on February 8, 2006 and jurisdiction over a number of areas covered by PUHCA was assumed by the FERC.

For information regarding each of the NU system's reportable segments, see Footnote 17, "Segment Information" contained within NU's 2005 Annual Report to Shareholders, which is incorporated into this Form 10-K by reference.

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 estimate, expect, anticipate, intend, plan, believe, forecast, should, could and similar expressions) are not statements of historical facts and may be forward looking.  Forward looking statement s 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, but are not limited to, actions by state and federal regulatory bodies, competition and industry restructuring, changes in economic conditions, changes in weather patterns, changes in laws, regulations or regulatory policy, expiration or initiation of significant energy supply contracts, changes in levels of capital expenditures, developments in legal or public policy doctrines, technological developments, volatility in electric and natural gas commodity markets, effectiveness of NU's risk management policies and procedures, changes in accounting standards and financial reporting regulations, fluctuations in the value of electricity positions, methods, timing and results of disposition of our competitive businesses, actions of rating agencies, terrorist attacks on domestic energy facilities, and other presently unknown or unforeseen factors.  Other risk factors are detailed from time to time in NU's reports to the SEC.

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.

REGULATED ELECTRIC OPERATIONS

Distribution and Sales

CL&P, PSNH and WMECO furnish retail franchise electric service in 149, 211 and 59 cities and towns in Connecticut, New Hampshire and Massachusetts, respectively.  In December 2005, CL&P provided retail franchise service to approximately 1.2 million customers in Connecticut, PSNH provided retail service to approximately 481,000 customers in New Hampshire and WMECO served approximately 209,000 retail customers in Massachusetts.

The following table shows the sources of 2005 electric franchise retail revenues based on categories of customers:

	CL&P	PSNH	WMECO	Total NU System
Residential	48%	42%	49%	47%
Commercial	39%	39%	34%	39%
Industrial	11%	18%	16%	13%
Other	2%	1%	1%	1%
Total	100%	100%	100%	100%

The actual changes in retail kilowatt-hour (kWh) sales for the last two years and the forecasted retail sales growth estimates for the five-year period 2006 through 2010 for CL&P, PSNH and WMECO are set forth below:

	2005 over 2004	2004 over 2003	Forecast 2006-2010 Compound Annual Growth Rate
NU System	2.6%	0.9%	1.2%
CL&P	3.0%	0.1%	1.1%
PSNH	1.9%	3.1%	1.8%
WMECO	1.4%	1.6%	0.2%

Consolidated NU retail sales rose by 2.6 percent in 2005, compared with 2004, but were down 0.1 percent on a weather-adjusted basis.  Residential electric sales were up 4.4 percent.  Commercial sales were up by 3.6 percent for the year and industrial sales decreased by 4.0 percent, due primarily to increases in energy costs, business closings and cogeneration equipment installation.  Retail sales for CL&P, PSNH and WMECO were up 3.0 percent, 1.9 percent and 1.4 percent, respectively.  There is some concern that higher electric and gas rates, driven by higher fuel costs and milder winter weather, could reduce sales in 2006.  

Regional and System Coordination

NU's electric utility subsidiaries and most other New England utilities, generation owners and marketers are parties to a series of agreements that provide for coordinated planning and operation of the region's generation and transmission facilities and the market rules by which these parties participate in the wholesale markets and acquire transmission services.  Under these arrangements, ISO New England Inc. (ISO-NE), a non-profit corporation whose board of directors and staff are independent from all market participants, has served as the Regional Transmission Operator for New England (RTO) since February 1, 2005.  ISO-NE ensures the reliability of the New England transmission system, administers the independent system operator tariff (ISO Tariff), subject to FERC approval, and oversees the efficient and competitive functioning of the regional wholesale power market.

The ISO Tariff provides for (i) a pool-wide non-discriminatory open access transmission tariff, (ii) a governance structure for stakeholder input into transmission and market rules by the New England Power Pool (NEPOOL) and (iii) market rules facilitating an open, competitive market structure.  The ISO 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 participating transmission owners’ agreement recovers its revenue requirements.

Open access transmission service over local transmission networks is provided by individual local transmission owners through their respective open access transmission tariffs, which are part of the ISO Tariff.  NU's local open access transmission tariff is also a formula rate, which was recently restructured to ensure timely recovery of NU's revenue requirements.    

Transmission revenues have been allocated since 2001 between CL&P, HWP and its wholly-owned subsidiary, Holyoke Power and Electric Company (HP&E), WMECO and PSNH based upon a net revenue requirement allocation methodology.  

FERC Regulatory Changes

The wholesale transmission revenues of NU's electric utility subsidiaries are based on rates and formulas that are approved by the FERC.  Most of NU's wholesale transmission revenues are collected through a combination of the New England regional network service (RNS) portion of the ISO Tariff and NU's local network service (LNS) portion of the ISO Tariff.  NU's LNS rate is reset on January 1 and June 1 of each year, while NU's RNS rate is reset on June 1 of each year.  Additionally, NU's LNS tariff provides for a true-up to actual costs, which ensures that NU recovers its total transmission revenue requirements, including the allowed return on equity (ROE).  In 2005, this true-up resulted in the recognition of a $2.1 million regulatory liability, including approximately $1.5 million due to NU's electric distribution companies.

As a result of the RTO start-up on February 1, 2005, the ROE in the LNS tariff was increased to 12.8 percent.  The ROE being utilized in the calculation of the current RNS rates is the sum of the 12.8 percent "base" ROE, plus a 50 basis point incentive adder for joining the RTO, or a total of 13.3 percent.  An initial decision by a FERC administrative law judge (ALJ) has set the base ROE at 10.72 percent as compared with the 12.8 percent requested the by New England RTO.  One of the adjustments made by the ALJ was to modify the underlying proxy group used to determine the ROE, resulting in a reduction in the base ROE of approximately 50 basis points.  The ALJ deferred to the FERC for final resolution on the 100 basis point incentive adder for new transmission investments, but reaffirmed the 50 basis point incentive for joining the RTO.  The New England transmission owners have challenged the ALJ's findings and recommendations through written exceptions filed on June 27, 2005 and a final order from the FERC is expected in 2006.  The result of this order, if upheld by the FERC, would be an ROE for LNS of 10.72 percent and an ROE for RNS of 11.22 percent.  When blended, the resulting "all in" ROE would be approximately 11.15 percent for the NU transmission business.  Management cannot at this time predict what ROE will ultimately be established by the FERC in these proceedings, but for purposes of current earnings accruals and estimates, the transmission business is assuming an ROE of 11.5 percent.

Effective February 1, 2006, FERC approved new rates allowing NU to collect 50 percent of the cost of construction work in progress (CWIP) for the major southwest Connecticut transmission projects in its formula LNS rate.

In November 2005, the FERC announced that it was considering a number of proposals to provide financial incentives for the construction of high-voltage electric transmission in the United States.  Those proposals included the reflecting in rate base 100 percent of the cost of CWIP; accelerated recovery of depreciation; imputing hypothetical capital structures in ratemaking; establishing ROEs for transmission owners that join RTOs; and other incentives that could improve the earnings and/or cash flows associated with NU's transmission capital expenditures.  Comments on the FERC proposals were submitted in January 2006 and final rules are expected by the summer of 2006.  

In March 2004, ISO-NE proposed at the FERC an administratively determined electric generation capacity pricing mechanism known as Locational Installed Capacity (LICAP), intended to provide a revenue stream sufficient to maintain existing generation assets and encourage the construction of new generation assets at levels sufficient to serve peak load, plus fixed reserve and contingency margins.

After opposition from state regulators, utilities and various Congressional delegations, the FERC ordered settlement negotiations before an administrative law judge to determine whether there was an acceptable alternative to LICAP.  On March 6, 2006, ISO-NE and a broad cross-section of critical stakeholders from around the region, including CL&P, PSNH and Select Energy, filed a comprehensive settlement agreement at the FERC implementing a forward capacity market (FCM) mechanism in place of LICAP.  The settlement agreement provides for a fixed level of compensation to generators from December 1, 2006 through May 31, 2010 without regard to location in New England, and annual forward capacity auctions, beginning in 2008, for one-year period ending May 31, 2011, and annually thereafter.  The settlement agreement must be approved by the FERC, and the parties have asked for a decision by June 30, 2006. According to preliminary estimates, FCM would require the operating companies to pay approximately the following amounts during the 3½-year transition period:  CL&P - $470 million; PSNH - $80 million; and WMECO - $100 million.  CL&P would be able to recover these costs from its customers through the federally mandated congestion charges (FMCC) mechanism.  PSNH and WMECO also would be able to recover these costs from their customers.

Rates - General

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.  CL&P and WMECO have divested all of their generation assets and are now acting as transmission and distribution companies.  PSNH has divested all ownership of nuclear generation but retained its fossil/hydro generation assets.  Under New Hampshire law, PSNH may not divest its fossil/hydro generation assets until April 2006 at the earliest; thereafter, divestiture may occur only if the NHPUC determines that such divestiture is in the economic interest of retail customers of PSNH.  Legislation has been proposed in New Hampshire that will extend the prohibition against any divestiture until at least July 2008.

CL&P, PSNH and WMECO have received regulatory orders allowing each to recover all or substantially all of their prudently incurred stranded costs which are pre-restructuring expenditures incurred, or commitments made for future expenditures, on behalf of customers with the expectation such expenditures would continue to be recoverable in the future through rates.  All three companies have financed significant portions of their stranded costs through the issuance of rate reduction bonds (RRBs) and rate reduction certificates (RRCs) (securitization) and are recovering the costs of securitization through rates.  As of December 31, 2005, CL&P had fully recovered all stranded costs except those being recovered through RRB-related charges, ongoing independent power producer costs, costs associated with the ongoing decommissioning of the Maine Yankee, Connecticut Yankee and Yankee Rowe nuclear units and annual decontamination and decommissioning costs payabl e under federal law.  PSNH anticipates it will complete recovery of its non-securitized stranded costs during 2006, and will continue to recover its remaining stranded costs including RRB-related charges, nuclear decommissioning and independent power production costs and certain going-forward costs relating to its generating assets.

All of NU's electric operating company customers are now able to choose their energy suppliers, with the electric companies furnishing "transitional standard offer," "default" or "transition" service to those customers who do not choose a competitive supplier.  Management recognizes that in other states electric companies have been negatively affected by the inability to recover supply costs on a timely basis.  To date, regulators have allowed the NU companies recovery of such costs in full, and management believes that current statutes and regulatory policy in Connecticut, Massachusetts and New Hampshire will continue to permit timely recovery.

Connecticut Retail Rates

CL&P Rate Matters

Since retail competition began in Connecticut in 2000, most of CL&P's customers have continued to buy their power from CL&P at standard offer rates (2000-2003) and transitional standard offer (TSO) rates (2004-2006).  Only a small number of CL&P customers (approximately 33,000 out of nearly 1.2 million at December 31, 2005) have opted for a competitive retail supplier.

In accordance with Connecticut's 2003 electric restructuring legislation, CL&P signed fixed-price contracts with six wholesale suppliers who together will serve all of CL&P's TSO requirements in 2006.  None of CL&P's suppliers for 2006 are affiliated with the company.  CL&P is fully recovering all of the payments it is making to those suppliers and has financial guarantees from each supplier to protect CL&P from loss in the event any of the suppliers encounters financial difficulties.  CL&P has not filled its generation supply requirements beyond 2006 and will in 2006 initiate new solicitation processes for its future load obligation.  

In December 2003, the DPUC issued a final decision establishing CL&P's retail distribution and transmission rates beginning on January 1, 2004 to cover a four-year period.  The decision approved an ROE of 9.85 percent with earnings above that level to be shared 50/50 between customers and shareholders.  The retail and transmission rates are included in CL&P's total TSO rates.  

In November 2004, the DPUC issued a decision that identified which specific costs imposed on CL&P by the FERC or ISO-NE constitute FMCCs and established a semi-annual proceeding to reconcile CL&P's FMCC charges that are recovered through rates.  The DPUC's decision also authorized CL&P to seek adjustments to its FMCC charges outside of a semi-annual reconciliation proceeding sooner in the event an adjustment is necessary to reflect changes necessitated by the procurement of additional power to serve CL&P's TSO load or if there is a material change in FMCC expenses.  

On May 16, 2005, the DPUC approved an interim 4.8 percent FMCC rate increase of $79.8 million, effective June 1, 2005, to recover new "reliability must run" costs not included in FMCC rates.  The DPUC approval was affirmed by the DPUC in an order dated August 24, 2005.  On August 1, 2005, CL&P submitted a reconciliation of its FMCC, Energy Adjustment Clause (EAC) and generation services charge (GSC) collections and net expenses for the period of January 1 through June 30, 2005, but proposing no rate change, and is awaiting DPUC action on that filing.  On February 1, 2006, CL&P submitted a reconciliation of its FMCC, EAC and GSC collections and net expenses for the period of January 1 through December 31, 2005, again proposing no rate change, and is also awaiting DPUC action on that filing.

The DPUC issued a final decision in December 2004 setting CL&P's TSO rates for January 1 through December 31, 2005.  The decision approved an increase of approximately 10.4 percent above the average rates in effect in January 2004.  The increase was necessary to collect higher costs for TSO generation supply and higher FMCCs.  One percentage point of the increase was necessary to implement the increase to CL&P's distribution rate previously approved for 2005.  An appeal filed by the Office of Consumer Counsel (OCC) with the Connecticut Superior Court challenging this decision was dismissed.

On December 28, 2005, the DPUC issued a final decision setting CL&P's TSO rates for 2006.  The decision approved an increase of approximately 17.5 percent above current TSO rates, effective as of January 1, 2006, and an additional TSO rate increase of approximately 4.9 percent effective as of April 1, 2006.  The increase, amounting to $676.5 million on an annual basis, was necessary to collect higher costs for TSO generation supply.   

In CL&P's 2001 competitive transition assessment (CTA) and systems benefits charge (SBC) reconciliation filing, and subsequently in a petition to reopen related proceedings, CL&P requested that a deferred intercompany tax liability associated with the intercompany sale of generation assets be excluded from the calculation of CTA revenue requirements.  In October 2003, CL&P appealed the DPUC's final decision denying CL&P's request to the Connecticut Superior Court.  A decision from the court is expected to be issued in 2006.  If CL&P's request is granted through these court proceedings, then there could be additional amounts due to CL&P from its customers.  The 2005 impact of including the deferred intercompany liability in CTA revenue requirements has been a reduction of approximately $17 million in revenue.

As a result of Connecticut legislation passed in 2005, CL&P filed for a transmission adjustment clause on August 1, 2005 with the rate tracking mechanism to be effective on July 1, 2005.  The DPUC approved the tracking mechanism, which provides for semi-annual adjustments in January and June, on December 20, 2005.  Effective January 1, 2006 the retail transmission rate was increased to recover an additional $21 million over the first six months of 2006.  CL&P adjusts its retail transmission rates on a regular basis, thereby recovering all of its retail transmission expenses on a timely basis.

A final decision relating to CL&P's streetlight assets, plant values, accounting practices and rates was issued by the DPUC on June 30, 2005.  The decision addressed, among other things, CL&P's liability for refunds to customers as of a result of past billing errors, and caused CL&P to take a $4.1 million pre-tax reserve.  CL&P's appeal of this decision to the Connecticut Superior Court is pending.  No refunds will be required to be paid until the appeal is resolved.

Connecticut Legislation

On July 6, 2005, Governor Rell signed legislation creating a mechanism to allow the DPUC to true-up, at least annually, the retail transmission charge in local electric distribution company rates based on changes in FERC-approved charges.  This mechanism will allow CL&P to include forward-looking transmission charges in its retail transmission rate and promptly recover its transmission expenditures.  In December 2005, the DPUC approved CL&P's proposal to implement the mechanism.  See "CL&P Retail Rates - CL&P Rate Matters."

On July 21, 2005, Governor Rell signed Public Act 05-01, entitled An Act Concerning Energy Independence (Act).  The Act provides for a variety of measures intended to reduce LICAP costs and other FMCC charges which represent the costs of power market rules approved by the FERC that are resulting in significantly higher costs for Connecticut.  The Act provides for incentives to electric distribution companies for their efforts in facilitating near- and long-term cost reduction measures, creates customer incentives for the development of customer-side and grid-side distributed resources and encourages new generation plants, long-term capacity contracts and

additional conservation measures.  The Act allows CL&P to own up to 200 megawatts (MW) of peaking facilities if the DPUC determines that such facilities will be more cost effective than other options for mitigating FMCCs and LICAP costs.  The DPUC has opened a number of new dockets to implement this legislation.

CL&P Transmission Projects

CL&P has undertaken a substantial transmission construction program over the past several years.  Transmission capital expenditures in Connecticut are focused primarily on four major transmission projects in southwest Connecticut.  These projects include a new 21-mile, 345 kilovolt (kV) project between Bethel, Connecticut and Norwalk, Connecticut, a 69-mile, 345 kV project between Middletown, Connecticut and Norwalk, and a related 115 kV underground project, and the replacement of the 138 kV cable between Connecticut and Long Island.  Each of these projects has received approval from the Connecticut Siting Council (CSC).  Capital expenditures for the southwest Connecticut transmission projects totaled $156 million in 2005, and total transmission expenditures were $207.8 million.  In 2006, CL&P's transmission capital expenditures in southwest Connecticut are projected to total approximately $325 million, and total transmission expenditur es are projected to total approximately $400 million.  

The Bethel to Norwalk project is currently projected to cost approximately $350 million.  The project is expected to begin to alleviate identified reliability issues in southwest Connecticut and to help offset rising federally mandated and other costs for all of Connecticut.  Work on the related substations and the transmission lines is approximately 70 percent complete.  Management estimates a project completion date of December 2006.  At December 31, 2005, CL&P has capitalized $196 million associated with this project.

On April 7, 2005, the CSC unanimously approved a proposal by CL&P and The United Illuminating Company to build a 69-mile, 345 kV transmission line from Middletown to Norwalk, Connecticut.  Approximately 24 miles of the 345 kV line will be built underground with the balance being built overhead.  The project still requires CSC review of detailed construction plans, as well as United States Army Corps of Engineers approval to bury the line beneath certain navigable rivers and Connecticut Department of Environmental Protection (DEP) approvals.  The CSC decision included provisions for low-magnetic field designs in certain areas and made variations to the proposed route.  As a result of increases due to configuration and design specification changes, current competitive bid and construction experience, and commodity price changes, CL&P's portion of the project is now estimated to cost approximately $1.05 billion.  CL&P received final te chnical approval from ISO-NE on January 20, 2006 and expects to award the major construction-related contracts during the second quarter of 2006.  CL&P expects the project to be completed by the end of 2009.  Three appeals of the CSC decision have been filed, but CL&P does not expect any of these three appeals to delay construction.  At December 31, 2005, CL&P has capitalized $41 million associated with this project.  CL&P anticipates filing its cost allocation proposal with ISO-NE during the fourth quarter of 2006.

In October 2004, CL&P and the Long Island Power Authority (LIPA) jointly filed plans with the DEP to replace an undersea 13-mile electric transmission line between Norwalk, Connecticut and Northport - Long Island, New York, consistent with a comprehensive settlement agreement reached in June 2004.  CL&P and LIPA each own approximately 50 percent of the line.  On June 20, 2005, the New York State Controller's Officer and the New York State Attorney General approved an agreement between CL&P and LIPA to replace the cable.  The CSC has previously approved the project.  State and federal permits are also expected to be issued in the second quarter of 2006.  Assuming these permits are received by no later than the second quarter of 2006 and the necessary construction contracts are signed, construction activities will begin when material lead times allow.  Management will provide the estimated removal and in-service dates when these construction contracts are signed.  At December 31, 2005, CL&P has capitalized $6 million associated with this project.

CL&P's construction of two 115 kV underground transmission lines between Norwalk and Stamford, Connecticut was approved by the CSC on July 20, 2005 and by ISO-NE on August 3, 2005.  There were no court appeals of the project, which is expected to cost approximately $120 million.  Management expects to begin major construction during 2007 and expects the lines to be in service during 2008.  At December 31, 2005, CL&P has capitalized $7 million associated with this project.

In late 2005, CL&P began construction of a new substation in Killingly, Connecticut that will improve CL&P's 345 kV and 115 kV transmission systems in northeast Connecticut.  The project is expected to be completed by the end of 2006 at a cost of approximately $32 million.  At December 31, 2005, CL&P has capitalized $2.5 million associated with this project.

During 2005, CL&P placed in service $175 million of electric transmission projects, including $70 million relating to the Bethel to Norwalk project.

For further information on NU's transmission construction program, see "Construction and Capital Improvement Program."

Massachusetts Retail Rates

In Massachusetts, as of February 28, 2005, there is only one type of service provided to customers not on competitive supply.  That service, called default or "basic" service, is procured by electric utility companies.  Pursuant to a DTE order issued in 2003, there are

now two separate solicitations for basic service.  

For smaller customers, there are two basic service solicitations each year.  In each of these solicitations, 50 percent of the basic service supply is procured for a twelve-month period; the rates in effect at any one time are an average of the prices obtained in two separate solicitations.  Basic service rates have been approved for smaller customers for the period January 1, 2006 through June 30, 2006.  The suppliers are unaffiliated entities.  The next basic service solicitation for smaller customers will take place in spring 2006.

On December 29, 2005, the DTE approved new rates for WMECO effective January 1, 2006, which included a previously approved $3 million distribution rate increase and the costs of new basic service mentioned above.  Overall average rates for all customers increased by 44 percent as a result of increased energy costs.  Under the December 2004 settlement which allowed the $3 million increase, WMECO agreed not to file for another distribution rate increase to be effective prior to January 1, 2007.

For larger customers, WMECO basic service is procured for a three-month period.  Basic service has been procured and rates approved for larger customers for the period of January 1, 2006 through March 31, 2006.  A single unaffiliated entity is the supplier.  In addition, basic service has now been procured and rates were approved by the DTE on February 17, 2006 for larger customers for the period of April 1, 2006 through June 30, 2006.  A single unaffiliated entity is the supplier.  Reflecting market prices, the approved basic service rates for larger customers for the April through June period are significantly lower than the January through March rates.  The decrease in the basic service rate for these customers will be approximately 44 percent.

WMECO has pending before the DTE its 2004 transition cost reconciliation filing made on March 31, 2005, which seeks to true up a variety of 2003 and 2004 costs.  Management does not expect this proceeding to materially affect WMECO.

New Hampshire Retail Rates

Under the terms of the "Agreement to Settle PSNH Restructuring" (Restructuring Agreement), PSNH files for approval of updated transition energy service and default energy service rates (known collectively as energy service rates or ES) periodically with the NHPUC to ensure timely recovery of its costs.  The ES rate recovers PSNH's generation and purchased power costs, including a return on PSNH's generation assets.  PSNH defers for future recovery or refund any difference between its ES revenues and the actual costs incurred.

On January 28, 2005, the NHPUC issued an order approving an ES rate of $0.0649 per kWh for the period February 1, 2005 through January 31, 2006, which included an 11 percent ROE on PSNH's generation assets.  An NHPUC order changing the ES rate to $0.0724 per kWh became effective on August 1, 2005.  

The NHPUC conducted a separate proceeding to determine a new ROE for PSNH generation.  On December 2, 2005, the NHPUC issued an order that modified the ROE calculation and required PSNH to use a generation ROE rate of 9.62 percent, effective August 1, 2005.  PSNH sought rehearing of this decision and simultaneously filed an appeal with the New Hampshire Supreme Court.  On February 10, 2006, the NHPUC denied PSNH's motion for reconsideration.  The appeal to the New Hampshire Supreme Court remains pending.  

On January 20, 2006, the NHPUC approved new ES rates of $0.0913 per kWh for the period February 1, 2006 through December 31, 2006.  This approval was facilitated by a December 14, 2005 stipulation and settlement agreement between PSNH, the NHPUC staff and New Hampshire Office of Consumer Advocate (OCA), which also allowed PSNH to implement deferred accounting treatment for its asset retirement obligations.

The stranded cost recovery charge (SCRC) allows PSNH to recover its stranded costs.  On an annual basis, PSNH files with the NHPUC a SCRC reconciliation filing for the preceding calendar year.  This filing includes the reconciliation of stranded cost revenues and costs and ES revenues and costs.  The cumulative deferral of SCRC revenues in excess of costs was $303.3 million at December 31, 2005.  This cumulative deferral will decrease the amount of non-securitized stranded costs that will have to be recovered from PSNH's customers in the future from $368.0 million to $64.7 million.

The 2004 SCRC reconciliation filing was filed with the NHPUC on May 2, 2005.  Pursuant to a settlement among PSNH, the NHPUC staff and the OCA, PSNH will be allowed to recover its 2004 ES and stranded costs without disallowances and to include its cumulative unbilled revenues in its ES and stranded cost reconciliations.  The NHPUC approved the settlement agreement as filed on December 22, 2005.  

The NHPUC deferred any action regarding PSNH's coal supply and transportation procedures until it completes a review using an outside expert.  While management believes PSNH's coal procurement and transportation policies and procedures are prudent and consistent with industry practice, it is unable to determine the impact, if any, of this review on PSNH's net income or financial position.

COMPETITIVE ENERGY BUSINESSES

NU is engaged in the retail and wholesale marketing of electricity and natural gas in the northeastern United States, the generation of electricity and the provision of energy related services to large government, industrial, commercial and institutional facilities.  In 2005, NU decided to exit all of its competitive businesses.  NU expects to complete the divestiture of substantially all of its competitive businesses by the end of 2006.  NU's principal objectives in deciding to exit its competitive businesses were:

·

To transition toward a simplified, 100% regulated business model,

·

To reduce its general business risk profile and increase its financial flexibility,  

·

To strengthen its balance sheet in order to finance its utility subsidiaries’ capital expenditure programs,

·

To enhance its earnings visibility and predictability and

·

To capitalize on the value of its generation assets in New England.

See "Status of Divestitures" below for further information.

NUEI is a wholly-owned subsidiary of NU and acts as the holding company for certain of NU's competitive energy subsidiaries.  These subsidiaries include SESI, a provider of energy management, demand-side management and related consulting services for commercial, industrial and institutional customers and electric utility companies; NGC, a corporation that acquires and manages generation facilities; NGS, a corporation that maintains and services fossil and hydroelectric facilities and provides high-voltage electrical contracting services, and Select Energy, a corporation engaged in the marketing, transportation, storage and sale of energy commodities, at wholesale and retail, in the northeastern and middle Atlantic states. The generation operations of HWP are also included in the results of NUEI.  NUEI and its integrated competitive energy business affiliates had aggregate revenues (excluding revenues from discontinued operations) of approximately $2.0 billion in 2005 as compared to approximately $2.7 billion in 2004 and had losses of $398.2 million in 2005, as compared to a loss of approximately $15.1 million in 2004.

NGC is the competitive generating subsidiary of NU and a major provider of pumped storage and conventional hydroelectric power in the northeastern United States.  NGC sells all its generation output to Select Energy, which in turn markets it to customers.  Select Energy also buys and manages the entire generation output of HWP, which consists of approximately 146 megawatts (MW) of coal-fired generation at the Mt. Tom station in Holyoke, Massachusetts (Mt. Tom Station) under an evergreen contract.  Pending their sale, the output from NGC's assets and the Mt. Tom Station is being sold in the forward or spot markets while the retail marketing business is servicing its requirements in the spot market and is no longer committed to serving Select Energy load.  See Exhibit 99.1 for certain NGC financial information.

Status of Divestitures

On March 9, 2005, NU announced that NUEI would exit its wholesale marketing business, which it conducts through its subsidiary, Select Energy, and its competitive energy services businesses.  On November 7, 2005, NU announced its decision to exit the remainder of its competitive businesses, which includes its competitive generation and retail marketing businesses.  NU intends to apply the net proceeds from the divestiture of its competitive businesses to debt reduction and the financing of the regulated businesses’ capital spending programs.  See "Construction and Capital Improvement Program."  

Set forth below is an overview of the status of the divestiture process.  For further information relating to these businesses, including 2005 results, see "Merchant Energy," "Retail Marketing,"  "Merchant Generation," "Wholesale Marketing" and "Energy Management and Other Businesses" below.  

Wholesale marketing.  In 2005, NUEI paid or agreed to pay approximately $242 million to complete the divestiture of its New England wholesale sales contracts.  All but approximately $56 million of that sum was paid in 2005.  NUEI continues to negotiate with counterparties to divest its remaining wholesale power obligations in the Pennsylvania-New Jersey-Maryland (PJM) power pool, which expire in 2008, and in New York, where its single contract expires in 2013.

Retail marketing.  NU has retained J. P. Morgan Securities, Inc. (JPMorgan) as its financial advisor in the divestiture of the retail marketing business, which provides electricity and natural gas service to approximately 30,000 customer locations in the New England, New York and PJM power pools.  Indicative bids have been received and NU expects to complete the sale of this business in mid-2006.  

Competitive generation.  JPMorgan has also been retained by NU to act as its financial advisor in the divestiture of its competitive generation, which includes NGC's 1,296 megawatts of competitive generation assets in Massachusetts and Connecticut.  NU expects to complete the sale of this business by the end of 2006.

Energy services businesses.  In 2005, NU sold two of its six competitive energy services businesses, Woods Network Services, Inc. and the New Hampshire operations of Select Energy Contracting, Inc. (SECI-NH) for a total of approximately $6.5 million.  In January 2006, the Massachusetts service location of Select Energy Contracting - Connecticut (SECI - CT), a division of SECI, was sold for approximately $2 million.  NU expects to complete the sale of SESI and Woods Electrical Company, Inc. (Woods Electrical) in 2006.  The sale or closure of NUEI's two remaining energy services businesses, Select Energy Contracting, Inc. - Connecticut and E.S. Boulos Company (Boulos), will be actively pursued during 2006.

Merchant Energy

NUEI, through Select Energy, sells multiple energy products including electricity and natural gas to retail customers in the northeastern United States.  Select Energy procures and delivers energy and capacity required to serve its electric and gas customers.  In order to support and complement its competitive energy business, Select Energy contracted in December of 1999 with NGC to purchase and market all of NGC's 1,296 MW for an initial five-year period, which contract has been extended through December 2008.  In addition, Select Energy purchases approximately 146 MW of coal-fired generation output from its affiliate, HWP, on a year-to-year basis and additional supply from other suppliers as needed to meet its load obligations.  In some instances, Select Energy utilizes generation failure insurance, options and energy futures to hedge its supply requirements.  NUEI also offers energy management consulting and construction services through its affiliate, SESI, discussed more fully below.

In 2005, Select Energy reported revenues of $1.9 billion and had retail and wholesale marketing sales of approximately 32,000 gigawatt-hours (gWh) of electricity and 64 billion cubic feet (BcF) of natural gas to approximately 31,000 customers.  During 2004, Select Energy reported revenues of $2.6 billion and had retail and wholesale marketing sales of approximately 41,000 gWh of electricity and 57 BcF of natural gas to approximately 30,000 customers.

In general, the lower level of revenues at NU Enterprises and Select Energy reflects the decision to exit the wholesale marketing business in 2005 and the sale and roll-off of the remaining contractual obligations, partially offset by increased retail marketing revenues.

Retail Marketing

Select Energy is licensed to provide retail electric supply in Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, Ohio, Pennsylvania, Virginia, the District of Columbia, New York and Rhode Island.  Within these states, Select Energy is currently registered with 44 electric distribution companies and 39 gas distribution companies to provide retail services.

Select Energy's retail marketing business had a $1.4 million improvement in performance during 2005, with net income of $6.3 million versus net income of $4.9 million in 2004 after adjusting for the effect of realizing certain in-the-money supply contracts in early 2005.  When the effects of realization of these contracts are included in retail marketing's 2005 results, it lost $22.8 million.  The stronger performance is attributed to expense reduction.  

As of December 31, 2005, Select Energy had contracts with retail electric customers throughout the Northeast who utilized over 2,000 MW of peak load at approximately 16,000 locations, including predominately commercial, industrial, institutional and governmental accounts.  During 2005, delivered retail electricity increased 6 percent from 2004 to about 11 million megawatt-hours (MWh).  No single retail electric customer accounted for more than ten percent of Select Energy's retail revenues.

During 2005, Select Energy's competitive natural gas business, which is primarily retail in nature, produced revenues of approximately $600 million, an increase from 2004 revenues of approximately $410 million.  This increase relates to both higher gas prices and higher gas volumes.  In 2005, Select Energy provided approximately 46 BcF of natural gas to approximately 15,000 retail gas customers, primarily located in Connecticut, Massachusetts, New York and Pennsylvania, compared to approximately 39.5 BcF in 2004.  These contracts generally have one-year terms and include primarily commercial, institutional, industrial and governmental accounts.  No single retail gas customer accounted for more than ten percent of Select Energy's retail gas revenues.  

NU Enterprises is in the process of selling the retail business and expects to close on the sale in mid-2006.  Because the business will likely be sold without benefit of either economic supply entitlements or output from NU Enterprises’ generation resources, the retail portfolio is substantially out of the money and the sale of the business could require NU to make a significant payment to the buyer.

Merchant Generation

NGC, NU's merchant electric generating affiliate, owns and operates a portfolio of approximately 1,296 MW of hydroelectric and pumped storage generating assets in Connecticut and Massachusetts.  NGC's portfolio consists of seven hydro facilities along the Housatonic River System; the three facilities comprising the Eastern Connecticut System, including one gas turbine, all located in Connecticut; and the Northfield Mountain pumped storage station and the Cabot and Turners Falls No. 1 hydroelectric stations located in Massachusetts.  NGC sells all of its energy and capacity to its affiliate, Select Energy, extending through 2008.  Select Energy's

performance under its contract with NGC is guaranteed by NU.  Select Energy also buys and manages the entire generation output of approximately 146 MW from HWP's Mt. Tom generating plant under a contract renewable on an annual basis.  Pending sale of its competitive generation assets, Select Energy has sold a small portion of the NGC and Mt. Tom generation in the forward markets and sells the balance bilaterally or in the spot market.  For further information relating to NU's electric generating plants, see Item 2, "Properties - Electric Generating Plants."  

NGC's contract with Select Energy extends through December 2008, but is expected to be terminated upon the sale of NGC.  During the remaining term, most 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 revenues are in the form of monthly payments at predetermined rates per unit of actual energy output.  This contract provides NGC with a stable stream of revenues, but at prices that at times are higher than average wholesale electricity prices in the markets served by NGC's facilities.

NGS manages, operates, maintains and supports electric power generating equipment, facilities and associated transmission and distribution equipment.  NGC and HWP have contracted with NGS to operate and maintain all of their generating plants.

The value of NGC's generating assets could be affected by the adoption of FCM in place of the prior LICAP proposal.  See "Regulated Electric Operations - FERC Regulatory Charges."

Wholesale Marketing

In 2005, Select Energy supplied more than 16,000 GWh of standard offer and default service load in New England and the PJM power pool, compared to 24,300 gWh in 2004, reflecting the wind down of this business.

During 2005, the wholesale marketing business lost $349 million, primarily due to having to mark to market and exit its wholesale portfolio during a period of extreme price volatility.  In 2004, that business lost $17 million due to a $48.3 million mark-to-market loss associated with certain wholesale natural gas positions established to economically hedge electricity purchased in anticipation of winning certain levels of wholesale electric load in New England.

In 2005, Select Energy revenues from CL&P were approximately $53.4 million, compared to approximately $611.3 million in 2004.

Competitive Energy Subsidiaries’ Market and Other Risks

Implementation of the decision to divest all of its competitive businesses will change the risk profile of NUEI.  NUEI will continue to be exposed to certain market risks under its remaining wholesale contracts until they expire or are divested; however, those risks will be reduced as these contracts are settled or expire.  The merchant energy business segment is comprised of the wholesale marketing business, generation assets and the retail marketing business, which will enter into contracts of varying lengths of time to buy and sell energy commodities, including electricity, natural gas, and oil to retail customers.  Market risk represents the loss that may affect the merchant energy business segment's financial results, primarily Select Energy, due to adverse changes in commodity market prices.

Risk management within Select Energy has been organized to address the market, credit and operational exposures arising from the merchant energy business segment.  A significant portion of the retail and marketing business is providing full requirements service to customers, primarily commercial, industrial, institutional and governmental accounts.  The wholesale business is still obligated to supply a number of regulated distribution companies and agencies on such basis.  The "full requirements" obligation commits Select Energy to supply the total energy requirement for the customers' load at all times.  An important component of Select Energy's risk management strategy is to manage the volume and price risks of its full requirements contracts.  These risks include unexpected fluctuations in both supply and demand due to numerous factors which are not within its control, such as weather, plant availability, exposure to transmission c ongestion costs and price volatility.

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.

Until the exit from the merchant energy business is completed, NU Enterprises will continue to be exposed to various market risks which could negatively affect the value of its remaining assets.  These assets include its remaining portfolio of wholesale energy contracts, its retail energy marketing business and its generation assets.  Market risk at this point is comprised of the possibility of adverse energy commodity price movements and, in the case of the wholesale marketing business, unexpected load ingress or egress, affecting the unhedged portion of these assets.  

NU Enterprises manages these and associated operating risks through detailed operating procedures and an internal review committee.  A separate, parent-level committee, the Risk Oversight Council (ROC), meets monthly with NU Enterprises’ leadership and upon the occurrence of specific portfolio-triggered events to review conformity of NU Enterprises’ activities, commitments and exposures to NU's risk parameters.  The ROC in turn is being integrated into NU's enterprise risk management system, which was instituted in 2005.

Energy Management Services and Other Businesses

NUEI has four affiliated companies in the energy related services business: Boulos, Woods Electrical, SESI and SECI.

Wholly-owned subsidiaries, Boulos and Woods Electrical, provide electrical construction and contracting services.  These services focus on high and medium voltage installations and upgrades and substation and switchyard construction.  Woods Network, a subsidiary of NUEI, is a network products and services company which was sold in 2005.

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.  In 2005, SESI had revenues of approximately $71.2 million.

SECI provides service contracts and mechanical and electrical contracting, primarily directed to energy systems in commercial markets.  SECI's New Hampshire operations were sold in 2005.  In 2005, SECI had revenues of approximately $69.7 million.

Mode 1 is a telecommunications subsidiary of NUEI, which, at January 1, 2005 held a $9.8 million investment in NEON Communications, Inc. (NEON).  NEON is a wholesale provider of high bandwidth communication services to customers in the Northeast and middle Atlantic states utilizing a portion of the NU system companies’ transmission and distribution facilities.  Effective March 8, 2005, NEON merged with Globix Communications, Inc. (Globix), a website hosting company, with Mode 1  receiving Globix shares equal to about five percent of Globix's outstanding shares.  Due to a decline in the value of Globix shares after the merger, NU recognized pre-tax impairment charges of $6.1 million in 2005.  Mode 1's investment in Globix at December 21, 2005 totaled $3.7 million.

REGULATED GAS OPERATIONS

Yankee is the holding company of Yankee Gas and its two active non-utility subsidiaries, NorConn, which holds certain minor properties and facilities of Yankee and its subsidiaries, and Yankee Energy Financial Services Company, which provides Yankee Gas 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 2005 was 47.7 BcF.  In 2005, total gas operating revenues of $503.3 million were comprised of the following: 47 percent residential; 28 percent commercial; 21 percent industrial; and the remaining 4 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 se rvices to customers who purchase gas from sources other than Yankee Gas.  In addition, Yankee Gas performs gas sales, gas exchanges and capacity releases to other market participants to reduce its overall gas expense.

Although Yankee Gas is not subject to the FERC's jurisdiction, the FERC does have limited oversight over certain intrastate gas transportation that Yankee Gas provides.  In addition, it regulates 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.  

Yankee Gas is constructing a liquefied natural gas (LNG) facility in Waterbury, Connecticut capable of storing the equivalent of 1.2 billion cubic feet of natural gas.  Construction of the facility began in March 2005 and is expected to be completed in time for the 2007-2008 heating season.  At December 31, 2005, the project was approximately 44 percent complete.  The facility is expected to cost approximately $108 million.  Through December 31, 2005, Yankee Gas has capitalized $46.4 million related to this project.  In 2005, Yankee Gas also spent $41.6 million on reliability improvements, new customer connections and other initiatives.

In December 2004, the DPUC approved in full a rate case settlement between Yankee Gas, the OCC and the Prosecutorial Division of the DPUC.  The decision allowed a rate increase for Yankee Gas as of January 1, 2005 in the amount of $14 million (4.1 percent to total costs, 9.4 percent to distribution portion of rates), with an allowed ROE of 9.9 percent.  Yankee Gas agreed not to file a new application for a rate increase that would become effective prior to the earlier of  the in-service date of the LNG or July 1, 2007.  

On December 23, 2005, the DPUC denied a motion by Yankee Gas for interim rate relief of $12.4 million, on or before January 12, 2006, stating that the circumstances presented by Yankee Gas’ filing did not rise to the level of a force majeure contemplated by the rate settlement as a prerequisite to such a filing.  Yankee Gas now expects to file a rate case in late 2006, with new rates to be effective the earlier of July 1, 2007 or the in-service date of the LNG facility.  

In a separate proceeding, Yankee Gas has filed supplemental information regarding $9 million of previous gas revenues recovered through its purchased gas adjustment clause during the period from September 1, 2003 to August 31, 2004.  Based on the facts of the case and the supplemental information provided to the DPUC, management believes the appropriateness of the charges to customers for the time period under review will be approved.

For additional information on the proposed expansion of Yankee Gas' natural gas delivery system, see "Construction and Capital Improvement Program."

FINANCING PROGRAM

2005 Financings  

On April 7, 2005, CL&P issued $100 million of first mortgage bonds (the Series A Bonds) with a coupon of 5.000 percent and a maturity of April 1, 2015.  CL&P also issued $100 million of first mortgage bonds (the Series B Bonds) with a coupon of 5.625 percent and a maturity of April 1, 2035.  The proceeds of both issuances were used to refinance the company's short-term borrowings, which were previously incurred to fund transmission and distribution capital expenditures.  

On July 6, 2005, CL&P entered into an agreement to extend the bank commitment for its $100 million accounts receivable sale program for an additional 364 days, through July 5, 2006.  The program is scheduled to remain in effect until July 3, 2007 but may be extended.

On July 21, 2005, Yankee Gas issued $50 million of first mortgage bonds (the Series I Bonds) with a coupon of 5.350 percent and a maturity of July 15, 2035.  The proceeds of the transaction were used to refinance the company's short-term debt and to fund its capital expenditures.

On August 11, 2005, WMECO issued $50 million in senior unsecured notes (the Series C Notes) with a coupon of 5.240 percent and a maturity of August 1, 2015.  The proceeds of this issuance were used to refinance the company's short-term debt previously incurred to fund capital expenditures.

On October 5, 2005, PSNH issued $50 million of first mortgage bonds (the Series M Bonds) with a fixed coupon of 5.60 percent and a maturity of October 5, 2035.  The proceeds of this issuance were used to refinance the company's short-term debt and to fund its capital expenditures.

On November 2, 2005, NU entered into an unsecured $600 million, 364-day credit facility, which was reduced following the increase in NU's five-year revolver and equity issuance and presently provides a total commitment of $310 million in long-term borrowings and letters of credit.  This facility will expire no later than November 30, 2007, although no advances or letters of credit will be available under the facility beyond October 30, 2006.

On December 9, 2005, CL&P, WMECO, PSNH and Yankee Gas amended their unsecured five-year revolving credit facility for $400 million by extending the expiration date by one year to November 6, 2010.  The companies will be able to borrow on a short-term basis and, subject to certain conditions, on a long-term basis.  CL&P may draw up to $200 million, and WMECO, PSNH and Yankee Gas may draw up to $100 million each from this facility, subject to the $400 million maximum for the entire facility.  

On December 9, 2005, NU amended its unsecured five-year revolving credit facility by extending the expiration date to November 6, 2010 and by increasing its borrowing limit from $500 million to $700 million.  The company will be able to borrow from this facility on a short-term basis and, subject to certain conditions, on a long-term basis.  The amended facility provides a total commitment of $700 million with a $550 million sub-limit for letters of credit.  

On December 12, 2005, NU issued 23 million common shares at $19.09 per share ($5 par value) for total proceeds of $439.1 million, before underwriting discounts and expenses.  The net proceeds will be used to finance the capital expenditures of the regulated subsidiaries and to finance the exit from the company's competitive businesses.

NU paid common dividends totaling $87.6 million in 2005, compared to $80.2 million paid in 2004, reflecting increases in the quarterly dividend rate that were effective September 30, 2005 and September 30, 2004.

Total NU system debt, including short-term debt, capitalized lease obligations and prior spent nuclear fuel liabilities, but not including RRCs and RRBs, was $3.1 billion as of December 31, 2005 (excluding SESI debt), compared with $3.1 billion as of December 31, 2004.

For more information regarding NU system financing, see "Notes to Consolidated Financial Statements" in NU's financial statements, the footnotes related to long-term debt, short-term debt, leases 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."  

2006 Financing Requirements  

The NU system's aggregate capital requirements for 2006 are approximately as follows:

	CL&P	PSNH	WMECO	Yankee Gas	Other	NU System
Construction	$600	$150	$50	$100	$0	$900
Maturities	0	0	0	0	0	0
Cash Sinking Funds*	0	0	0	0	23	23
Total	$600	$150	$50	$100	$23	$923

* 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 2006 financing requirements, see "Notes to Consolidated Financial Statements " 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."  

2006 Financing Plans

CL&P plans to issue up to $250 million of long-term debt in 2006, primarily to finance its distribution and transmission businesses and for general corporate purposes.  See "Construction and Capital Improvement Program."

The Rocky River Realty Company (RRR) plans to issue up to $25 million of long-term debt to refinance short-term debt and for general corporate purposes.

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.

Financial Covenants in Credit Facilities

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, 2005, CL&P's, WMECO's, PSNH's, and Yankee Gas' leverage ratios were 48 percent, 55 percent, 54 percent and 41 percent, respectively.  These ratios do not include RRBs and RRCs and the leverage ratio for Yankee Gas does not exclude goodwill from capitalization.

NU is allowed, under its current 364-day and five-year revolving credit agreement facilities, to maintain a debt to total capitalization (leverage ratio) of no more than 70 percent through December 31, 2005, 67.5 percent through March 31, 2006 and 65.0 percent thereafter.  At December 31, 2005, NU's leverage ratio was 60 percent.  The ratio does not include RRBs and RRCs.

Short-Term Debt Limits

The amount of short-term debt that may be incurred by NU, CL&P, WMECO, Yankee, Yankee Gas and HWP was subject to approval by the SEC under the 1935 Act during 2005.  On June 30, 2004, the SEC issued an order extending these companies’ short-term debt authority and authority to participate in the Northeast Utilities System Money Pool (Money Pool) through June 30, 2007.  The order also authorized the participation of the competitive subsidiaries in the Money Pool through June 30, 2007, but did not limit their borrowings from the Money Pool.  On October 28, 2005, the SEC issued an order adding the North Atlantic Energy Service Corporation (NAESCO) as a participant in the Money Pool, increasing HWP's short-term debt authority from $10 million to $35 million, and increasing NU's borrowing authority from $450 million to $700 million.  Although the 1935 Act was repealed as of February 8, 2006, under the FERC's transition rules all of the existing orders under the 1935 Act relevant to FERC authority will continue to be in effect until December 31, 2007, except for those related to NU, Yankee Gas and Yankee, which have no SEC or FERC borrowing limitations after February 8, 2006.  Yankee Gas’ long-term debt issuances will continue to be regulated by the DPUC.  The DPUC does not regulate Yankee Gas’ short-term debt issuances.  Except for PSNH, the remaining operating companies will be subject to FERC jurisdiction as to issuing short-term debt after February 8, 2006 and must renew any short-term debt authority after the 1935 Act order expires on December 31, 2007.  NU, Yankee Gas, NGC and Mode 1 may lend to, but may not borrow from, the Money Pool under the present Money Pool terms.  The following table shows the amount of short-term borrowings authorized for each company, as the case may be, as of December 31, 2005, and the amounts of outstanding short-term debt of those companies at the end of 2005 and as of March 1, 2 006 (in millions):

			Outstanding Short-Term Debt (1)
	Maximum Authorized Short-Term Debt		December 31, 2005		March 1, 2006
NU	$	700	$	0	$	0
CL&P	450		26.8		142.3
PSNH (2)	100		16.1		0
WMECO (3)	200		14.9		37.9
Yankee Gas	150		74.0		63.5
Yankee Energy System	50		0		0
HWP	35		15.5		18.1
Other (4)	N/A		270.7		347.3
Total			$	418.0	$	609.1

(1)

These columns include borrowings of various NU system companies from NU, other NU system companies and unaffiliated lenders.  Total NU system short-term indebtedness to unaffiliated lenders was $32 million at December 31, 2005 and $218 million at March 1, 2006.

(2)

Under applicable NHPUC regulations, PSNH can incur short-term debt up to ten percent of fixed net plant or such other amount as approved by the NHPUC.  Pursuant to a superseding order issued by the NHPUC, PSNH can incur short-term debt up to $100 million.  In the absence of an NHPUC order, PSNH's short-term debt limits were subject to periodic approval by the SEC under the 1935 Act prior to its repeal.

(3)

Pursuant to a DTE order, WMECO can lend through the Money Pool only to CL&P, HWP, Northeast Nuclear Energy Company (NNECO), Quinnehtuk and RRR.

(4)

Includes RRR, Quinnehtuk, Yankee Energy Financial Services Company, Yankee, NorConn Properties, Inc., NUEI, NGS, Boulos, Woods Electrical, Select Energy, North Atlantic Energy Corporation  (NAEC), NNECO, Select Energy New York, Inc., SESI, Properties, Inc. and NAESCO.

Debt Issuance Limitations

CL&P's charter contains preferred stock provisions restricting the amount of additional unsecured debt it may incur.  At shareholders' meetings in November 2003, CL&P obtained authorization from its preferred stockholders to issue unsecured indebtedness with a maturity of less than ten years in excess of ten percent of capitalization (but not in excess of 20 percent of capitalization) for a ten-year period expiring March 2014.  As of December 31, 2005, the amount of additional unsecured debt it could incur was $531.9 million.

CL&P's first mortgage bond indenture was amended in April 2005, with the consent of a majority of its outstanding bondholders, to eliminate certain restrictions and change the methodology for determining the amount of secured debt that can be issued and the amount of assets that can be sold under the indenture.  The new methodology requires CL&P to pass a "75 percent test", in which after giving effect to any new issuance or asset sale, the company's outstanding mortgage bonds must be less than 75 percent of its net plant.  At December 31, 2005, CL&P's outstanding mortgage bonds were 30.3 percent of its net plant.

Yankee Gas’ first mortgage bond indenture provides that additional bonds may not be issued based on bondable property additions, except for certain refunding purposes, unless: (i) net earnings during a period of twelve consecutive calendar months during the period of fifteen consecutive calendar months immediately preceding the first day of the month in which the application for additional bonds is made are at least twice the pro forma annual interest charges on outstanding bonds, certain prior lien obligations and bonds to be issued and (ii) Yankee Gas has available property credits equal to 166 2/3 percent of the principal amount of bonds to be issued.  The indenture also allows Yankee Gas to issue first mortgage bonds equal to the available amount of bonds previously issued but retired, but subject under certain conditions to meeting the net earnings for interest test just described.  Yankee Gas would need to meet this test to issue first mortgage bon ds based on any of its currently available prior redeemed bonds.  As of December 31, 2005, Yankee Gas' net earnings were 2.48 times the annual interest charges on its outstanding bonds.  If Yankee Gas is unable to pass this issuance test, it would need to issue junior debt which would not have the security of the first mortgage bond indenture.

Limitations on Liens  

NU's supplemental indentures, under which it 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.   ;As of December 31, 2005, no NU debt was secured by liens on NU assets.  Furthermore, NU may not declare or make distributions on its capital stock, acquire its capital stock (or rights thereto), or permit an NU system company to do the same, at times when there is an event of default existing under the supplemental indentures under which the amortizing notes were issued.  

The indenture under which NU issued $263 million in principal amount of 7.25 percent notes in April 2002 and $150 million in principal amount of 3.30 percent notes in June 2003 contains a limitation on liens on NU assets and a limitation on sale and leaseback transactions involving those assets.

Many of the NU system companies' financing agreements have similar restrictions on liens.

Preferred Stock Issuance Limitations  

CL&P's charter has provisions that 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, 2005, CL&P's income before interest charges was approximately 2.44 times the pro forma annual interest and preferred dividend requirements.  CL&P has no current plans to issue any preferred stock.

Dividend Payment Limitations  

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, 2005, retained earnings available for the payment of dividends totaled $330.4 million.

The Federal Power Act limits the payment of dividends by PSNH, CL&P, WMECO and Yankee Gas to retained earnings.  At December 31, 2005, retained earnings available for the payment of dividends for these companies were $232.1 million, $382.6 million, $85.0 million and $38.5 million, respectively.  Similar restrictions in the 1935 Act were eliminated with the repeal of the 1935 Act on February 8, 2006.

PSNH is limited by New Hampshire statutes to the payment of dividends not exceeding the amount of retained earnings.

NGC's bond covenants prevent NGC from making dividend payments unless (i) no default or event of default will occur from doing so, (ii) the debt service reserve account has been sufficiently funded with six months of principal and interest on the outstanding bonds, and (iii) the debt service coverage ratio for the previous four fiscal quarters (or, if shorter, since the bond issuance closing date) and

projected debt service coverage ratio for the next eight fiscal quarters is greater than or equal to (a) 1.35 if contracted generating capacity is greater than 75 percent or (b) 1.70 if contracted generating capacity is less than 75 percent. At December 31, 2005, 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 2006.

Capitalization

NU and its electric utility subsidiaries are required under the 1935 Act to maintain their consolidated common equity at a level equal to at least 30 percent of their consolidated capitalization.  In planning for the issuance of RRBs and RRCs by CL&P and PSNH in 2001, these companies obtained SEC consent for their common equity ratios to remain below 30 percent through December 31, 2006.  WMECO obtained a similar SEC consent on August 31, 2005.  As of December 31, 2005, NU's, CL&P's, WMECO's and PSNH's ratios were 34.9 percent, 32.1 percent, 31.7 percent and 33.3 percent, respectively.  These ratios include RRBs and RRCs as debt.  With the repeal of the 1935 Act on February 8, 2006, this restriction is no longer directly applicable, and the FERC has no similar requirement.

Credit  

NU provides credit assurance in the form of guarantees and letters of credit for the financial performance obligations of certain of its unregulated and regulated subsidiaries.  At December 31, 2005, the maximum level of exposure in accordance with the Financial Accounting Standards Board (FASB) Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" (FIN 45), under guarantees by NU, primarily on behalf of NUEI, totaled $989.7 million.  Computations under FIN 45 include all exposures even though they are not reasonably likely to result in exposure to NU.  Additionally, NU had $253 million of letters of credit issued at December 31, 2005, the majority of which were issued for the benefit of the unregulated subsidiaries.

NU received authorization from the SEC under the 1935 Act to provide up to $750 million of such guarantees for the benefit of its unregulated subsidiaries through June 30, 2007.  As of December 31, 2005, the value of guarantees outstanding under this limit was $567.5 million.  NU has also issued indirect guarantees of its regulated companies by issuing guarantees to surety companies.  These guarantees for the regulated companies are subject to a separate $50 million SEC limitation apart from the $750 million guarantee limit.  As of December 31, 2005, $0.2 million of guarantees were outstanding for the regulated entities.  These amounts are calculated using separate, more probabilistic and fair value-based criteria than the maximum level of exposure required to be disclosed under FIN 45.  FIN 45 requires the inclusion of all exposures without taking into account the likelihood of these exposures resulting in an actual cost to NU.  

In October 2004, the SEC authorized NU under the 1935 Act to issue guarantees of up to an aggregate $100 million through June 30, 2007 of the debt or other obligations of two of its subsidiaries, NUSCO and RRR.  These companies provide certain specialized support and real estate services to the entire NU system and occasionally enter into transactions that require financial backing from NU.  The amount of guarantees outstanding in compliance with the SEC limit under this category at December 31, 2005 was $0.2 million.

Due to repeal of the 1935 Act on February 8, 2006, NU is no longer limited in the amount of guarantees it can issue.

Ratings Triggers

Certain NU system credit financing agreements have trigger events tied to the credit ratings of certain NU system companies, as discussed below.

NU and its subsidiaries have $1.41 billion of revolving credit agreements with a number of banks.  There are no ratings triggers that would result in a default, but lower ratings could increase interest on future borrowings from the credit lines.

Select Energy has certain contracts that 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.  Were NU's unsecured ratings to decline one level to sub-investment grade, Select Energy could, under its present contracts, be asked to provide approximately $407 million of collateral or letters of credit to various unaffiliated counterparties as of December 31, 2005, and approximately $96 million to several independent system operators and unaffiliated local distribution companies as of December 31, 2005, which management believes NU would currently be able to provide.  At December 31, 2005, Select Energy could have been requested to provide $12.7 million of collateral under certain contracts which counterparties have not required to date.  NU's credit ratings are currently investment grade and its ratings outlooks a re currently stable.  Management does not believe that at this time there is a significant risk of a ratings downgrade to sub-investment grade levels.  

NGC has a debt reserve account related to its senior secured debt that can be funded with cash, an NU guarantee (if NU has an investment grade rating by Standard & Poor's and Moody’s Investors Service (Moody's) or a letter of credit (LOC) from an acceptable counterparty.  The account is currently funded with a guarantee from NU.  If NU were to be downgraded below investment grade, NGC

would then be required to substitute cash or an LOC for this guarantee.

RRR is a real estate subsidiary that owns NU's Connecticut headquarters site.  As of December 31, 2005, it had approximately $2.3 million of debt outstanding that could be affected by a ratings change.  If 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.

CONSTRUCTION AND CAPITAL IMPROVEMENT PROGRAM

The NU system's construction program expenditures are estimated to total approximately $900 million in 2006.  Of such total amount, approximately $600 million is expected to be expended by CL&P, $150 million by PSNH, $100 million by Yankee Gas and $50 million by WMECO.  This construction program data includes all anticipated costs necessary for committed projects and for those reasonably expected to become committed projects in 2006, 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 2006 in light of future developments, such as restructuring, industry consolidation, performance and other events.

CL&P plans to invest approximately $1.2 billion during the period from 2006 to 2010 to construct two new 345 kV transmission lines from inland Connecticut to Norwalk, Connecticut and $120 million for a related 115 kV underground project to meet growing electric demands in the area.  Approximately $60 million to $70 million will be invested in this period to replace an existing 138 kV 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 investment in electric plant by approximately $3.1 billion over the 2006 through 2010 timeframe.  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 investment in electric transmission would increase by nearly $2.3 billion by th e end of 2010.  See "Regulated Electric Operations-Connecticut Retail Rates."

In October 2004, PSNH received the approvals necessary to begin construction related to the conversion of one of three 50 megawatt units at the coal-fired Schiller Station to burn wood.  Construction of the $75 million Northern Wood Power Project began in 2004 and significant construction has been completed.  The project is expected to achieve commercial operation in the second half of 2006.  Construction-related expenditures for 2006 are estimated to total $10.3 million.  This project was approximately 86 percent complete on December 31, 2005.  As of December 31, 2005, PSNH has capitalized $64.7 million related to this project.

Yankee Gas will continue to emphasize system expansion of its natural gas distribution system in Connecticut and has received DPUC support for the installation of a liquefied natural gas production and storage facility in Waterbury, Connecticut capable of storing the equivalent of 1.2 billion cubic feet of natural gas and estimated to cost approximately $108 million.  Construction began in March 2005 and the facility is approximately 48 percent complete.  The plant is expected to be in service for the 2007/2008 heating season.

NUCLEAR ACTIVITIES

General

During 2005, certain NU system companies owned equity interests in three regional nuclear companies (the Yankee Companies) that separately own the Connecticut Yankee nuclear unit (CY), the Maine Yankee nuclear unit (MY), and the Yankee Rowe nuclear unit (YA).  YA, CY and MY have been permanently removed from service and are being decontaminated and decommissioned.

CL&P, PSNH, WMECO and other New England electric utilities are the stockholders of the Yankee Companies.  Each Yankee Company owns a single nuclear generating unit.  The stockholder-sponsors of each Yankee Company are responsible for proportional shares of the operating and decommissioning costs of the respective Yankee Company.  CL&P's, PSNH's and WMECO's stock ownership percentages in the Yankee Companies are set forth below:

	CL&P	PSNH	WMECO	NU System
Connecticut Yankee Atomic Power Company (CYAPC)	34.5%	5.0%	9.5%	49.0%
Maine Yankee Atomic Power Company (MYAPC)	12.0%	5.0%	3.0%	20.0%
Yankee Atomic Electric Company (YAEC)	24.5%	7.0%	7.0%	38.5%

CL&P, PSNH and WMECO sold their shares of the Vermont Yankee Atomic Power Corporation (VYNPC), owner of the Vermont Yankee nuclear unit (VY), back to VYNPC in 2003.  Prior to the sale of VY, NU subsidiaries owned 17 percent of VYNPC and, under the terms of the sale, will continue to buy 16 percent of VY's output through March 2012 at a range of fixed prices.

The NRC has broad jurisdiction over the design, construction and operation of nuclear generating stations, including the decommissioning activities at the Yankee Companies.

Nuclear Fuel

General

Nuclear fuel costs associated with nuclear plant operations include amounts for disposal of spent nuclear fuel.  The NU system companies include in their operating expense those spent fuel disposal costs accepted by the DPUC, NHPUC and DTE in rate case or fuel adjustment decisions.  Spent fuel disposal costs also are reflected in the FERC-approved wholesale charges.

High-Level Radioactive Waste  

The Nuclear Waste Policy Act of 1982 (NWPA) provides that the federal government is responsible for the permanent disposal of spent nuclear reactor fuel (SNF) and other high-level waste.  As required by the NWPA, electric utilities generating SNF and high-level waste are obligated to pay fees into a fund which would be used to cover the cost of siting, constructing, developing and operating a permanent disposal facility for this waste.  The NU system companies have been paying for such services for fuel burned on or after April 7, 1983, on a quarterly basis since July 1983.  The DPUC, NHPUC and DTE permit the fee to be recovered through rates.  For nuclear fuel used to generate electricity prior to April 7, 1983 (prior-period fuel), payment must be made upon the first delivery of spent fuel to the United States Department of Energy (DOE).  The DOE's current estimate for an available site is 2010 at the earliest.

In 2002, Congress designated the Yucca Mountain site in Nevada as the nation's repository for used nuclear fuel.  In return for payment of the fees prescribed by the NWPA, the federal government is to take title to and dispose of the utilities' high-level wastes and SNF.  There have been numerous litigation proceedings involving 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 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, with the companies’ aggregate damages estimated at between $523 million and $543 million.  The trial addressing these issues concluded on August 31, 2004 and final post-trial briefs were filed on January 28, 2005.  During the course of the trial the government filed a motion seeking permission to file a counterclaim against CYAPC and MYAPC seeking to offset the pre-1983 monies the companies are holding against an y potential damage award in this litigation.  Both MYAPC and CYAPC filed their responses on September 24, 2004.  The court's ruling on that matter is expected to be issued in the same time frame as its overall ruling in the case.

On January 23, 2004, Dominion Nuclear Connecticut, Inc. (DNCI) and Dominion Resources, Inc., on behalf of themselves, CL&P, WMECO and NUSCO, filed a similar complaint in the United States Court of Federal Claims against DOE, with respect to DOE's failure to accept spent nuclear fuel for disposal from the Millstone nuclear power station.  The complaint is subject to an automatic stay imposed by the United States Court of Federal Claims until the lead cases (including the case filed by CYAPC) go to trial on their damages claims.

Until the federal government begins accepting nuclear waste for disposal, nuclear generating plants will need to retain high-level waste and spent fuel onsite or make some other provisions for its storage.

Construction of on-site 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 complete at CY, YA and MY.  All of the spent fuel has been moved to the respective storage sites for CY, YA and MY as of April 2005, June 2003 and February 2004, respectively.  

Decommissioning

NU has significant decommissioning and plant closure cost obligations to CYAPC, YAEC and MYAPC, each of which collects these costs through wholesale FERC-approved rates charged under power purchase agreements to CL&P, PSNH and WMECO and the other non-NU sponsor companies.  These companies in turn pass these costs on to their customers through state regulatory commission-approved retail rates.

During 2002 - 2005, NU was notified by CYAPC, YAEC and MYAPC that the estimated cost of decommissioning these units and other closure costs increased over prior estimates due to higher anticipated costs for spent fuel storage, security, liability and property insurance and soil remediation.  

CYAPC's estimated decommissioning and plant closure costs for the period 2000 through 2023 have increased by approximately $395 million over the April 2000 estimate of $436 million approved by the FERC in a 2000 rate case settlement.  NU's share of these increased costs would be approximately $194 million.  In July 2004, CYAPC filed with the FERC for recovery of these increased costs.  In the filing, CYAPC sought to increase its annual decommissioning collections from $16.7 million to $93 million for a six-year period beginning on January 1, 2005.  In August 2004, the FERC issued an order accepting the rates, with collection beginning on February 1, 2005, subject to refund, and held hearings in the spring of 2005.  On November 22, 2005, the FERC trial judge issued an initial decision finding CYAPC's actions were prudent and that an increase in decommissioning collections was warranted.  However, the judge also fou nd that the total dollars requested should reflect a lower escalation rate, which reduces the collections by approximately $38 million.  A final order is expected later in 2006.  The FERC rejected other proceedings brought by certain intervenors with respect to the recoverability of the decommissioning costs from retail ratepayers.  The FERC's action is currently on appeal to the federal court.    

NU cannot at this time predict the timing or outcome of the final FERC order.  Although management believes that these costs will ultimately be recovered from the customers of CL&P, PSNH and WMECO, there is a risk that the FERC may not allow these costs to be recovered in wholesale rates.  If the FERC does not allow these costs to be recovered in wholesale rates, NU would expect the state regulatory commissions to disallow those costs in retail rates as well.  As owners of equity investments in CYAPC, CL&P, PSNH and WMECO are subject to losses if CYAPC is not successful in rate proceedings at the FERC.  For further information on this proceeding, see Item 3, "Legal Proceedings."

MYAPC filed with the FERC in October 2003 for new rates and reached a settlement with the FERC and intervening parties in September 2004 for total annual collections of approximately $27 million annually through October 2008.  

On November 23, 2005, YAEC filed a request with the FERC for recovery of additional decommissioning-related costs totaling $192.1 million (stated on a 2006 dollar basis) for completing site closure activities from October 2005 forward and storing spent nuclear fuel and other high level nuclear waste on site until 2020.  NU's share of such costs would be approximately $74 million.  On January 31, 2006, the FERC accepted the higher rates sought by YAEC, effective February 1, 2006, subject to refund after FERC hearings.  The hearings have been suspended pending settlement discussions between YAEC, the FERC and other intervenors.

YAEC, MYAPC and CYAPC are currently collecting revenues for the decommissioning of the related sites through their power purchase agreements.  YAEC ceased decommissioning collections in June 2000 but began collections again on June 1, 2003.  The table below sets forth the NU system companies' estimated share of remaining decommissioning costs of the Yankee Companies' units as of December 31, 2005, net of amounts collected in rates.  The estimates are based on the latest decommissioning cost estimates.  For information on the equity ownership of the NU system companies in each of the Yankee Companies' units, see "Nuclear Activities-General."

	CL&P		PSNH		WMECO		NU System
	(Millions)
CY*	$	91.4	$	13.2	$	25.2	$	129.8
MY*		17.3		7.2		4.3		28.8
YA*		42.7		12.2		12.2		67.1
Total	$	151.4	$	32.6	$	41.7	$	225.7

* 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 YA, CY and MY as of December 31, 2005, which have been recorded as an obligation on the books of the NU system companies.

As of December 31, 2005, 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	$	12.3	$	1.8	$	3.4		$	17.5
MY		5.7		2.4		1.4			9.5
YA		5.5		1.6		1.6			8.7
Total	$	23.5	$	5.8	$	6.4		$	35.7

In June 2003, CYAPC terminated its contract with Bechtel Power Corporation (Bechtel) for the decommissioning of CY.  For information on the settlement of litigation between CYAPC and Bechtel relating to the termination of this contract, see Item 3, "Legal Proceedings."  

OTHER REGULATORY AND ENVIRONMENTAL MATTERS

Environmental Regulation

General

The NU system and its subsidiaries are subject to various federal, state and local requirements with respect to water quality, air quality, toxic substances, hazardous waste and other environmental matters.  Additionally, the NU system's major generation and transmission facilities may not be constructed or significantly modified without a review by the applicable state agencies of the environmental impact of the proposed construction or modification.  Compliance with increasingly stringent environmental laws and regulations, particularly air and water pollution control requirements, may limit operations or require substantial investments in new equipment at existing facilities.

Surface Water Quality Requirements

The federal Clean Water Act requires every "point source" discharger of pollutants into navigable waters to obtain a National Pollutant Discharge Elimination System (NPDES) permit from the United States Environmental Protection Agency (EPA) or state environmental agency specifying the allowable quantity and characteristics of its effluent.  States may also require additional permits for discharges into state waters.  NU system facilities are in the process of obtaining or renewing all required NPDES or state discharge permits in effect.  Compliance with NPDES and state discharge permits has necessitated substantial expenditures and may require further significant expenditures, which are difficult to estimate, because of additional requirements or restrictions that could be imposed in the future, including requirements related to Sections 316(a) and 316(b) of the Clean Water Act for facilities owned by PSNH and HWP.  

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 release s.  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 cost the NU system approximately $28 million during 2005: approximately $17 million for PSNH and approximately $11 million for HWP.  

Massachusetts has recently imposed significant new emission reduction requirements on power plants, in addition to the Federal requirements.  The four pollutants regulated under standards signed into law in September 2001 are NOX, SO2, carbon dioxide (CO2) and mercury, with some limits and requirements effective in October 2006 and other limits and requirements effective in 2008 and 2012.  Interim limits for NOX and SO2 were also set for the Mt. Tom Station.  The mercury standards were finalized in June 2004.  The capital cost for Mt. Tom Station to meet current and known future Massachusetts emission reduction limits and requirements is estimated to be approximately $14 million for installation of a selective catalytic reduction (SCR) system to meet the new emission standards.  Completion of this work, expected in mid-2006, will reduce the Mt. Tom Station's NOX emissions, thus lowering the amount of NOX allowances required compared to prior ye ars.  SO2 requirements will be met by purchasing lower sulfur coals and reduction allowances.  Additional costs for compliance with mercury requirements are unknown at this time.  Effective January 1, 2006, new CO2 requirements for power plants became effective, limiting emissions from the Mt. Tom Station.  The MDEP has also proposed trading rules that, if passed, may further define compliance options.

In New Hampshire, the Multiple Pollutant Reduction Program was signed into law in May 2002.  This law addresses emissions reductions of the same four pollutants as in Massachusetts.  NOX, SO2 and CO2 have their emission caps established for current compliance beginning in 2007.  In November 2005, PSNH and various legislative, state government and environmental leaders announced that they had reached a consensus to propose legislation to reduce the level of mercury emissions from PSNH's coal-fired plants by 2013 with incentives for early reduction.  As part of the proposed legislation, PSNH's primary long-term alternative to comply with the proposed legislation would be to install wet scrubber technology at its two Merrimack coal units, which have a combined capacity of 433 MW, at a cost of approximately $250 million.  The proposed legislation is being considered during the 2006 legislative session.  

The Regional Greenhouse Gas Initiative (RGGI) is a cooperative effort by nine northeastern states including New Hampshire and Connecticut to develop a regional program for stabilizing and reducing CO2 emissions from fossil-fired electric generators.  This initiative proposes to stabilize CO2 emissions at current levels and require a ten percent reduction by 2020.  The RGGI agreement (MOU) was signed on December 20, 2005 by the states of Connecticut, Delaware, Maine, New Jersey, New Hampshire, New York and Vermont.  Each signatory state committed to propose for approval legislative and/or regulatory mechanisms to implement the program.  RGGI may impact PSNH's Merrimack, Newington and Schiller stations.  At this time, the impact of this agreement on NU cannot be determined.    

Hazardous Materials Regulations

Prior to the last quarter of the 20^th century when environmental best practices and laws were implemented, NU system companies, like most industrial companies, disposed of residues from operations by depositing or burying such materials on-site or disposing of them at off-site landfills or facilities.  Typical materials disposed of include coal gasification waste, fuel oils, ash, gasoline and other hazardous materials that might contain polychlorinated biphenyls (PCBs).  It has since been determined that deposited or buried wastes, under certain circumstances, could cause groundwater contamination or create other environmental risks.  The NU system has recorded a liability for what it believes is, based upon currently available information, its estimated environmental investigation and/or remediation costs for waste disposal sites for which the NU system companies expect to bear legal liability, and continues to evaluate the environmental impa ct 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, 2005, the liability recorded by the NU system for its estimated environmental remediation costs for known sites needing investigation and/or remediation, including those sites described below, exclusive of recoveries from insurance or from third parties, was approximately $30.7 million, representing 52 sites.  All cost estimates were made in accordance with generally accepted accounting principles where investigation and/or remediation costs are probable and reasonably estimable.  These costs could be significantly higher if additional remedial actions become necessary.  These liabilities break down as follows:

1. Under the federal Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended, commonly known as Superfund, EPA has the authority to clean up or order the clean up of hazardous waste sites and to impose the clean up costs on parties deemed responsible for the hazardous waste activities on the sites.  Responsible parties include the current owner of a site, past owners of a site at the time of waste disposal, waste transporters and waste generators.  As of December 31, 2005, the NU system was involved in four Superfund matters: one in New Jersey, two in New Hampshire and one in Kentucky, which could have a material impact on the NU system.  The NU system has established a reserve of approximately $0.7 million for its share of the clean up of these sites.  

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's.  Byproducts from the manufacture of gas using coal resulted in fuel oils, hydrocarbons, coal tar, purifier wastes, metals and other waste products that may pose risks to human health and the environment.  The NU system currently has partial or full ownership responsibilities at 28 former MGP sites.  Of the total NU system liabilities, a reserve of approximately $25.3 million has been established to address future investigation and/or remediation costs at MGP sites, of which $17.7 million is for Yankee Gas sites.

3. Other sites undergoing and/or anticipating comprehensive investigations or remediation actions under state programs located in Connecticut, Massachusetts or New Hampshire include two former fuel oil releases, two landfills, three asbestos hazard abatement projects and thirteen miscellaneous projects.  To date, a reserve of approximately $4.75 million has been established to address future investigation and/or remediation costs at these sites.

In the past, the NU system has received other claims from government agencies and third parties for the cost of remediating sites not currently owned by the NU system but affected by past NU system disposal activities and may receive more such claims in the future.  The NU system expects that the costs of resolving claims for remediating sites about which it has been notified will not be material, but cannot estimate the costs with respect to sites about which it has not been notified.

For further information on environmental liabilities, see Footnote 9B, "Commitments and Contingencies - Environmental Matters" contained within NU's 2005 Annual Report to Shareholders, which is incorporated into this Form 10-K by reference.

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.

The NU system companies have closely monitored research and government policy developments for many years and will continue to do so.  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.  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, c ould 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.

In 2004, Connecticut enacted legislation designed to reduce the magnetic field exposure associated with new transmission lines of 345 kV and above on a precautionary basis.  The CSC held hearings in January 2005 to assess proposals for mitigating EMF associated with certain of NU's proposed new overhead transmission lines.  For information on these hearings, see "Regulated Electric Operations - CL&P Transmission Projects."  In addition, the CSC is currently conducting a proceeding to adopt "EMF best management practices" to identify transmission facility design strategies to address the perceived but uncertain risks of EMF when constructing new transmission facilities.  

FERC Hydroelectric Project Licensing

New Federal Power Act licenses may be issued for hydroelectric projects for terms of 30 to 50 years as determined by the FERC. Upon the expiration of an existing license, (i) the FERC may issue a new license to the existing licensee, or (ii) the United States may take over the project or the FERC may issue a new license to a new licensee, upon payment to the existing licensee of the lesser of the fair value or the net investment in the project, plus severance damages, less certain amounts earned by the licensee in excess of a reasonable rate of return.

The NU system companies currently hold the FERC licenses for 11 hydroelectric projects totaling 16 plants.  In addition, the NU system companies own and operate five unlicensed hydroelectric projects that are currently deemed non-jurisdictional by the FERC.  These licensed and unlicensed hydroelectric projects are located in Connecticut, Massachusetts, Vermont and New Hampshire and aggregate approximately 1,367 MW of capacity.  NGC owns four licensed and four unlicensed projects with approximately 1,296 MW capacity.  PSNH owns nine hydroelectric generating stations with an aggregate of approximately 68.1 MW of capacity.

On June 23, 2004, a single, 40-year license was issued to NGC for the 109.8 MW Housatonic hydroelectric project and the 11 MW Falls Village project.  The new license incorporates the terms and conditions of the Connecticut Department of Environmental Protection (DEP) 401 water quality certification.  The license and water quality certificate require operation of the Falls Village and Bulls Bridge projects in run of river mode and specify minimum flow releases for the by pass reaches at these projects and minimum flow releases at the Stevenson project and Shepaug projects.  Upstream and downstream fish passage facilities for the Stevenson project must be designed by 2011 and constructed by 2014.  Fish passage facilities for the Shepaug and Bulls Bridge projects must be designed by 2021 and completed by 2024.  Interim upstream eel passage facilities at the Stevenson project required to be operational in 2005 were placed in operation in accordance with a FERC approved plan.  The license also requires that NGC prepare and implement a number of project plans, including recreation, shoreline management, critical habitat management, debris management, nuisance plant monitoring and historic property management plans.  NGC is in the process of preparing and filing these plans, and a number of plans have been reviewed and approved by the FERC.  NGC received an extension until April 2006 for the filing of the shoreline management plan.

PSNH's FERC license for the Merrimack River Hydroelectric Project that consists of the Amoskeag, Hooksett and Garvins Falls hydroelectric generating stations expired on December 31, 2005.  In December 2003, PSNH filed an application for a new license for the project.  The FERC issued a notice that the project was ready for environmental analysis in March 2005.  In response to the FERC's notice, comments were filed by various parties to the proceeding, including the filing of a preliminary fishway prescription by the United States Fish and Wildlife Service (USFW).  On December 19, 2005, in accordance with new regulations issued by the Departments of Agriculture, Interior and Commerce regarding appeal of mandatory license conditions and prescriptions, PSNH submitted an alternative fishway prescription and filed a request for a hearing on disputed issues of material fact related to USFW's preliminary fishway prescription.  The environmental assess ment for the project was issued on January 24, 2006 and a 30-day comment period has expired.  The current project license expired on December 31, 2005 and FERC issued an annual license for the project on January 19, 2006 on terms and subject to conditions substantially similar to the previous license.  

Licensed operating hydroelectric projects are not generally subject to decommissioning during the license term in the absence of a specific license provision which expressly permits the FERC to order decommissioning during the license term.  However, the FERC has taken the position that under appropriate circumstances it may order decommissioning of hydroelectric projects at relicensing or may require the establishment of decommissioning trust funds as a condition of relicensing.  The FERC may also require project decommissioning during a license term if a hydroelectric project is abandoned, the project license is surrendered or the license is revoked.

At this time, it appears unlikely that the FERC will order decommissioning of NGC or PSNH hydroelectric projects at relicensing or that the projects will be abandoned, surrendered or the project licenses revoked.  However, it is impossible to predict the outcome of the FERC relicensing proceedings with certainty, or to determine the impact of future regulatory actions on project economics.  Until such time as a project is ordered to be decommissioned and the terms and conditions of a decommissioning order are known, any estimates of the cost of project decommissioning are preliminary and subject to change as new information becomes available.

EXECUTIVE OFFICERS OF NU

          Name          

Age

Business Experience During Past 5 Years

Gregory B. Butler

48

Senior Vice President and General Counsel of NU since December 1, 2005 and of CL&P, PSNH and WMECO since March 9, 2006, and a Director of Northeast Utilities Foundation, Inc. since December 1, 2002; previously Senior Vice President, Secretary and General Counsel of NU from August 31, 2003 to December 1, 2005; Vice President, Secretary and General Counsel of NU from May 1, 2001 through August 30, 2003; Vice President - Governmental Affairs of NUSCO from January 1997 to May 2001.

Lawrence E. De Simone

58

President-Competitive Group of NU and President of NU Enterprises, Inc., since October 25, 2004 and Chairman, President and Chief Executive Officer of Select Energy, Inc. since February 1, 2005; previously Executive Vice President - Regulated Business and Services of PPL Corporation from January 1, 2004 to August 31, 2004; Executive Vice President - Supply of PPL Corporation from October 2001 to December 31, 2003; and President of PPL EnergyPlus from November 1, 1998 to September 30, 2001.

Cheryl W. Grisé (*)

53

Executive Vice President of NU since December 1, 2005; 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 - Utility Group of NU from May 2001 to December 1, 2005; 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.

Gary A. Long (**)

54

President and Chief Operating Officer and a Director of PSNH since July 1, 2000; previously Senior Vice President - PSNH from February 2000 through June 2000 and Vice President - Customer Service and Economic Development of PSNH from January 1994 to February 2000.

David R. McHale

45

Senior Vice President and Chief Financial Officer of NU, CL&P, WMECO and PSNH since January 1, 2005 and a Director of WMECO and PSNH since January 1, 2005; previously Vice President and Treasurer of NU, WMECO and PSNH from July 1998 to December 31, 2004.

Raymond P. Necci

54

President and Chief Operating Officer and a Director of CL&P since January 17, 2005.  Previously Vice President - Utility Group Services of NUSCO from January 1, 2002 to January 16, 2005; Vice President - Nuclear Operations of Dominion Nuclear Connecticut from March 31, 2001 to December 31, 2001; and Vice President - Nuclear Technical Services of Northeast Nuclear Energy Company from December 15, 1999 to March 31, 2001.

Leon J. Olivier

57

Executive Vice President of NU since December 1, 2005; Director of WMECO and PSNH since January 17, 2005 and a Director of CL&P since September 2001.  Previously President - Transmission Group of NU from January 17, 2005 to December 1, 2005; President and Chief Operating Officer of CL&P from September 2001 to January 2005; 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.

Rodney O. Powell

53

President and Chief Operating Officer and a Director of WMECO since January 1, 2005.  Previously Vice President - Customer Relations of CL&P from January 1, 2002 to December 31, 2004; Vice President - Central Region of CL&P from October 14, 1998 to January 1, 2002; and a Director of CL&P from June 30, 1999 to September 10, 2001.

Charles W. Shivery (***)

60

Chairman of the Board, President and Chief Executive Officer of NU since March 29, 2004; Previously, President (interim) of NU from January 1, 2004 to March 29, 2004 and a Director of Northeast Utilities Foundation since March 3, 2004; previously President - Competitive Group of NU and President and Chief Executive Officer of NU Enterprises, Inc., from June 2002 through December 2003; Co-President of Constellation Energy Group, Inc. from October 2000 to February 2002; President and Chief Executive Officer of Constellation Power Source Holdings, Inc., from 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.  

John P. Stack (****)

47

Vice President - Accounting and Controller of NU, CL&P, WMECO and PSNH since January 2002.  Previously Executive Director - Corporate Accounting and Taxes from 1998 to January 2002.

 (*)

Mrs. Grisé is a Director of MetLife, Inc. and Dana Corporation.

 (**)

Mr. Long is a Director of Citizens Bank-NH.

 (***)

Mr. Shivery is a Director of Energy Insurance Mutual, the Connecticut Business & Industry Association and Connecticut Children's Hospital.

(****)

Mr. Stack is on the Board of the Connecticut Hospice and Chairman of its Audit and Finance Committee.

EMPLOYEES

As of December 31, 2005, the NU system companies had 6,879 employees on their payrolls, excluding temporary employees, of which 2,194 were employed by CL&P, 1,332 by PSNH, 418 by WMECO, 469 by Yankee Gas, 207 by NGS, 1,599 by NUSCO, 135 by Select, 111 by SESI, 161 by SECI, 230 by Boulos and 23 by Woods Electric.  NU, NGC, NAEC, NAESCO, NNECO, Mode 1 and NUEI have no employees.   

As a result of the March 2005 decision to exit the competitive wholesale and service businesses, 39 full-time positions have been eliminated.  It is expected that the November 2005 announcement to divest NU's remaining competitive businesses will necessitate further employee reductions.  See "Competitive Energy Businesses - Status of Divestitures."

Approximately 2,435 employees of CL&P, PSNH, WMECO, HWP, NGS and Yankee Gas are covered by 15 union agreements.  During 2005 and 2006 to date, six of seven contracts under negotiation have been ratified.  One Yankee Gas physical worker contract remains in the negotiation process.  In addition to the continued negotiation of this contract, NU expects to negotiate three PSNH labor contracts in the spring of 2006.

INTERNET INFORMATION

The NU system's Web site address is http://www.nu.com.  The company makes available through its Web site a link to the SEC's EDGAR site, at which site NU's, CL&P's, WMECO's and PSNH's annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports may be reviewed.  Printed copies of these reports may be obtained free of charge by writing to the Company's Investor Relations Department at Northeast Utilities, 107 Selden Street, Berlin, Connecticut 06037.

Item 1A.

Risk Factors

NU is subject to a variety of significant risks in addition to the matters set forth under "Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995" in Item 1, "Business," above.  NU's susceptibility to certain risks, including those discussed in detail below, could exacerbate other risks.  These risk factors should be considered carefully in evaluating NU's  risk profile.

Risks Related to the Exit from the Competitive Businesses

On March 9, 2005, NU announced the decision to exit its wholesale marketing and energy services businesses, and on November 7, 2005, NU announced the decision to exit its retail marketing and competitive generation businesses, which constituted the remainder of NU's competitive business.  NU has disposed of a substantial part of its wholesale business, has sold two of its six services businesses and is in the process of selling the remainder, and is actively marketing its retail marketing business and competitive generation assets.

As of December 31, 2005, Select Energy had reached agreements to terminate or assign an estimated net 7.4 million megawatt-hours of wholesale electric sales obligations.  As of January 1, 2006, Select Energy still has an estimated 16.4 million megawatt-hours of wholesale electric sales obligations through the end of the last such obligation in 2013, all but 2.6 million megawatt-hours of which has been sourced.  However, sales volumes will likely be affected by weather, economic factors, and each contract's relative price compared with alternative sources of electricity.

The wholesale marketing business, until fully exited, will continue to present financial risk to NU from a variety of perspectives. These include earnings volatility around Select Energy's portfolio of contracts, which will be accounted for almost entirely on a mark-to-market basis until settled or exited.  NU recorded after tax losses associated with this portfolio during 2005 of $278.9 million, including $39.6 million in the fourth quarter of 2005.  NU may incur additional material charges to divest the remainder of the portfolio.  Two large remaining wholesale contracts expiring in 2007 and 2013, respectively, pose an additional level of risk due to the possibility that Select Energy may have to serve much higher levels of load than were previously anticipated.  NU recorded  pre-tax charges totaling approximately $53 million in the fourth quarter for changes in the estimates of the load forecasts related to these contracts.

In addition, the cost to exit several wholesale contracts was significantly more than Select Energy's mark-to-market, which was somewhat offset by several buyouts of municipal contracts at prices better than Select Energy's marks.  During the third quarter of 2005, Select Energy entered into a transaction under which it agreed to pay approximately $20 million in excess of its mark-to-market price to assign a number of its long-dated New England contracts to a third party.  In December 2005, Select Energy transferred the balance of its sales and purchase obligations in New England to a third party and  recognized a pre-tax loss in the fourth quarter of 2005 of $11.8 million compared to the September 30, 2005 mark-to-market.  Select Energy continues to have discussions regarding settlement of its remaining wholesale portfolio obligations.  Future contract settlements could also be at amounts higher than NU's mark-to-market amounts.  

The financial reliability of Select Energy's counterparties and its ability to manage its wholesale marketing portfolio of contracts and assets within acceptable risk parameters will be of material importance to Select Energy until these contracts are divested.  The net fair value position of the wholesale portfolio at December 31, 2005 was a net liability of $230.1 million, all which has been reflected in 2005 results.

NU's decision to exit the retail marketing and generation businesses could have material negative financial implications in 2006, depending on the outcome of a number of factors, including the resolution of certain accounting issues related to impairment of assets, recognition of closure or exit costs, recognition of losses in settling energy contracts, recognition of losses of the portfolio of retail contracts, and how the disposition of those businesses is accomplished.

Exiting from Select Energy's retail and remaining wholesale obligations could have an adverse impact on NU's liquidity, although any negative effect will be mitigated by the sale of the competitive generating assets.  The book value of NU's competitive generating assets was approximately $825 million at December 31, 2005.  NU's equity investment in its combined wholesale, retail and generation businesses is approximately $57 million at December 31, 2005.  Should NU fail to realize this equity amount on sale of these businesses after payment or assumption of all related debt, NU could incur further charges.  

To date, most of Select Energy's contract terminations have been on terms where Select Energy settled with its counterparty for a sum of money and obtained a full release from further liability on the contract.  One significant contract settlement was, and future contract terminations may be, negotiated on terms whereby Select Energy's obligations are assigned or transferred to a credit-worthy third party, but a release from Select Energy's customer is not obtained.  In such circumstances, Select Energy or another NU company will be liable to the customer should the third party default.  Any such contingent liabilities could remain open for extended periods of time.

NU currently expects, but cannot assure, that it will achieve the complete exit from its competitive businesses by the end of 2006.

Risks Related to NU Enterprises’ Wholesale and Retail Marketing and Competitive Generation Businesses

A significant portion of Select Energy's competitive energy marketing activities has been providing electricity to full requirements customers, which are primarily regulated local distribution companies (LDC) and commercial and industrial retail customers.  Under the terms of full requirements contracts, Select Energy is required to provide a percentage of the LDC's electricity requirements at all times.  The volumes sold under these contracts vary based on the usage of the LDC's retail electric customers, and usage is dependent upon factors outside of Select Energy's control, such as unanticipated migration or inflow of customers.  The varying sales volumes could be different than the supply volumes that Select Energy expected to utilize, either from its owned limited generation or from electricity purchase contracts, to serve the full requirements contracts.  Differences between actual sales volumes and supply volumes can require Select Energy to purchase additional electricity or sell excess electricity, both of which are subject to market conditions such as weather, plant availability, transmission congestion, and potentially volatile price fluctuations that can impact prices and, in turn, Select Energy's margins.

Until Select Energy disposes of its retail electric and gas marketing business, it will be subject to a number of ongoing risks which are similar, though of a lesser magnitude, to those of the wholesale marketing business.  Fluctuations in prices, fuel costs, competitive conditions, regulations, weather, transmission costs, lack of market liquidity, plant outages and other factors can all impact the retail business adversely from time to time.  Extreme price volatility in the third quarter was responsible for a decline in new business in both the retail gas and electric sectors, and could impact this segment should price volatility recur.  This factor may affect Select Energy's ability to dispose of this business in accordance with its present expectations.

The competitive generation business is also subject to certain risks.  The future values of locational installed capacity credits which may become available to the owners of generation in the New England market in the future have not been finally determined and are subject to regulatory decision-making over which NU has no control.  

Risks Related to Liquidity and Collateral Calls

NU's senior unsecured debt ratings by Moody's Investors Service and Standard & Poor's, Inc. are currently Baa2 and BBB-, respectively, with stable outlooks.  Were either of these ratings to decline to non-investment grade level, Select Energy could be asked to provide, as of December 31, 2005, approximately $407 million of collateral or letters of credit to unaffiliated counterparties and $96 million to several independent system operators and unaffiliated local distribution companies and LDCs under agreements largely guaranteed by NU.  In addition, at December 31, 2005, Select Energy could have been requested to provide $12.7 million of collateral under certain contracts which counterparties have not required to date.  While NU's credit facilities are in amounts that would be adequate to meet calls at that level, NU's ability to meet any future calls would depend on its liquidity and access to bank lines and the capital markets at such time.

Risks Related to the Need for Future Financings

NU expects to obtain the liquidity needed to fund the exit from its remaining wholesale and retail marketing businesses through bank borrowings and a portion of the proceeds from the December 2005 sale of its common shares.  While NU is reasonably confident these funds will be available on a timely basis and on reasonable terms, failure to obtain such financing could delay NU's ability to exit the competitive businesses and constrain its ability to finance regulated capital projects.  In addition, any ratings downgrade of its operating company securities ratings could negatively impact the cost or availability of capital to such companies.

Risks Associated With the Transmission Operations of NU's Utility Subsidiaries

NU, primarily through its subsidiary CL&P, has undertaken a substantial transmission capital investment program over the past several years and expects to invest approximately $2.3 billion in regulated electric transmission infrastructure from 2006 through 2010.  Included in this amount is approximately $1.3 billion for costs associated with construction of two Connecticut 345 kV transmission lines from Middletown to Norwalk and Bethel to Norwalk; replacement of an undersea electric transmission line between Norwalk and Northport, New York; and two 115 kV underground transmission lines between Norwalk and Stamford, Connecticut.  The regulatory approval process for these transmission projects has encompassed an extensive permitting, design and technical approval process.  Various factors have resulted in increased cost estimates and delayed construction.  Recoverability of all such investments in rates may be subject to prudence review at the FER C at the time such projects are placed in service.  While NU believes that all such expenses have been prudently incurred, NU cannot predict the outcome of future reviews should they occur.

The projects are expected to help alleviate identified reliability issues in southwest Connecticut and to help reduce customers’ costs in all of Connecticut.  However, if, due to further regulatory or other delays, the projected in-service date for one or more of these projects is delayed, there may be increased risk of failures in the existing electricity transmission system in southwestern Connecticut and supply interruptions or blackouts may occur.  

The successful implementation of NU's transmission construction plans is also subject to the risk that new legislation, regulations or judicial or regulatory interpretations of applicable law or regulations could impact NU's ability to meet its construction schedule and/or require NU to incur additional expenses, and may adversely affect its ability to achieve forecast levels of revenues.

Risks Associated with the Distribution Operations of NU's Utility Subsidiaries

CL&P and WMECO procure energy for a substantial portion of their customers via requests for proposal on an annual, semi-annual or quarterly basis.  There is a risk that any given solicitation will not be fully subscribed or that prices will be much higher than current prices.  CL&P and WMECO receive approvals of recovery of these contract prices from the DPUC and DTE, respectively.  While both regulators have consistently approved solicitation processes, results and recovery of costs, management cannot predict the outcome of future solicitation efforts or the regulatory proceedings related thereto.  Recent increases in fuel and energy prices could lead to consumer or regulatory resistance to prompt recovery of such costs.

The energy requirements for PSNH are currently met primarily through PSNH's generation resources or long-term fixed price contracts.  The remaining energy needs are met through spot market or bilateral energy purchases.  Unplanned forced outages can increase the level of energy purchases needed by PSNH and therefore increase the market risk associated with procuring the necessary amount of energy to meet requirements.  PSNH recovers these costs through its stranded cost recovery charge proceedings, subject to a prudence review.

Litigation-Related Risks

NU and its affiliates are engaged in litigation that could result in the imposition of large cash awards against them.  This litigation includes a civil lawsuit between Consolidated Edison, Inc. (Con Edison) and NU relating to the parties’ October 13, 1999 Agreement and Plan of Merger.

Further information regarding these legal proceedings, as well as other matters, is set forth in Item 3, "Legal Proceedings."

NU may also be subject to future litigation based on asserted or unasserted claims and cannot predict the outcome of any of these proceedings.  Adverse outcomes in existing or future litigation could result in the imposition of substantial cash damage awards against us.

Risks Associated With Environmental Regulation

NU's subsidiaries’ operations are subject to extensive federal, state and local environmental statutes, rules and regulations which regulate, among other things, air emissions, water discharges and the management of hazardous and solid waste.  In particular, more stringent regulation of carbon dioxide and mercury emissions have been proposed in various New England states.  Compliance with these requirements requires the NU system to incur significant costs relating to environmental monitoring, installation of pollution control equipment, emission fees, maintenance and upgrading of facilities, remediation and permitting.  The costs of compliance with these legal requirements may increase in the future.  An increase in such costs, unless promptly recovered, could have an adverse impact on NU's business and results of operations, financial position and cash flows.  For further information, see Item 1, "Business - Other Regulatory and Env ironmental Matters - Environmental Regulation."

The NU system's failure to comply with environmental laws and regulations, even if due to factors beyond its control or reinterpretations of existing requirements, could also increase costs.  

Existing environmental laws and regulations may be revised or new laws and regulations seeking to protect the environment may be adopted or become applicable to NU.  Revised or additional laws could result in significant additional expense and operating restrictions on NU's facilities or increased compliance costs that would negatively impact the value of NU's competitive generation assets or which may not be fully recoverable in distribution company rates for regulated generation.  The cost impact of any such legislation would be dependent upon the specific requirements adopted and cannot be determined at this time.

Severe Weather Conditions May Negatively Impact Results

Severe weather, such as ice and snow storms, hurricanes and other natural disasters, may cause outages and property damage which may require NU to incur additional costs that are generally not insured and that may not be recoverable from customers.  The cost of repairing damage to NU's operating subsidiaries' facilities and the potential disruption of their operations due to storms, natural disasters

or other catastrophic events could be substantial.  The effect of the failure of NU's facilities to operate as planned would be particularly burdensome during a peak demand period, such as during the hot summer months.  

Volatility in Electric and Gas Rates May Adversely Impact Sales

The nation's economy has been affected by the recent significant increases in energy prices, particularly fossil fuels.  The impact of these increases may lead to a decline in electricity and gas sales in NU's service territory.  Such a decline without an adjustment in rates would reduce NU's revenues and limit future growth prospects.  

Item 1B.

Unresolved Staff Comments

NU does not have any unresolved SEC staff comments.  

Item 2.

Properties

Transmission and Distribution System

At December 31, 2005, NU owned 312 transmission and 153 distribution substations that had an aggregate transformer capacity of 26,901,736 kilovoltamperes (kVa) and 1,531,166 kVa, respectively; 3,085 circuit miles of overhead transmission lines ranging from 69 kilovolt (kV) to 345 kV, and 215 cable miles of underground transmission lines ranging from 69 kV to 138 kV; 34,456 pole miles of overhead and 2,573 conduit bank miles of underground distribution lines; and 453,901 line transformers in service with an aggregate capacity of 20,342,000 kVa.

Electric Generating Plants

As of December 31, 2005, the NU system's electric generating plants were as follows:  

Owner	Name of Plant (Location)	Type	Year Installed	Claimed    Capability*     (kilowatts)
PSNH	Total - Fossil-Steam Plants	(7 units)	1952-78	999,554
	Total - Hydro-Conventional	(20 units)	1917-83	67,840
	Total - Internal Combustion	(5 units)	1968-70	101,461
	Total PSNH Generating Plant	(32 units)		1,168,855
HWP	Total - Fossil-Steam Plants	(1 unit)	1960	146,369
NGC	Total - Hydro-Conventional	(37 units)	1903-55	191,329
	Total - Hydro-Pumped Storage	(6 units)	1928-73	1,084,001
	Total - Internal Combustion	(1 unit)	1969	20,763
	Total NGC Generating Plant	(44 units)		1,296,093
Totals		77 units		2,611,317
NU System	Total - Fossil-Steam Plants	(8 units)	1952-78	1,145,923
	Total - Hydro-Conventional	(57 units)	1903-83	259,169
	Total - Hydro-Pumped Storage	(6 units)	1928-73	1,084,001
	Total - Internal Combustion	(6 units)	1968-70	177,224
NU System Totals		77 units		2,611,317

*Claimed capability represents winter ratings as of December 31, 2005.

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/or sell electricity at retail, including to provide transitional 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.  Title 16 of the Connecticut General Statutes was amended by Public Act 03-135, "An Act Concerning Revisions to the Electric Restructuring Legislation," to prohibit an electric di stribution company from owning or operating generation assets.  However, Public Act 05-01, "An Act Concerning Energy Independence," allows CL&P to own up to 200 MW of peaking facilities if the DPUC determines that such facilities will be more cost effective than other options for mitigating FMCCs and LICAP costs.  CL&P has divested all of its generation assets and is now acting as a transmission and distribution company.  See "Regulated Electric Operations - Rates - General" for more information on electric industry restructuring.

PSNH - The NHPUC, pursuant to statutory requirement, has issued orders granting PSNH exclusive franchises to distribute electricity in the respective areas in which it is now supplying such service.

In addition to the right to distribute electricity as set forth above, the franchises of PSNH include, among others, rights and powers to manufacture, generate, purchase, and transmit electricity, to sell electricity at wholesale to other utility companies and municipalities and to erect and maintain certain facilities on certain public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law.  The franchises of PSNH include the power of eminent domain.

WMECO - WMECO is authorized by its charter to conduct its electric business in the territories served by it, and has locations in the public highways for transmission and distribution lines.  Such locations are granted pursuant to the laws of Massachusetts by the Department of Public Works of Massachusetts or local municipal authorities and are of unlimited duration, but the rights thereby granted are not vested.  Such locations are for specific lines only, and for extensions of lines in public highways, further similar locations must be obtained from the Department of Public Works of Massachusetts or the local municipal authorities.  In addition, WMECO has been granted easements for its lines in the Massachusetts Turnpike by the Massachusetts Turnpike Authority and pursuant to state laws, has the power of eminent domain.   

The Massachusetts restructuring legislation defines service territories as those territories actually served on July 1, 1997 and following municipal boundaries to the extent possible.  The restructuring legislation further provides that until terminated by law or otherwise, distribution companies shall have the exclusive obligation to serve 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.  Pursuant to the Massachusetts restructuring legislation, the DTE was required to define service territories for each distribution company, including WMECO.  The DTE subsequently determined that there were advantages to the exclusivity of service territories and issued a report to the Massachusetts Legislature recommending against, in this regard, any changes to the restructuring legislation.

HWP and HP&E - HWP, and its wholly owned subsidiary HP&E, are authorized by their charters to conduct their businesses in the territories served by them.  HWP's electric business is subject to the restriction that sales be made by written contract in amounts of not less than 100 horsepower to purchasers who use the electricity in their own business in the counties of Hampden or Hampshire, Massachusetts and cities and towns in these counties, and customers who occupy property in which HWP has a financial interest, by ownership or purchase money mortgage.  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 no to distribute electricity at retail in Holyoke and surrounding towns unless other sellers can legally compete with HG&E and to amend the charters of HWP & HP&E to reflect that limitation.

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.

NGC - NGC is an exempt wholesale generator (EWG) and, as it currently operates its business, is not regulated by the DPUC or the DTE.  The FERC's authorization for EWGs such as NGC to sell wholesale electric power at market-based rates typically contains an exemption from much of the traditional public utility company rate regulation.  As an EWG, NGC is a "public utility" subject to the Federal Power Act.  The market-based rate authorization that NGC has received from the FERC exempts NGC from some, but not all, of Federal Power Act regulations, including traditional cost-based rate regulation.  However, NGC is required to file summary information concerning its power transactions on a quarterly basis with FERC.

Yankee Gas - Yankee Gas directly and from its predecessors in interest holds valid franchises to sell gas in the areas in which Yankee Gas supplies gas service.  Generally, Yankee Gas holds franchises to serve customers in areas designated by those franchises as well as in most other areas throughout Connecticut so long as those areas are not occupied and served by another gas utility under a valid franchise of its own or are not subject to an exclusive franchise of another gas utility.  Yankee Gas’ 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, the right and power to manufacture, generate, purchase, transmit and distribute gas, to sell gas at wholesale to other utility companies and municipalities and to erect and maintain certain facilities on public highways and grounds, all subject to such consents and approvals of public authorities and others as may be required by law.  The franchises include the power of eminent domain.

Item 3.

Legal Proceedings

1.

Consolidated Edison, Inc. v. NU - Merger Litigation

On March 5, 2001, Consolidated Edison, Inc. (Con Edison) advised NU that it was unwilling to close its merger with NU on the terms set forth in the parties' 1999 merger agreement (the Merger Agreement).  On March 12, 2001, NU filed suit against Con Edison seeking damages in excess of $1 billion.

On May 11, 2001, Con Edison filed an amended complaint seeking damages for breach of contract, fraudulent inducement and negligent misrepresentation in an unspecified amount, but which Con Edison's Chief Financial Officer has testified is at least $314 million.  NU disputes both Con Edison's entitlement to any damages as well as its method of computing its alleged damages.

The companies completed discovery in the litigation and submitted cross motions for summary judgment.  The court denied Con Edison's motion in its entirety, leaving intact NU's claim for breach of the Merger Agreement, and partially granted NU's motion for summary judgment by eliminating Con Edison's claims against NU for fraud and negligent misrepresentation.

In July 2003, an intervener in this litigation made the claim that NU shareholders at March 5, 2001 were entitled to damages from Con Edison, if any, and not current NU shareholders.  NU's cross-claim for summary judgment dismissing this assertion was denied in May 2004, and NU appealed to the United States Court of Appeals for the Second Circuit.

On October 12, 2005, the United State Court of Appeals for the Second Circuit issued a decision concluding that NU shareholders had no right to sue Con Edison for its alleged breach of the Merger Agreement.  As a result, the Second Circuit did not reach the second issue presented for review which was whether the right to pursue recovery of the $1 billion merger premium belongs to NU shareholders who held shares at the time of the breach or those who hold shares if and when a judgment is rendered against Con Edison.  NU filed for rehearing and suggested an en banc review on  October 26, 2005.  By order dated January 3, 2006, NU's request for rehearing was denied.  The ruling leaves intact the remaining claims between NU and Con Edison for breach of contract, which include NU's claim for recovery of costs and expenses of approximately $32 million and CEI's claim for damages of "at least $314 million."  NU senior management is curre ntly considering whether to seek certiorari review by the U.S. Supreme Court.  A petition for certiorari may be filed on or before April 1, 2006.

A status conference was held in the U.S. District Court on February 7, 2006 to discuss next steps with respect to the remaining (non-shareholder) claims between the two companies.  A scheduling order is expected to follow.

 It is not possible to predict either the outcome of this matter or its ultimate effect on NU.

2.

Wisvest-Connecticut, LLC (Wisvest) v. Select Energy, Inc. and PSEG Power Connecticut LLC v. NU

Wisvest filed suit in July 2002 against Select Energy in the Superior Court at New Britain, Connecticut.  In its complaint, Wisvest alleged that Select Energy breached its Load Asset Contract for Electrical Load dated November 23, 1999 (the Agreement), which contract expired on December 31, 2003, by unilaterally reducing the amount of electricity it proposed to purchase from Wisvest.  The complaint sought monetary damages and a declaratory judgment.    

Select Energy filed an Answer to the complaint, denying any liability.  It also filed several special defenses and counterclaims to recover approximately $5.8 million plus interest for congestion charges incurred and paid by Select Energy prior to the implementation of SMD on March 1, 2003.  Select Energy, pursuant to the contract, ultimately withheld from a final payment to Wisvest (now known as PSEG Power Connecticut LLC) approximately $6.5 million for the pre-SMD congestion and interest charges.

In a separate but related claim, PSEG Power Connecticut LLC brought suit against NU seeking to recover the $6.5 million withheld by Select Energy under an NU parent guaranty.  The cases were consolidated on the complex litigation docket in Connecticut Superior Court and NU commenced discovery.  PSEG Power Connecticut LLC moved for summary judgment on the parent guaranty; however, consideration of the motion was stayed by the court pending completion of discovery by Select Energy.  

On December 30, 2005 the case was settled and all claims and counterclaims have been withdrawn by all parties (i.e. Select, NU and PSEG Power Connecticut LLC) to the lawsuit.

3.

Constellation Power Source, Inc. (Constellation) v. Select Energy, Inc.

This case involves a dispute between Select Energy and Constellation over responsibility for socialized congestion charges imposed by ISO-NE prior to the implementation of Standard Market Design (SMD) on March 1, 2003, and who is responsible for congestion charges and losses following implementation of SMD.  Constellation filed a complaint in the U.S. District Court for the District of Connecticut against Select Energy claiming that Select Energy was responsible for pre- and post-SMD congestion and losses amounting to approximately $9.7 million.  Select Energy filed a counterclaim seeking to recover the $2.5 million in pre-SMD charges that Constellation has refused to pay.  Discovery has concluded and the case is expected to go to trial in May 2006.

4.

NRG Bankruptcy

On May 14, 2003, NRG and certain of its affiliates filed for Chapter 11 protection in the United States Bankruptcy Court for the Southern District of New York (Bankruptcy Court).  The filing affects relationships between various NU companies and the NRG companies.

A.

Station Service

NRG has disputed its responsibility to pay for the provision of station service by CL&P to NRG's Connecticut generating plants.  The FERC issued a decision on December 20, 2002 that NRG had agreed that station service from CL&P would be subject to CL&P's applicable retail rates, and that states (i.e., the DPUC) have jurisdiction over the delivery of power to end users even where, as here, power is not delivered via distribution facilities.  NRG refused CL&P's subsequent demand for payment, and on April 3, 2003, CL&P petitioned the DPUC for a declaratory order enforcing the FERC's December 20, 2002 decision.  Prior to the issuance of  a decision by the DPUC, NRG filed a petition under Chapter 11 of the U.S. Bankruptcy Code, staying any further action by the DPUC.

On September 18, 2003, the Bankruptcy Court approved the parties' stipulation to submit the station service issue to arbitration for a determination of liability and damages which will fix CL&P's claim in bankruptcy.  The parties are currently pursuing arbitration of the issues in dispute but no hearing dates have been scheduled.  On December 17, 2003, the DPUC issued a decision in CL&P's rate case that addressed the issue that CL&P had first raised to the DPUC in its April 3, 2003 filing.  The DPUC affirmatively stated that CL&P has been appropriately administering its station service rates.  Subsequently, however, in unrelated proceedings, the FERC issued a series of orders with conflicting policy direction, which call into question its December 20, 2002 NRG order.  

B.

Yankee Gas

On October 9, 2002, NRG informed Yankee Gas that its affiliate, Meriden Gas Turbines, LLC (MGT), was permanently shutting down or abandoning its Meriden power plant project, and requested that Yankee Gas cease its construction activities and begin an orderly wind down of its work relating to the project.  Based on NRG's statement that it expected that Yankee Gas would draw on a $16 million letter of credit (LOC), Yankee Gas drew down the full amount of the LOC.  On November 12, 2002, MGT filed suit against Yankee Gas in Meriden Superior Court, claiming that Yankee Gas breached the agreement with MGT (MGT Agreement) and seeking a declaratory ruling from the court that Yankee Gas wrongfully drew down the $16 million LOC.  In April 2003, Yankee Gas filed its answer to MGT's complaint and asserted a counterclaim to recover its losses arising out of MGT's termination of the MGT Agreement.

Yankee Gas has filed an amended answer and counterclaim and an application for a prejudgment remedy (PJR) seeking to attach sufficient assets to secure a judgment on Yankee Gas’ counterclaims and a preliminary injunction seeking to enjoin a sale of MGT's assets, including the MGT project itself.  Hearings were held on Yankee Gas’ applications and the court ordered the parties to participate in mediation, which was held on September 21, 2004.  The mediation was unsuccessful and on October 7, 2004, the court denied Yankee Gas’ application for a PJR and preliminary injunction.  The parties subsequently reached a settlement in principle of their claims; however, MGT has since requested the court to place the case back on the trial calendar.  The parties are currently awaiting a scheduling order from the court.

C.

Congestion Charges

On August 5, 2002, CL&P withheld the past due congestion charges from its payment to NRG pursuant to contractual provisions allowing the withholding of disputed sums.  CL&P continued to withhold congestion charges from its monthly payments to NRG, through March 1, 2003, and at present is withholding approximately $28 million.  On November 28, 2001, CL&P filed a complaint against NRG in Connecticut Superior Court alleging breach of contract arising from the failure of NRG to pay approximately $29.6 million of socialized congestion charges.  The case was removed to U.S. District Court for the District of Connecticut.  NRG filed a counterclaim seeking recovery of all amounts CL&P has withheld.  Discovery is complete and CL&P's motion for summary judgment is pending.  No trial date is currently scheduled.

5.

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.

On February 16, 2005, the U.S. District Court for the Southern District of Texas (the court to which the case was transferred after Hawkins removed it from the Connecticut Superior Court to Federal Court) entered an order dismissing the apportionment complaint (including the claims against NU, NUSCO and CL&P) with prejudice and remanding the case to the Waterbury Superior Court.  Subsequently, Hawkins appealed the February 16, 2005 order to the U. S. District Court of Appeals for the Fifth Circuit, where the appeal is pending.

6.

CYAPC Decommissioning Dispute

A.

Bechtel Power Corporation (Bechtel) Litigation

On June 14, 2003, CYAPC terminated its contract with Bechtel for the decommissioning of the Connecticut Yankee nuclear power plant, due to Bechtel's history of incomplete and untimely performance and refusal to perform the remaining decommissioning work.

In June 2003, Bechtel filed a complaint against CYAPC in Connecticut Superior Court.  Bechtel's complaint asserted claims for breach of contract, negligent misrepresentation, commercial impracticability, breach of CYAPC's duty of good faith and fair dealing, wrongful termination, and violation of the Connecticut Unfair Trade Practices Act.  On August 22, 2003, CYAPC filed its answer and counterclaims, including counts for breach of contract, negligent misrepresentation and breach of duty of good faith and fair dealing.

On June 18, 2004, Bechtel requested the court to grant a prejudgment remedy in the amount of $93.5 million by garnishing CYAPC's assets, the CYAPC shareholders contributions to the decommissioning trust, and proceeds of DOE litigation.

On October 27, 2004, Bechtel and CYAPC entered into an agreement under which Bechtel relinquished its right to seek garnishment of the decommissioning trusts and related payments, in return for the potential attachment of CYAPC's real property, and an amount totaling $41.7 million (representing shareholder equity) that the sponsors would pay into a separate escrow account through June 30, 2007.  On January 30, 2006, the court ruled that Bechtel could attach CYAPC's property up to the amount of $7.9 million and its shareholder equity in the amount of $41.7 million plus earned interest.

On December 3, 2004, Bechtel filed an offer of judgment to settle its claims for a payment of $20 million by CYAPC, conditioned on CYAPC's withdrawal of its counterclaim, which offer was rejected by CYAPC.  On February 22, 2005, CYAPC filed an offer of judgment to settle its counterclaims for a payment of $65 million by Bechtel, conditioned on Bechtel's withdrawal of its claims, which offer was rejected by Bechtel.  Had one of the parties subsequently won the case in an amount equal to or greater than its offer, the court would have added 12 percent annual interest on that award, computed from the date of the party's claim, which is June 23, 2003 in the case of Bechtel's claim, and August 22, 2003 in the case of CYAPC's counterclaim.  

On March 7, 2006, CYAPC and Bechtel executed a settlement agreement terminating the court litigation.  Bechtel has agreed to pay CYAPC $15 million and withdraw from the FERC proceeding referred to below, and CYAPC will withdraw its termination of the contract for default and deem it terminated by agreement.

B.

FERC Proceeding

On July 1, 2004, CYAPC filed with the FERC to increase its decommissioning collections from $16.7 million per year (in 2000 dollars) to $93 million per year (in 2003 dollars) for the six-year period beginning January 1, 2005.  The 2003 estimate projects an increase of $395.6 million in 2003 dollars and a total cost to complete decommissioning of $831.3 million in 2003 dollars.  The increases largely reflect increased costs of security and insurance, the continuing cost of storing spent nuclear fuel that the DOE has failed to remove, the additional costs to CYAPC for it to manage the decommissioning activities that were Bechtel's responsibilities and declining financial markets.

On August 30, 2004, the FERC issued an order accepting the CYAPC rate filing, suspending collections for five months and establishing hearing procedures.  Bechtel was allowed to intervene in the FERC case.  The FERC also denied the DPUC/OCC's petition for declaratory order, which had requested that the FERC determine that CYAPC's wholesale purchasers (its utility owners) were responsible for all decommissioning costs, including imprudent costs, but could only pass through to retail ratepayers prudent costs.  The FERC held that, under the Federal Power Act, its responsibility was to determine just and reasonable wholesale rates, and not determine retail rates.

The FERC administrative law judge conducted hearings on the reasonableness of the decommissioning rates in the spring of 2005.  The DPUC argued that CYAPC's imprudent management of the decommissioning project while Bechtel was the contractor resulted in schedule delays and costs increases and recommended a disallowance in the range of approximately $225 to $234 million.  Bechtel claimed that it was impossible for it to fulfill its contract obligations, CYAPC was not justified in terminating its contract and CYAPC's approach to the remaining decommissioning work was faulty.  The FERC trial staff argued that CYAPC should have used a lower gross domestic product (GDP) escalation rate in calculating the level of decommissioning charges and that use of such rate would reduce charges by $36 million.  In post trial briefs, the FERC trial staff also claimed that CYAPC's actions were imprudent and increases in decommissioning charges should be disallowed.

In an initial decision rendered on November 22, 2005, the FERC trial judge found no imprudence on CYAPC's part, and thus there was no basis for a rate disallowance.  However, the trial judge agreed with the FERC trial staff's lower GDP escalator for calculating the decommissioning rate increase.  Briefs addressing these issues are due in January and February 2006 and a final FERC order is expected later in 2006.

Management cannot predict the outcome of this litigation or its impact on NU.  

NU's electric operating subsidiaries collectively own 49.0 percent of CYAPC, as follows: CL&P - 34.5 percent, PSNH - 5.0 percent and WMECO - 9.5 percent.

7.

Northern Wood Power Project

In August 2003, PSNH sought the approval of the NHPUC to modify one of its older 50 MW coal-fired generating stations, Unit 5 at Schiller Station in Portsmouth (Northern Wood Power Project), to a technologically advanced fluidized bed boiler capable of burning wood, with the plan to burn locally sourced low-grade wood fuel.  This project would qualify Schiller Unit 5 to receive revenues from the sale of renewable energy certificates necessary to fulfill renewable portfolio standard requirements in various New England states..  In May 2004, the NHPUC approved the Northern Wood Power Project and a risk/reward cost-recovery mechanism jointly offered by PSNH, the New Hampshire Governor's Office of Energy and Planning, the New Hampshire Office of Consumer Advocate, and the New Hampshire Timberland Owners’ Association.  Ground-breaking for the project took place on October 15, 2004.  The NHPUC's orders approving the Northern Wood Power Project w ere appealed to the New Hampshire Supreme Court by four existing wood-fired generating plants.  On April 4, 2005, the Supreme Court rejected the appeal and affirmed the NHPUC's approval Order.  The project is expected to commence commercial operation in the second half of 2006.  

8.

Enron Bankruptcy Claim

CL&P has a pending rejection damages claim against Enron Power Marketing, Inc. (EPMI) in the U. S. Bankruptcy Court for the Southern District of New York in the amount of $42.9 million.  The claimed damages result from the rejection of the December 22, 2000 electricity purchase agreement between EPMI and CL&P.  The Connecticut Resource Recovery Authority- related claim was objected to by EPMI and CL&P has filed its response.  An amended scheduling and discovery order was entered on December 14, 2005 providing that experts and documents must be disclosed over the next few months.  A status conference is scheduled for June 1, 2006.

Rulings by the bankruptcy judge on similar claims by different creditors of Enron and its subsidiaries may adversely affect the value of CL&P's $42.9 million rejection damages claim.  Management cannot predict the outcome of this litigation or its impact on CL&P.

9.

Connecticut MGP Cost Recovery

By letter dated August 5, 2004, Yankee Gas and CL&P (NU Companies) demanded contribution from UGI Utilities, Inc. (UGI) for past and future remediation costs related to MGP operations on thirteen sites currently or formerly owned by the NU Companies in a number of different locations throughout the State of Connecticut.  The NU Companies allege that UGI controlled operations of the plants at various times throughout the period 1883 to 1941.  According to the NU Companies’ demand letter, investigation and remedial costs at the sites to date total approximately $10 million and complete remediation costs for all sites could total $182 million.  The NU Companies are seeking a fair and equitable contribution for these costs from UGI.  UGI is reviewing the information provided by the NU Companies and is investigating the claim.

10.

Other Legal Proceedings

The following sections of Item 1, "Business" discuss additional legal proceedings: See "Regulated Electric Operations," and "Regulated Gas Operations" for information about various state restructuring and rate proceedings, civil lawsuits related thereto, and information about proceedings relating to power, transmission and pricing issues; "Competitive System Businesses" for information on issues relating to the operation of the merchant energy business, the provision of energy services and related matters; "Nuclear Activities" for information related to high-level nuclear waste; and "Other Regulatory and Environmental Matters" for information about proceedings involving surface water and air quality requirements, toxic substances and hazardous waste, EMF, licensing of hydroelectric projects, and other matters.  In addition, see Item 1A, "Risk Factors" for general information about several signif icant risks.

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, CL&P, PSNH or WMECO.

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
2005	First	$	19.45	$	17.84
	Second	21.22		18.11
	Third	21.79		19.47
	Fourth	20.08		17.61
2004	First	$	20.10	$	18.35
	Second	19.50		17.70
	Third	19.49		18.50
	Fourth	20.03		17.30

There were no purchases made by or on behalf of NU or any "affiliated purchaser" (as defined in Rule 10b-18(a)(3) under the Securities Exchange Act of 1934), of common stock during the fourth quarter of the year ended December 31, 2005.

As of January 31, 2006, there were 53,183 common shareholders of NU on record.  As of the same date, there were a total of 1,996,864 common shares issued, including 175,006,183 unallocated Employee Stock Ownership Plan (ESOP) shares held in the ESOP trust.

On February 14, 2006, the NU Board of Trustees approved the payment of 17.5 cent per share dividend, payable on March 31, 2006, to shareholders of record as of March 1, 2006.  

On January 31, 2005, the NU Board of Trustees approved the payment of a 16.25 cent per share dividend, payable on March 31, 2005, to shareholders of record as of March 1, 2005.

On April 12, 2005, the NU Board of Trustees approved the payment of a 16.25 cent per share dividend, payable on June 30, 2005, to shareholders of record as of June 1, 2005.

On May 10, 2005, the NU Board of Trustees approved the payment of a 17.5 cent per share dividend, payable on September 30, 2005, to shareholders of record as of September 1, 2005.

On October 11, 2005, the NU Board of Trustees approved the payment of a 17.5 cent per share dividend, payable on December 30, 2005, to shareholders of record as of December 1, 2005.

On January 12, 2004, the NU Board of Trustees approved the payment of a 15 cent per share dividend, payable on March 31, 2004, to shareholders of record as of March 1, 2004.  

On April 13, 2004, the NU Board of Trustees approved the payment of a 15 cent per share dividend, payable on June 30, 2004, to shareholders of record as of June 1, 2004.

On May 10, 2004, the NU Board of Trustees approved the payment of a 16.25 cent per share dividend, payable on September 30, 2004, to shareholders of record as of September 1, 2004.

On October 12, 2004, the NU Board of Trustees approved the payment of a 16.25 cent per share dividend, payable on December 30, 2004, to shareholders of record as of December 1, 2004.

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 the "Notes to Consolidated Financial Statements," within NU's 2005 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 2005 and 2004, CL&P approved and paid $53.8 million and $47.1 million of common stock dividends to NU.

During 2005 and 2004, PSNH approved and paid $42.4 million and $27.2 million of common stock dividends, respectively, to NU.

During 2005 and 2004, WMECO approved and paid approximately $7.7 million and $6.5 million of common stock dividends, respectively, to NU.

For information regarding securities authorized for issuance under equity compensation plans, see Item 12, "Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters," included in this report on Form 10-K.  

Item 6.

Selected Financial Data

NU.  Reference is made to information under the heading "Selected Consolidated Financial Data" contained within NU's 2005 Annual Report to Shareholders, which information is incorporated herein by reference.

CL&P.  Reference is made to information under the heading "Selected Consolidated Financial Data" contained within CL&P's 2005 Annual Report, which information is incorporated herein by reference.  

PSNH.  Reference is made to information under the heading "Selected Consolidated Financial Data" contained within PSNH's 2005 Annual Report, which information is incorporated herein by reference.

WMECO.  Reference is made to information under the heading "Selected Consolidated Financial Data" contained within WMECO's 2005 Annual Report, which information is incorporated herein by reference.

Item 7.

Management's Discussion and Analysis of Financial Condition and Results of Operations

NU.  Reference is made to information under the heading "Management's Discussion and Analysis and Results of Operations" contained within NU's 2005 Annual Report to Shareholders, which information is incorporated herein by reference.

CL&P.  Reference is made to information under the heading "Management's Discussion and Analysis and Results of Operations" contained within CL&P's 2005 Annual Report, which information is incorporated herein by reference.

PSNH.  Reference is made to information under the heading "Management's Discussion and Analysis and Results of Operations" contained within PSNH's 2005 Annual Report, which information is incorporated herein by reference.

WMECO.  Reference is made to information under the heading "Management's Discussion and Analysis and Results of Operations" contained within WMECO's 2005 Annual Report, which information is incorporated herein by reference.

Item 7A.

Quantitative and Qualitative Disclosures about Market Risk

Market Risk Information

The merchant energy business utilizes the sensitivity analysis methodology to disclose quantitative information for its commodity price risks (including where applicable capacity and ancillary components).  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 price components, or other similar price changes.  Under sensitivity analysis, the fair value of the portfolio is a function of the underlying commodity components, contract prices and market prices represented by each derivative 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 pr ices.

NU Enterprises - Retail Marketing Portfolio:  When conducting sensitivity analyses of the change in the fair value of Select Energy's retail marketing portfolio, which would result from a hypothetical change in the future market price of electricity and natural gas, the fair values of the contracts are determined from models that take into consideration estimated future market prices of electricity and natural gas, 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 marketing portfolio, which includes cash flow and fair value hedges and electricity and natural gas contracts, assuming a 10 percent change in forward market prices.  At December 31,

2005, a 10 percent increase in market price would have resulted in a pre-tax decrease in fair value of $30 million ($18 million after-tax) and a 10 percent decrease would have resulted in a pre-tax increase in fair value of $30.1 million ($18 million after-tax).

The impact of a change in electricity and natural gas prices on Select Energy's retail marketing portfolio at December 31, 2005, is not necessarily representative of the results that will be realized when these contracts are physically delivered.  Most contracts in the retail marketing portfolio are accounted for at delivery, and changes in fair value are not expected to impact earnings.  

NU Enterprises - Generation Portfolio:  When conducting sensitivity analyses of the change in the fair value of merchant energy's generation portfolio, which would result from a hypothetical change in the future market price of electricity, the fair values of the contracts are determined from models that take into consideration estimated future market prices of electricity, the volatility of the market prices in each period, as well as the time value factors of the underlying commitments.  The merchant energy generation portfolio is comprised of primarily third party derivative generation related sales contracts (third party generation contracts) and physical generation from NGC and HWP (physical generation).  In most instances, market prices and volatility are determined from quoted prices.  Models are used for periods beyond 2009.  

A hypothetical change in the fair value for third party generation contracts was determined assuming a 10 percent change in forward market prices.  At December 31, 2005, a 10 percent increase in market price would have resulted in a pre-tax decrease in fair value of $13.9 million ($8.3 million after-tax) and a 10 percent decrease would have resulted in a pre-tax increase in fair value of $13.9 million ($8.3 million after-tax).  These transactions are accounted for at fair value, and changes in market prices impact earnings.  

A hypothetical change in the fair value for the physical generation was determined assuming a 10 percent change in forward market prices.  At December 31, 2005, a 10 percent increase in market price would have resulted in a pre-tax increase in fair value of $166.4 million ($99.8 million after-tax) and a 10 percent decrease would have resulted in a pre-tax decrease in fair value of $166.4 million ($99.8 million after-tax).  Physical generation is accounted for at delivery, and changes in fair value are not expected to impact earnings.

The impact of a change in electricity prices on merchant energy's generation portfolio at December 31, 2005, is not necessarily representative of the results that will be realized when these contracts are physically delivered or electricity is generated.  

NU Enterprises - Wholesale Portfolio:  When conducting sensitivity analyses of the change in the fair value of Select Energy's wholesale portfolio, which would result from a hypothetical change in the future market price of electricity, the fair values of the contracts are determined from models that take into consideration estimated future market prices of electricity, the volatility of the market prices in each period, as well as the time value factors of the underlying commitments.

A hypothetical change in the fair value of the wholesale portfolio was determined assuming a 10 percent change in forward market prices . At December 31, 2005, Select Energy has calculated the market price resulting from a 10 percent change in forward market prices of those contracts.  A 10 percent increase would have resulted as a pre-tax decrease in fair value of $21.3 million ($12.8 million after-tax) and a 10 percent decrease would have resulted in a pre-tax increase in fair value of $20.2 million ($12.1 million after-tax).

The impact of a change in electricity and natural gas prices on Select Energy's wholesale transactions at December 31, 2005 are not necessarily representative of the results that will be realized when these contracts are physically delivered.  These transactions are accounted for at fair value, and changes in market prices impact earnings.

Other Risk Management Activities

Interest Rate Risk Management:  NU manages its interest rate risk exposure in accordance with its written policies and procedures by maintaining a mix of fixed and variable rate debt.  At December 31, 2005, approximately 87 percent (79 percent including the debt subject to the fixed-to-floating interest rate swap in variable rate debt) of NU's long-term debt, including fees and interest due for spent nuclear fuel disposal costs, is at a fixed interest rate.  The remaining long-term debt is variable-rate and is subject to interest rate risk that could result in earnings volatility.  Assuming a one percentage point increase in NU's variable interest rates, including the rate on debt subject to the fixed-to-floating interest rate swap, annual interest expense would have increased by $4 million.  At December 31, 2005, NU parent maintained a fixed-to-floating interest rate swap to manage the interest rate risk associated with its $263 million of fixed-rate debt.

Credit Risk Management:  Credit risk relates to the risk of loss that NU would incur as a result of non-performance by counterparties pursuant to the terms of its contractual obligations.  NU serves a wide variety of customers and suppliers that include IPPs, industrial companies, gas and electric utilities, oil and gas producers, financial institutions, and other energy marketers.  Margin accounts exist within this diverse group, and NU realizes interest receipts and payments related to balances outstanding in these margin accounts.  This wide customer and supplier mix generates a need for a variety of contractual structures, products and terms which, in turn, requires NU to manage the portfolio of market risk inherent in those transactions in a manner consistent with the parameters established by NU's risk management process.

Credit risks and market risks at NU Enterprises are monitored regularly by a Risk Oversight Council operating outside of the business lines that create or actively manage these risk exposures to ensure compliance with NU's stated risk management policies.  

NU tracks and re-balances the risk in its portfolio in accordance with fair value and other risk management methodologies that utilize forward price curves in the energy markets to estimate the size and probability of future potential exposure.

NYMEX traded futures and option contracts cleared off the NYMEX exchange are ultimately guaranteed by NYMEX to Select Energy.  Select Energy has established written credit policies with regard to its counterparties to minimize overall credit risk on all types of transactions.  These policies require an evaluation of potential counterparties’ financial condition (including credit ratings), collateral requirements under certain circumstances (including cash in advance, LOCs, and parent guarantees), and the use of standardized agreements, which allow for the netting of positive and negative exposures associated with a single counterparty.  This evaluation results in establishing credit limits prior to Select Energy entering into energy contracts.  The appropriateness of these limits is subject to continuing review.  Concentrations among these counterparties may impact Select Energy's overall exposure to credit risk, either positively or negat ively, in that the counterparties may be similarly affected by changes to economic, regulatory or other conditions.

At December 31, 2005 and December 31, 2004, Select Energy maintained collateral balances from counterparties of $28.9 million and $57.7 million, respectively.  These amounts are included in counterparty deposits on the accompanying consolidated balance sheets.  Select Energy also has collateral balances deposited with counterparties of $103.8 million and $46.3 million at December 31, 2005 and December 31, 2004, respectively.

The Utility Group has a lower level of credit risk related to providing regulated electric and gas distribution service than NU Enterprises.  However, the Utility Group companies are subject to credit risk from certain long-term or high-volume supply contracts with energy marketing companies.  The Utility Group manages the credit risk with these counterparties in accordance with established credit risk practices and maintains an oversight group that monitors contracting risks, including credit risk.

NU has formed a Risk and Capital Committee comprised of senior NU officers, which reports to the Chief Executive Officer, to review the risks of large capital projects.  NU has also enlisted external engineering firms as agents on large projects providing engineering, procurement and construction management services and is conducting competitive bids on large components of all major projects.

Additional quantitative and qualitative disclosures about market risk are set forth in "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations."

Item 8.

Financial Statements and Supplementary Data

NU.  Reference is made to information under the headings "Report of Independent Registered Public Accounting Firm," "Consolidated Balance Sheets," "Consolidated Statements of (Loss)/Income," "Consolidated Statements of Comprehensive (Loss)/Income," "Consolidated Statements of Shareholders' Equity," "Consolidated Statements of Cash Flows," "Consolidated Statements of Capitalization," "Notes to Consolidated Financial Statements," and "Consolidated Statements of Quarterly Financial Data" contained within NU's 2005 Annual Report to Shareholders, which information is incorporated herein by reference.

CL&P.  Reference is made to information under the headings "Report of Independent Registered Public Accounting Firm," "Consolidated Balance Sheets," "Consolidated Statements of Income," "Consolidated Statements of Comprehensive Income," "Consolidated Statements of Common Stockholder's Equity," "Consolidated Statements of Cash Flows," "Notes to Consolidated Financial Statements," and "Consolidated Quarterly Financial Data" contained within CL&P's 2005 Annual Report, which information is incorporated herein by reference.

PSNH.  Reference is made to information under the headings "Report of Independent Registered Public Accounting Firm," "Consolidated Balance Sheets," "Consolidated Statements of Income," "Consolidated Statements of Comprehensive Income," "Consolidated Statements of Common Stockholder's Equity," "Consolidated Statements of Cash Flows," "Notes to Consolidated Financial Statements," and "Consolidated Quarterly Financial Data" contained within PSNH's 2005 Annual Report, which information is incorporated herein by reference.

WMECO.  Reference is made to information under the headings "Report of Independent Registered Public Accounting Firm," "Consolidated Balance Sheets," "Consolidated Statements of Income," "Consolidated Statements of Comprehensive Income," "Consolidated Statements of Common Stockholder's Equity," "Consolidated Statements of Cash Flows," "Notes to Consolidated Financial Statements," and "Consolidated Quarterly Financial Data" contained within WMECO's 2005 Annual Report, which information is incorporated herein by reference.  

Item 9.

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

No events that would be described in response to this item have occurred with respect to NU, CL&P, PSNH or WMECO.

Item 9A.

Controls and Procedures

Management is responsible for the preparation, integrity, and fair presentation of the accompanying consolidated financial statements of Northeast Utilities and subsidiaries (NU) and of other sections of NU's 2005 annual report.  These financial statements, which were audited by Deloitte & Touche LLP, have been prepared in conformity with accounting principles generally accepted in the United States of America using estimates and judgments, where required, and giving consideration to materiality.

Additionally, management is responsible for establishing and maintaining adequate internal controls over financial reporting.  Under the supervision and with the participation of management, including our principal executive officer and principal financial officer, NU conducted an evaluation of the effectiveness of internal controls over financial reporting based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  Based on this evaluation under the framework in COSO, management concluded that our internal controls over financial reporting were effective as of December 31, 2005.

Deloitte & Touche LLP has issued an attestation report on management's assessment of internal controls over financial reporting.

NU, CL&P, PSNH and WMECO undertook separate evaluations of 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 made timely and in accordance with the Exchange Act and the rules and forms of the SEC.  This evaluation was made under the supervision and with the participation of management, including the companies' principal executive officers and principal financial officer, as of the end of the period covered by this Annual Report on Form 10-K.  The principal executive officers and principal financial officer have concluded, based on their review, that the companies' disclosure controls and procedures are effective to ensure that information required to be disclosed by the companies in reports that it files under the Exchange Act i) is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms and i i) is accumulated and communicated to management including the principal executive officers and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

There have been no significant changes in internal controls over financial reporting during the quarter ended December 31, 2005 that have materially affected, or are reasonably likely to materially affect internal controls over financial reporting.

Item 9B.

Other Information

No information is required to be disclosed under this item at December 31, 2005, as this information has been previously disclosed in applicable reports on Form 8-K during the fourth quarter of 2005.

Part III

Item 10.

Directors and Executive Officers of the Registrants

The information in Item 10 is provided as of March 10, 2006 except where otherwise indicated.

NU

In addition to the information provided below concerning the executive officers of NU, incorporated herein by reference is the information contained in the sections "Proxy Statement - Election of Trustees," "Board Committees and Responsibilities," "Selection of Trustees," and "Section 16(a) Beneficial Ownership Reporting Compliance," of the definitive proxy statement for solicitation of proxies by NU's Board of Trustees, to be dated March 24, 2006, which will be filed with the Commission pursuant to Rule 14a-6 under the Securities Exchange Act of 1934.

         Name          

Positions  Held 

Gregory B. Butler

SVP,  GC

Lawrence E. De Simone

P

Cheryl W. Grisé (1)

EVP

David R. McHale  (2)

SVP, CFO

Leon J. Olivier (3)

EVP

Charles W. Shivery

CHB, P, CEO, T

John P. Stack

VP, C

CL&P

         Name          

Positions  Held 

Gregory B. Butler (4)

SVP, GC

Cheryl W. Grisé (1)

CEO, D

David R. McHale (2)

SVP, CFO

Raymond P. Necci (5)

P, COO, D

Leon J. Olivier (3)

OTH, D

Charles W. Shivery

OTH

John P. Stack

VP, C

PSNH

         Name          

Positions  Held 

Gregory B. Butler (4)

SVP, GC

Cheryl W. Grisé (1)

CEO, D

Gary A. Long

P, COO, D

David R. McHale (2)

SVP, CFO, D

Leon J. Olivier (3)

OTH, D

Charles W. Shivery

OTH

John P. Stack

VP, C

WMECO

        Name          

Positions  Held 

Gregory B. Butler (4)

SVP, GC

Cheryl W. Grisé (1)

CEO, D

David R. McHale (2)

SVP, CFO, D

Leon J. Olivier (3)

OTH, D

Rodney O. Powell

P, COO, D

Charles W. Shivery

OTH

John P. Stack

VP, C

(1)

Served as President - Utility Group of NU until December 1, 2005, when she was elected Executive Vice President of NU.

(2)

Became an executive officer upon election as Senior Vice President and Chief Financial Officer effective January 1, 2005.

(3)

Served as President-Transmission Group of NU effective January 17, 2005 until December 1, 2005 when he was elected Executive Vice President of NU.  Elected Director of WMECO & PSNH on January 17, 2005.  

(4)

Elected Senior Vice President and General Counsel of CL&P, WMECO and PSNH, effective March 9, 2006.

(5)

Became an executive officer of CL&P upon election as President and Chief Operating Officer, effective January 17, 2005.  Also elected a Director of CL&P, effective January 17, 2005.

Key:
C	-	Controller
CEO	-	Chief Executive Officer
CFO	-	Chief Financial Officer
CHB	-	Chairman of the Board
COO	-	Chief Operating Officer
D	-	Director
EVP	-	Executive Vice President
GC	-	General Counsel
OTH	-	Executive Officer of Registrant because of policy-making function for NU System
P	-	President
SVP	-	Senior Vice President
T	-	Trustee
VP	-	Vice President

          Name          

Age

Business Experience During Past Five Years

Gregory B. Butler

48

Senior Vice President and General Counsel of NU since December 1, 2005 and of CL&P, PSNH and WMECO since March 9, 2006, and a Director of Northeast Utilities Foundation, Inc. since December 1, 2002; previously Senior Vice President, Secretary and General Counsel of NU from August 31, 2003 to December 1, 2005; Vice President, Secretary and General Counsel of NU from May 1, 2001 through August 30, 2003; Vice President - Governmental Affairs of NUSCO from January 1997 to May 2001.

Lawrence E. De Simone

58

President-Competitive Group of NU and President of NU Enterprises, Inc., since October 25, 2004, and Chairman, President and Chief Executive Officer of Select Energy, Inc, since February 1, 2005; previously Executive Vice President - Regulated Business and Services of PPL Corporation from January 1, 2004 to August 31, 2004; Executive Vice President - Supply of PPL Corporation from October 2001 to December 31, 2003; and President of PPL EnergyPlus from November 1, 1998 to September 30, 2001.

Cheryl W. Grisé (*)

53

Executive Vice President of NU since December 1, 2005,  Chief Executive Officer of CL&P, PSNH and WMECO since September 10, 2002, a Director of CL&P since May 1, 2001, of PSNH since May 14, 2001 and of WMECO since June 2001, and a Director of Northeast Utilities Foundation, Inc. since September 23, 1998; previously President - Utility Group of NU from May 2001 to December 1, 2005; 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.

Gary A. Long (**)

54

President and Chief Operating Officer and a Director of PSNH since July 1, 2000; previously Senior Vice President of PSNH from February 2000 through June 2000 and Vice President - Customer Service and Economic Development of PSNH from January 1994 to February 2000.

David R. McHale

45

Senior Vice President and Chief Financial Officer of NU, CL&P, WMECO and PSNH since January 1, 2005 and a Director of WMECO and PSNH since January 1, 2005; previously Vice President and Treasurer of NU, WMECO and PSNH from July 1998 to December 31, 2004.

Raymond P. Necci

54

President and Chief Operating Officer and a Director of CL&P since January 17, 2005;  previously Vice President - Utility Group Services of NUSCO from January 1, 2002 to January 16, 2005; Vice President - Nuclear Operations of Dominion Nuclear Connecticut from March 31, 2001 to December 31, 2001; and Vice President - Nuclear Technical Services of Northeast Nuclear Energy Company from December 15, 1999 to March 31, 2001.

Leon J. Olivier

57

Executive Vice President of NU since December 1, 2005, a Director of WMECO and PSNH since January 17, 2005 and a Director of CL&P since September 2001; previously, President - Transmission Group of NU from January 17, 2005 to December 1, 2005. President and Chief Operating Officer of CL&P from September 2001 to January 2005; 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.

Rodney O. Powell

53

President and Chief Operating Officer  and a Director of WMECO since January 1, 2005.  Previously Vice President - Customer Relations of CL&P from January 1, 2002 to December 31, 2004; Vice President - Central Region of CL&P from October 14, 1998 to January 1, 2002; and a Director of CL&P from June 30, 1999 to September 10, 2001.

Charles W. Shivery (***)

60

Chairman of the Board, President and Chief Executive Officer of NU since March 29, 2004; Previously, President (interim) of NU from January 1, 2004 to March 29, 2004 and a Director of Northeast Utilities Foundation since March 3, 2004; previously President - Competitive Group of NU and President and Chief Executive Officer of NU Enterprises, Inc., from June 2002 through December  2003; Co-President of Constellation Energy Group, Inc. from October 2000 to February 2002; President and Chief Executive Officer of Constellation Power Source Holdings, Inc., from 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.  

John P. Stack (****)

47

Vice President - Accounting and Controller of NU, CL&P, WMECO and PSNH since January 2002. Previously Executive Director - Corporate Accounting and Taxes from  1998 to January 2002.

 (*)

Mrs. Grisé is a Director of MetLife, Inc. and Dana Corporation.

 (**)

Mr. Long is a Director of Citizens Bank-NH.

 (***)

Mr. Shivery is a Director of Energy Insurance Mutual, the Connecticut Business & Industry Association and Connecticut Children's Hospital.

(****)

Mr. Stack is on the Board of the Connecticut Hospice and Chairman of its Audit and Finance Committee.

There are no family relationships between any director or executive officer and any other director or executive officer of NU, CL&P, PSNH or WMECO.

NU, CL&P, PSNH, WMECO

Each of the registrants has adopted a Code of Ethics for Senior Financial Officers (Chief Executive Officer, Chief Financial Officer and Controller) and a Standards of Business Conduct which is applicable to all Directors, officers, employees, contractors and agents of the Company.  The Code of Ethics and the Standards of Business Conduct have both been posted on Northeast Utilities’ web site and are available at http://www.nu.com/investors/corporate_gov/default.asp on the Internet.  Information pertaining to amendments and waivers from the Code of Ethics will be posted at this site.

Printed copies of the Code of Ethics and the Standards of Business Conduct are also available to any shareholder without charge upon written request mailed to:

Ms. Kerry J. Kuhlman

Vice President and Secretary

Northeast Utilities Service Company

P.O. Box 270

Hartford, CT  06141

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 and Change in Control Arrangements," "Compensation Committee Report on Executive Compensation" and "Share Performance Chart" of the definitive proxy statement for solicitation of proxies by NU's Board of Trustees, to be dated March 24, 2006, which will be filed with the Commission pursuant to Rule 14a-6 under the Securities Exchange Act of 1934.

CL&P, PSNH, WMECO

SUMMARY COMPENSATION TABLE

The following tables present the cash and non-cash compensation for the last three years received by the Chief Executive Officer and the next four highest paid executive officers in 2005 (collectively, the named executive officers) of each of CL&P, PSNH, and WMECO in accordance with rules of the Securities and Exchange Commission (SEC):

	Long-Term Compensation
	Annual Compensation                                                              Awards						Payouts
Name and Principal Position	Year	Salary ($)	Bonus ($)	Other Annual Compensation ($) (Note 1)	Restricted  Stock Award(s) ($) (Note 2)	Securities Underlying Options/Stock Appreciation Rights (#)	Long-Term Incentive Program Payouts ($)	All Other Compensation ($) (Note 3)
Charles W. Shivery Chairman of the Board, President and Chief Executive Officer of NU (Note 4)	2005	840,000	635,166	7,565	787,493	-	-	43,108
	2004	799,380	200,000	3,754	866,244	-	-	43,150
	2003	554,616	674,000	8,946	220,004	-	-	16,639
Cheryl W. Grisé Executive Vice President of NU and Chief Executive Officer of CL&P, PSNH and WMECO (Note 5)	2005	518,000	403,239	2,316	321,165	-	-	23,297
	2004	505,539	234,949	5,000	387,494	-	-	229,321
	2003	451,538	581,513	13,216	324,994	-	-	184,587
Leon J. Olivier Executive Vice  President of NU (Note 6)	2005	397,654	356,747	108,211	212,496	-	-	13,803
	2004	330,693	143,521	107,993	81,696	-	-	12,523
	2003	317,100	275,000	3,192	78,505	-	-	18,343
Gregory B. Butler Senior Vice President and General Counsel of NU, CL&P, PSNH and WMECO (Note 7)	2005	348,654	264,925	4,234	170,634	-	-	8,926
	2004	304,615	75,316	760	250,003	-		12,785
	2003	244,615	232,200	4,473	109,995	-	-	6,000
David R. McHale Senior Vice President and Chief Financial Officer of NU, CL&P, PSNH and WMECO (Note 8)	2005	272,116	156,614	1,500	134,065	-	-	7,826
	2004	192,385	30,974	-	70,003	-	-	7,890
	2003	184,500	118,602	-	63,900	-	-	8,133

Notes:

(1)

"Other Annual Compensation" in 2005 for Mr. Olivier includes $105,966 of supplemental pension payments under his previous employment agreement with Northeast Nuclear Energy Company, a subsidiary of NU.  "Other Annual Compensation" for all officers includes miscellaneous items such as reimbursement for financial planning fees.

(2)

Restricted shares listed in the Table are valued as of the date of grant.  The aggregate restricted share holdings by the individuals named in the table were, at December 31, 2005, 214,734 common shares, with an aggregate value of $4,228,093.  The aggregate restricted share holdings by each of the individuals named in the table and the value thereof, at December 31, 2005, were 95,776 common shares ($1,885,823) for Mr. Shivery; 62,073 common shares ($1,222,216) for Mrs. Grisé; 18,421 common shares ($362,708) for Mr. Olivier; 25,434 common shares ($500,793) for Mr. Butler; and 13,030 common shares ($256,553) for Mr. McHale.  Each of the individuals was awarded restricted share units as long term incentive compensation during 2005, which vest over three years, with 50 percent payable at vesting and 50 percent payable four years after vesting; with the exception of restricted share units awarded to Mr. Shivery which vest over three years and are payabl e at retirement.  Dividends on restricted share units are reinvested and additional shares added as a result of reinvestment are vested and paid on the same schedule. Each restricted share unit represents the right to one common share of Northeast Utilities,  In addition, Mr. Shivery was awarded 25,000 restricted shares in 2004 upon his appointment as Chairman, President and CEO; these shares vest over four years and dividends are paid out during the vesting period.  In 2003, Messrs. Shivery, Olivier, Butler and McHale and Ms. Grisé were awarded restricted shares as long term compensation which vest over four years; dividends on these restricted shares are paid out during the vesting period. Payment of 50 percent of the 2003 annual incentive payout for Mr. Shivery and Mrs. Grisé was made

in restricted share units which vest over three years and on which dividends are reinvested during the vesting period.  Payment of 50 percent of the 2001 and 2002 annual bonuses of Mrs. Grisé was made on February 25, 2002 and February 25, 2003, respectively, in the form of restricted shares vesting one-third on each of the next three anniversaries of these payments; dividends on these restricted shares granted in 2003 are paid out during the vesting period.

(3)

"All Other Compensation" for 2005 consists of employer matching contributions under the Northeast Utilities Service Company 401K Plan, generally available to all eligible employees ($6,300 for each named executive officer), matching contributions under the Deferred Compensation Plan for Executives (Mr. Shivery - $18,900, Mrs. Grisé -$9,240  and, Mr. Olivier - $5,630, and dividends on restricted stock (Mr. Shivery - $17,908, Mrs. Grisé - $7,757, Mr. Olivier - $1,874, Mr. Butler - $2,626 and Mr. McHale - $1,526).

(4)

Served as interim President of NU effective January 1, 2004 and elected Chairman of the Board, President and Chief Executive Officer on March 29, 2004.

(5)

Mrs. Grisé served as President - Utility Group of NU until December 1, 2005, when she was elected Executive Vice President of NU.

(6)

Mr. Olivier served as President of CL&P through January 17, 2005 when he was elected President - Transmission Group and then elected Executive Vice President of NU on December 1, 2005.

(7)

Mr. Butler was elected Senior Vice President and General Counsel of CL&P, PSNH and WMECO on March 9, 2006.

(8)

Mr. McHale was elected Senior Vice President and Chief Financial Officer of NU, CL&P, PSNH and WMECO on January 1, 2005.

Aggregated Options/SAR Exercises in Last Fiscal Year and FY-End Option/SAR Values
	Shares With Respect to Which Options Were Exercised  #)	Value Realized ($)	Number of Securities Underlying Unexercised  Options/SARs at Fiscal Year End (#)		Value of Unexercised In-the-Money Options/SARs at Fiscal Year End ($)
Name			Exercisable	Unexercisable	Exercisable	Unexercisable
Charles W. Shivery	-	-	29,024	-	22,929	-
Cheryl W. Grisé	-	-	171,228	-	210,069	-
Leon J. Olivier	-	-	19,900	-	10,989	-
Gregory J. Butler	-	-	29,800	-	25,925	-
David R. McHale	-	-	18,501	-	12,639	-

LONG-TERM INCENTIVE PLANS - AWARDS IN LAST FISCAL YEAR

Grants of three-year performance cash units were made during 2005 under the Northeast Utilities Incentive Plan to the Company's officers.  Payments will be made in cash following the close of the performance period.  Payments at the threshold, target, and maximum levels will be determined based on cumulative net income, average return on equity, average credit rating, and total shareholder return relative to thirteen utility companies, over the performance period. In the event of retirement before age 65, grants are prorated based on time in the performance period, their value is determined based on performance through the end of the performance period and the amounts are paid out at the end of the performance period. In the event of retirement after age 65, grants made prior to the calendar year of retirement are fully vested and grants made during the calendar year of retirement are prorated based on time in the performance period. The value of the grants i s determined based on performance through the end of the performance period and the amounts are paid at the end of the performance period.  In the event of death, disability, or a Change of Control, as defined, grants are prorated based on time in the performance period, their value is set at target and the amounts are immediately paid out.  In the event of a Termination Upon a Change of Control, as defined, grants are fully vested, their value is set at target and the amounts are immediately paid out.       

Grants in 2005 to the named executive officers were as follows:

			Estimated Future Payouts Under Non-stock Price-Based Plans
(a)	(b)	(c)	(d)	(e)	(f)
Name	Number of Shares, Units or Other Rights (#)	Performance or Other Period Until Maturation or Payout	Threshold ($)	Target ($)	Maximum ($)
Charles W. Shivery	10,500	1/1/2005-12/31/2007	525,000	1,050,000	1,575,000
Cheryl W. Grisé	4,015	1/1/2005-12/31/2007	200,750	401,500	602,250
Leon J. Olivier	2,500	1/1/2005-12/31/2007	125,000	250,000	375,000
Gregory B. Butler	2,625	1/1/2005-12/31/2007	131,250	262,500	393,750
David R. McHale	2,063	1/1/2005-12/31/2007	103,150	206,300	309,450

PENSION BENEFITS

The tables on the following pages show the estimated annual retirement benefits that would be payable to a named executive officer 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 (either at the 50 percent level or the 60 percent level) 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 each named executive officer, 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 awards under the executive incentive plans and deferred compensation (as earned) as "compensation" under the plan (See Table I below).  The target benefit under the Supplemental Plan 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).  On February 1, 2005, the Supplemental Plan was amended to change the formula for calculating the target benefit under the plan. Under the Supplemental Plan, as amended, the formula for calculating the target benefit for officers who were eligible for the target benefit before February 1, 2005, uses an amount equal to 60 percent of the officer's Final Average Compensation, as defined (See Table II below).  The formula for calculating the target benefit under the Supplemental Plan for officers who become eligible for the target benefit on or after February 1, 2005 uses an amount equal to 50 percent of the participant's Final Average Compensation (See Table III below). Each of the named executive officers is eligible for the target benefit based on 60 percent of compensation, with the exception of Mr. McHale, who became eligible for the target benefit on February 1, 2005 and thus is eligible for the target based on 50 percent of compensation, and Mr. Olivier, who is eligible solely for the make-whole benefit and is not eligible for the target benefit.  Mr. Olivier also has a special retirement pursuant to his employment arrangement (see below).

In addition, Mr. Shivery's employment agreement provides for a special retirement benefit consisting of an amount equal to the difference between the equivalent of fully-vested benefits under the Retirement Plan and the Supplemental Plan calculated by adding three additional years to his actual service and using an early commencement reduction factor of two percent per year for each year Mr. Shivery's age at commencement is under age 65, if better than the factors then in use under the Retirement Plan, and benefits otherwise payable from the Retirement Plan and the Supplemental Plan.  

The terms of Mr. Olivier's employment provide for certain supplemental pension benefits in lieu of a make-whole benefit if certain eligibility requirements are met, in order to provide a benefit similar to that provided by his previous employer. Under this arrangement, if Mr. Olivier remains in continuous employment with the Company until September 10, 2011 (or earlier with the Company's permission), he will be eligible for a special benefit, subject to reduction for termination prior to age 65, of three percent of Final Average Compensation for each of his first 15 years of service since September 10, 2001, plus one percent of Final Average Compensation for each of the second 15 years of service.  Alternatively, if he does not voluntarily terminate his employment with the Company prior to his 60th birthday, or upon earlier termination upon a Change of Control, as defined in the Special Severance Program, he may receive upon retirement a lump sum payment of $2,050 ,000 in lieu of the make-whole benefit and the benefit described in the preceding sentence.  These supplemental pension benefits will be offset by the value of any benefits he receives from the Retirement Plan. If the conditions described above are not met, then Mr. Olivier would be eligible for the make-whole benefit under the Supplemental Plan

TABLE I

ANNUAL BENEFIT FOR OFFICERS ELIGIBLE

 FOR MAKE-WHOLE BENEFIT

Final Average Compensation	Years of Credited Service
	15	20	25	30	35
$200,000	$43,078	$57,437	$71,797	$86,412	$101,028
250,000	54,328	72,437	90,547	108,912	127,278
300,000	65,578	87,437	109,297	131,412	153,528
350,000	76,828	102,437	128,047	153,912	179,778
400,000	88,078	117,437	146,797	176,412	206,028
450,000	99,328	132,437	165,547	198,912	232,278
500,000	110,578	147,437	184,297	221,412	258,528
600,000	133,078	177,437	221,797	266,412	311,028
700,000	155,578	207,437	259,297	311,412	363,528
800,000	178,078	237,437	296,797	356,412	416,028
900,000	200,578	267,437	334,297	401,412	468,528
1,000,000	223,078	297,437	371,797	446,412	521,028
1,100,000	245,578	327,437	409,297	491,412	573,528
1,200,000	268,078	357,437	446,797	536,412	626,028
1,300,000	290,578	387,437	484,297	581,412	678,528
1,400,000	313,078	417,437	521,797	626,412	731,028
1,500,000	335,578	447,437	559,297	671,412	783,528
1,600,000	358,078	477,437	596,797	716,412	836,028
1,700,000	380,578	507,437	634,297	761,412	888,528
1,800,000	403,078	537,437	671,797	806,412	941,028

TABLE II

ANNUAL BENEFIT FOR OFFICERS ELIGIBLE  FOR

 MAKE WHOLE PLUS 60 PERCENT TARGET BENEFIT

Final Average Compensation	Years of Credited Service
	15	20	25	30	35
$200,000	$72,000	$96,000	$120,000	$120,000	$120,000
250,000	90,000	120,000	150,000	150,000	150,000
300,000	108,000	144,000	180,000	180,000	180,000
350,000	126,000	168,000	210,000	210,000	210,000
400,000	144,000	192,000	240,000	240,000	240,000
450,000	162,000	216,000	270,000	270,000	270,000
500,000	180,000	240,000	300,000	300,000	300,000
600,000	216,000	288,000	360,000	360,000	360,000
700,000	252,000	336,000	420,000	420,000	420,000
800,000	288,000	384,000	480,000	480,000	480,000
900,000	324,000	432,000	540,000	540,000	540,000
1,000,000	360,000	480,000	600,000	600,000	600,000
1,100,000	396,000	528,000	660,000	660,000	660,000
1,200,000	432,000	576,000	720,000	720,000	720,000
1,300,000	468,000	624,000	780,000	780,000	780,000
1,400,000	504,000	672,000	840,000	840,000	840,000
1,500,000	540,000	720,000	900,000	900,000	900,000
1,600,000	576,000	768,000	960,000	960,000	960,000
1,700,000	612,000	816,000	1,020,000	1,020,000	1,020,000
1,800,000	648,000	864,000	1,080,000	1,080,000	1,080,000

TABLE III

ANNUAL BENEFIT FOR OFFICERS ELIGIBLE FOR

MAKE-WHOLE PLUS 50 PERCENT TARGET BENEFIT

Final Average Compensation	Years of Credited Service
	15	20	25	30	35
$200,000	$60,000	$80,000	$100,000	$100,000	$100,000
250,000	75,000	100,000	125,000	125,000	125,000
300,000	90,000	120,000	150,000	150,000	150,000
350,000	105,000	140,000	175,000	175,000	175,000
400,000	120,000	160,000	200,000	200,000	200,000
450,000	135,000	180,000	225,000	225,000	225,000
500,000	150,000	200,000	250,000	250,000	250,000
600,000	180,000	240,000	300,000	300,000	300,000
700,000	210,000	280,000	350,000	350,000	350,000
800,000	240,000	320,000	400,000	400,000	400,000
900,000	270,000	360,000	450,000	450,000	450,000
1,000,000	300,000	400,000	500,000	500,000	500,000
1,100,000	330,000	440,000	550,000	550,000	550,000
1,200,000	360,000	480,000	600,000	600,000	600,000
1,300,000	390,000	520,000	650,000	650,000	650,000
1,400,000	420,000	560,000	700,000	700,000	700,000
1,500,000	450,000	600,000	750,000	750,000	750,000
1,600,000	480,000	640,000	800,000	800,000	800,000
1,700,000	510,000	680,000	850,000	850,000	850,000
1,800,000	540,000	720,000	900,000	900,000	900,000

The make-whole and target benefits presented in the tables above are based on a straight life annuity with a 33 1/3 percent and 50 percent, respectively surviving spouse benefit beginning at age 65 and do not take into account any additional reduction for joint and survivorship annuity payments.  Final average compensation for purposes of calculating the target benefit is the highest average annual compensation of the participant during any 36 consecutive months compensation was earned.  Final average compensation for purposes of calculating the make-whole benefit is the highest average annual compensation of the participant during any 60 consecutive months compensation was earned.  Compensation for these benefits includes the annual salary and bonus shown in the Summary Compensation Table and, for the make-whole benefit for officers hired before November 1, 2001, and for the target benefit for officers who were hired before November 1, 2001 and eligible for the target benefit prior to October 2003, an amount that represents the target annual value of long-term incentive compensation for 2001.  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.

The compensation covered by the Supplemental Plan in 2005 for Mr. Shivery, Mrs. Grisé, Mr. Butler, and Mr. McHale for the target benefit was $1,475,166, $1,050,439, $613,583 and $428,730, respectively, and the compensation covered by the Supplemental Plan for Mr. Olivier for the make-whole benefit was $754,401.

As of December 31, 2005, the named executive officers participating in the Supplemental Plan had attained the following years of credited service for purposes of the Supplemental Plan: Mr. Shivery - 3, Mr. Olivier - 6, Mrs. Grisé - 25, Mr. Butler - 9, and Mr. McHale -24.

EMPLOYMENT AGREEMENTS, TERMINATION OF EMPLOYMENT AND CHANGE IN CONTROL ARRANGEMENTS

NUSCO has entered into employment agreements with Messrs. Shivery, Olivier, Butler and McHale and Mrs. Grisé. In addition, Mr. Olivier participates in the Special Severance Program for Officers of Northeast Utilities System Companies providing for benefits upon termination connected with a Change of Control, while other named executive officers have Change of Control benefits pursuant to the terms of the employment agreements..  The agreements and the Special Severance Program are also binding on Northeast Utilities and, except for Mr. Shivery's agreement, on certain majority-owned subsidiaries of Northeast Utilities.  

The agreement with Ms. Grisé was supplemented during 2001 to provide for special deferred compensation of  $500,000, which payment was vested and paid in even installments (adjusted to reflect investment performance) on June 28, 2002, 2003 and 2004.

Mr. Olivier's agreement provides for specified initial salary, restricted shares, and stock options, and retirement and other benefits.

The employment agreements, other than that with Mr. Olivier, obligate the officer to perform such duties as may be directed by the NUSCO Board of Directors or the Northeast Utilities Board of Trustees, protect the Company's confidential information, refrain, while employed by the Company and for a period of time thereafter, from competing with the Company in a specified geographic area, and provide that the officer's base salary will not be reduced below certain levels without the consent of the officer.  These agreements also provide that the officer will participate in specified benefits under the Supplemental Executive Retirement Plan or other supplemental retirement programs (see Pension Benefits, above) and/or in certain executive incentive programs at specified incentive opportunity levels, for a specified employment term and for automatic one-year extensions of the employment term unless at least six months’ notice of non-renewal (60 days’ notice in the case of Mr. Shivery and Mr. McHale) 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.  Where termination of employment occurs for "cause," the agreements for Messrs. Shivery, Butler and McHale and for Mrs. Grisé provide that the supplemental retirement benefit will not be due except for the Make-Whole Benefit.  Absent "cause," the Company may remove the officer from his or her position on sixty days’ prior written notice (except in the case of Mr. Shivery and Mr. McHale, where no notice period is required), but in the event the officer is so removed and signs a release of all claims against the Company, the officer will receive two years’ base salary and annual incentive payments at target level, specified employee welfare and pe nsion benefits, and vesting of specified long-term incentive compensation.  

These employment agreements, other than that for Mr. Olivier, contain Change of Control provisions providing benefits upon any termination of employment (for reasons other than disability, death, retirement at or after age 65 or "cause") following a Change of Control , as defined, between (a) the earlier of (i) the date shareholders approve a Change of Control transaction or (ii) a Change of Control transaction occurs and (b) the earlier of (i) the date, if any, on which the Board of Trustees abandons the transaction or (ii) the date two years following the Change of Control.  Under these provisions,  if the officer signs a release of all claims against the Company, the officer will be entitled to certain payments, including two years’ of annual base salary plus annual incentive payments at target level for each year plus an additional year's base salary plus annual incentive payment at target level, for compliance with a covenant not to compet e, along with specified employee welfare and pension benefits, and vesting of stock appreciation rights, options and restricted stock. Mr. Olivier is eligible for benefits on termination following Change of Control in accordance with the Special Severance Program, providing payment equal to two years’ annual base salary plus annual incentive payment at target level. Each  named executive officers, other than Mr. Olivier, will also receive additional benefits under the Supplemental Plan including eligibility for the Make-Whole Benefit and the Target Benefit, regardless of the executive's eligibility for early retirement under the Retirement Plan.  The named executive officers are also eligible for more favorable actuarial reductions for early commencement of retirement benefits than otherwise provided under the terms of the Retirement Plan.  A termination of employment preceding the actual date of the Change of Control may be subject to the same treatment s provided above only with specifi c approval by the Board of Trustees.

To the extent that the sum of benefits payable upon termination following Change of Control comprises an "excess parachute payment" under the Internal Revenue Code for any of the named executive officers, each of the named executive officers will also receive a gross-up payment offsetting the additional excise tax imposed as a result of the "excess parachute payment," and Federal, state and local taxes on such excise tax.   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).  

The descriptions of the various agreements set forth above are for purpose of disclosure in accordance with the proxy and other disclosure rules of the SEC and shall not be controlling on any party; the actual terms of the agreements themselves determine the rights and obligations of the parties.

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

NU

Incorporated herein by reference is the information contained in the sections "Common Stock Ownership of Certain Beneficial Owners," "Common Stock Ownership of Management," and "Securities Authorized for Issuance Under Equity Compensation Plans" of the definitive proxy statement for solicitation of proxies by NU's Board of Trustees, to be dated March 24, 2006, which will be filed with the Commission pursuant to Rule 14a-6 under the Securities Exchange Act of 1934.

CL&P, PSNH, and WMECO

NU owns 100 percent of the outstanding common stock of registrants CL&P, PSNH, and WMECO.  The following table sets forth, as of February 28, 2006, the beneficial ownership of the equity securities of NU by (i) the Chief Executive Officer of each of CL&P, PSNH and WMECO and the Executive Officers of CL&P, PSNH, and WMECO listed on the Summary Compensation Table in Item 11 and (ii) all of the current Executive Officers and directors of each of CL&P, PSNH and WMECO, as a group.  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 Class	Name		Amount of Nature of Beneficial Ownership	Percent of Class
NU Common	Charles W. Shivery	(1)	220,646	(2)
NU Common	Cheryl W. Grisé	(3)	278,717	(2)
NU Common	Leon J. Olivier	(4)	55,131	(2)
NU Common	Gregory B. Butler	(5)	78,286	(2)
NU Common	David R. McHale	(6)	49,415	(2)

Amount beneficially owned by Directors and Executive Officers as a group:

Company	Number of Persons	Amount and Nature of Beneficial Ownership	Percent of Outstanding
CL&P	7	757,341	(2)
PSNH	7	763,011	(2)
WMECO	7	743,505	(2)

Notes:

(1)

Includes 29,024 shares that could be acquired by Mr. Shivery pursuant to currently exercisable options, 1,500 shares which Mr. Shivery owns jointly with his wife with whom he shares voting and dispositive power, and 16,390 shares as to which Mr. Shivery has sole voting and no dispositive power.

(2)

As of February 28, 2006, the Directors and Executive Officers of CL&P, PSNH, or WMECO individually and as a group, owned less than one percent of the shares outstanding.

(3)

Includes 171,228 shares that could be acquired by Mrs. Grisé pursuant to currently exercisable options, 5,746 shares as to which  Mrs. Grisé has sole voting and no dispositive power, and 265 shares held by Mrs. Grisé's husband as custodian for her children, with whom she shares voting and dispositive power.

(4)

Includes 19,900 shares that could be acquired by Mr. Olivier pursuant to currently exercisable options and 1,388 shares as to which Mr. Olivier has sole voting and no dispositive power.  

(5)

Includes 29,800 shares that could be acquired by Mr. Butler pursuant to currently exercisable options, 12,680 shares held jointly by Mr. Butler with his wife, with whom he shares voting and dispositive power, and 1,945 shares as to which Mr. Butler has sole voting but no dispositive power.

(6)

Includes 18,501 shares that could have been acquired by Mr. McHale pursuant to currently exercisable options and 1,130 shares as to which Mr. McHale 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 Securities and Exchange Commission:

Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights	Weighted-average exercise Price of outstanding options, warrants and rights	Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
	(a)	(b)	(c)
Equity compensation plans approved by security holders	1,224,816	$18.319	See Note 1
Equity compensation plans not approved by security holders	0	0	None
Total	1,224,816	18.319	See Note 1

Notes to table:

1.

Under the Northeast Utilities Incentive Plan, 7,379,357 shares were available for issuance as of December 31, 2005.  In addition, an amount equal to one percent of the outstanding shares as of the end of each year becomes available for issuance under the Incentive Plan the following year.  Under the Northeast Utilities Employee Share Purchase Plan II, 6,517,239 additional shares are available for issuance.  Each such plan expires in 2008.

Item 13.

Certain Relationships and Related Transactions

Incorporated herein by reference is the information contained in the section "Certain Relationships and Related Transactions" of the definitive proxy statement for solicitation of proxies by NU's Board of Trustees, to be dated March 24, 2006, which will be filed with the Commission pursuant to Rule 14a-6 under the Securities Exchange Act of 1934.

Item 14.

Principal Accountant Fees and Services

NU

Incorporated herein by reference is the information contained in the sections "Pre-Approval of Services Provided by Principal Auditors" and "Fees Paid to Principal Auditor" of the definitive proxy statement for solicitation of proxies by NU's Board of Trustees, to be dated March 24, 2006, which will be filed with the Commission pursuant to Rule 14a-6 under the Securities Exchange Act of 1934.

CL&P, PSNH, WMECO

None of CL&P, PSNH and WMECO are subject to the audit committee requirements of the Securities and Exchange Commission, the national securities exchanges or the national securities associations.  CL&P, PSNH and WMECO obtain audit services from the independent auditor engaged by the Audit Committee of NU's Board of Trustees.  The NU Audit Committee has established policies and procedures regarding the pre-approval of services provided by the principal auditors. Those policies and procedures delegate pre-approval of services to the NU Audit Committee Chair and/or Vice Chair provided that such offices are held by NU Trustees who are "independent" within the meaning of the Sarbanes-Oxley Act of 2002 (SOX) and that all such pre-approvals are presented to the Audit Committee at the next regularly scheduled meeting of the Committee.  The following relates to fees and services for the entire Northeast Utilities System, including CL&P, PSNH, and WMECO: 

Fees Paid to Principal Auditor

The Company's principal auditor was paid fees aggregating $3,535,700 and $ 2,930,455 for the years ended December 31, 2005 and 2004, respectively, comprised of the following:

1.

Audit Fees

The aggregate fees billed to NU and its subsidiaries by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu and their respective affiliates (collectively, the "Deloitte Entities") for audit services rendered for the years ended December 31, 2005 and 2004 totaled $3,309,000 and $2,679,300, respectively. The audit fees were incurred for audits of the annual consolidated financial statements of NU and its subsidiaries, reviews of financial statements included in quarterly reports on Form 10-Q of NU and its subsidiaries, comfort letters, consents and other costs related to registration statements and financings. The fees also included audits of internal controls over financial reporting as of December 31, 2005 and 2004.  

2

Audit Related Fees

The aggregate fees billed to NU and its subsidiaries by the Deloitte Entities for audit related services rendered for the years ended December 31, 2005 and 2004 totaled $148,000 and $174,950, respectively, primarily related to the examination of management's assertions of CL&P's, PSNH's and WMECO's securitization subsidiaries and the Company's 401k Plan.

3.

Tax Fees

The aggregate fees billed to NU and its subsidiaries by the Deloitte Entities for tax services for the years ended December 31, 2005 and 2004 totaled $55,000 and $54,965, respectively. These services related solely to reviews of tax returns. There were no services related to tax advice or tax planning.

4.

All Other Fees

The aggregate fees billed to NU and its subsidiaries by the Deloitte Entities for the years ended December 31, 2005 and 2004 for services other than the services described above totaled $23,700 and $21,240, respectively, primarily related to tax return software licensing.   

The Audit Committee pre-approves all auditing services and permitted non-audit services (including the fees and terms thereof) to be performed for the Company by its independent auditors, subject to the de minimis exceptions for non-audit services described in Section 10A(i)(1)(B) of the Securities Exchange Act of 1934, which are approved by the Audit Committee prior to the completion of the audit.  The Audit Committee may form and delegate authority to subcommittees consisting of one or more members when appropriate, including the authority to grant pre-approvals of audit and permitted non-audit services, provided that decisions of such subcommittee to grant pre-approvals are presented to the full Audit Committee at its next scheduled meeting. No services were provided which were not pre-approved.

The NU Audit Committee has considered whether the provision by the Deloitte Entities of the non-audit services described above was allowed under Rule 2-01(c)(4) of Regulation S-X and was compatible with maintaining auditor independence and has concluded that the Deloitte Entities were and are independent of the Company in all respects.

Part IV

Item 15.

Exhibits and Financial Statement Schedules

(a)	1.	Financial Statements:
		The Reports of the Independent Registered Public Accounting Firm 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").
		Report of Independent Registered Public Accounting Firm	S-1
	2.	Schedules:
		Financial Statement Schedules for NU (Parent), NU and Subsidiaries, CL&P and Subsidiaries, PSNH and Subsidiaries, and WMECO and Subsidiary are listed in the Index to Financial Statements Schedules	S-2
	3.	Exhibits Index	E-1

NORTHEAST UTILITIES

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

NORTHEAST UTILITIES

(Registrant)

Date:  March 7, 2006	By	/s/ Charles W. Shivery
		Charles W. Shivery
		Chairman of the Board,
		President and Chief Executive Officer
		(Principal Executive Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

Date	Title	Signature
March 7, 2006	Chairman of the Board, President and Chief Executive Officer, and a Trustee	/s/ Charles W. Shivery
		Charles W. Shivery
	(Principal Executive Officer)
March 7, 2006	Senior Vice President and Chief Financial Officer (Principal Financial Officer)	/s/ David R. McHale
		David R. McHale
March 7, 2006	Vice President - Accounting and Controller	/s/ John P. Stack
		John P. Stack
March 7 , 2006	Trustee	/s/ Richard H. Booth
		Richard H. Booth
March 7, 2006	Trustee	/s/ Cotton M. Cleveland
		Cotton M. Cleveland
March 7, 2006	Trustee	/s/ Sanford Cloud, Jr.
		Sanford Cloud, Jr.
March 7, 2006	Trustee	/s/ James F. Cordes
		James F. Cordes
March 7, 2006	Trustee	/s/ E. Gail de Planque
		E. Gail de Planque
March 7, 2006	Trustee	/s/ John G. Graham
		John G. Graham
March 7, 2006	Trustee	/s/ Elizabeth T. Kennan
		Elizabeth T. Kennan
March 7, 2006	Trustee	/s/ Robert E. Patricelli
		Robert E. Patricelli
March 7, 2006	Trustee	/s/ John F. Swope
		John F. Swope

THE CONNECTICUT LIGHT AND POWER COMPANY

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

THE CONNECTICUT LIGHT AND POWER COMPANY

(Registrant)

Date:  March 7, 2006	By	/s/ Cheryl W. Grisé
		Cheryl W. Grisé
		Chief Executive Officer
		(Principal Executive Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

Date	Title	Signature
March 7, 2006	Chief Executive Officer and a Director (Principal Executive Officer)	/s/ Cheryl W. Grisé
		Cheryl W. Grisé
March 7, 2006	President and Chief Operating Officer and a Director	/s/ Raymond P. Necci
		Raymond P. Necci
March 7, 2006	Senior Vice President and Chief Financial Officer (Principal Financial Officer)	/s/ David R. McHale
		David R. McHale
March 7, 2006	Vice President - Accounting and Controller	/s/ John P. Stack
		John P. Stack
March 7, 2006	Director	/s/ Leon J. Olivier
		Leon J. Olivier

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE

(Registrant)

Date:  March 7, 2006	By	/s/ Cheryl W. Grisé
		Cheryl W. Grisé
		Chief Executive Officer
		(Principal Executive Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

Date	Title	Signature
March 7, 2006	Chief Executive Officer and a Director (Principal Executive Officer)	/s/ Cheryl W. Grisé
		Cheryl W. Grisé
March 7, 2006	President and Chief Operating Officer and a Director	/s/ Gary A. Long
		Gary A. Long
March 7, 2006	Senior Vice President and Chief Financial Officer and a Director	/s/ David R. McHale
		David R. McHale
	(Principal Financial Officer)
March 7, 2006	Vice President - Accounting and Controller	/s/ John P. Stack
		John P. Stack
March 7, 2006	Director	/s/ Leon J. Olivier
		Leon J. Olivier

WESTERN MASSACHUSETTS ELECTRIC COMPANY

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

WESTERN MASSACHUSETTS ELECTRIC COMPANY

(Registrant)

Date:  March 7, 2006	By	/s/ Cheryl W. Grisé
		Cheryl W. Grisé
		Chief Executive Officer
		(Principal Executive Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

Date	Title	Signature
March 7, 2006	Chief Executive Officer and a Director (Principal Executive Officer)	/s/ Cheryl W. Grisé
		Cheryl W. Grisé
March 7, 2006	President and Chief Operating Officer and a Director	/s/ Rodney O. Powell
		Rodney O. Powell
March 7, 2006	Senior Vice President and Chief Financial Officer and a Director	/s/ David R. McHale
		David R. McHale
	(Principal Financial Officer)
March 7, 2006	Vice President - Accounting and Controller	/s/ John P. Stack
		John P. Stack
March 7, 2006	Director	/s/ Leon J. Olivier
		Leon J. Olivier

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Trustees and Shareholders of Northeast Utilities and the Boards of Directors of The Connecticut Light and Power Company, Public Service Company of New Hampshire and Western Massachusetts Electric Company:

We have audited the consolidated financial statements of Northeast Utilities and subsidiaries (the "Company"), The Connecticut Light and Power Company ("CL&P"), Public Service Company of New Hampshire ("PSNH") and Western Massachusetts Electric Company ("WMECO") (collectively "the Companies") as of December 31, 2005 and 2004, and for each of the three years in the period ended December 31, 2005, management's assessment of the effectiveness of the Company's internal control over financial reporting as of December 31, 2005, and the effectiveness of the Company's internal control over financial reporting as of December 31, 2005, and have issued our reports thereon dated March 7, 2006; such consolidated financial statements and reports are included in Northeast Utilities’ 2005 Annual Report to Shareholders and CL&P's, PSNH's and WMECO's 2005 Annual Reports, all of which are incorporated herein by reference.  Our report on t he consolidated financial statements of Northeast Utilities expresses an unqualified opinion and includes an explanatory paragraph regarding the Company's recording of significant charges in connection with its decision to exit certain business lines and the reporting of certain components of the Company's energy services businesses as discontinued operations.  Our audits also included the consolidated financial statement schedules of the Company, CL&P, PSNH and WMECO, listed in Item 15.  These consolidated financial statement schedules are the responsibility of the Company's management.  Our responsibility is to express an opinion based on our audits.  In our opinion, such consolidated financial statement schedules, when considered in relation to the basic consolidated 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

March 7, 2006

INDEX TO FINANCIAL STATEMENTS SCHEDULES

Schedule

I.	Financial Information of Registrant: Northeast Utilities (Parent) Balance Sheets at December 31, 2005 and 2004	S-3
	Northeast Utilities (Parent) Statements of (Loss)/Income for the Years Ended December 31, 2005, 2004, and 2003	S-4
	Northeast Utilities (Parent) Statements of Cash Flows for the Years Ended December 31, 2005, 2004, and 2003	S-5
II.	Valuation and Qualifying Accounts and Reserves for 2005, 2004, and 2003:
	Northeast Utilities and Subsidiaries	S-6 - S-8
	The Connecticut Light and Power Company	S-9 - S-11
	Public Service Company of New Hampshire	S-12 - S-14
	Western Massachusetts Electric Company	S-15 - S-17

All other schedules of the companies' for which provision is made in the applicable regulations of the SEC are not required under the related instructions or are not applicable, and therefore have been omitted.

SCHEDULE I
NORTHEAST UTILITIES (PARENT)
FINANCIAL INFORMATION OF REGISTRANT
BALANCE SHEETS
AT DECEMBER 31, 2005 AND 2004
(Thousands of Dollars)
	2005	2004
ASSETS
Current Assets:
Cash	$                 390	$                 244
Notes receivable from affiliated companies	352,700	210,600
Notes and accounts receivable	879	1,129
Accounts receivable from affiliated companies	7,642	126
Taxes receivable	-	6,291
Derivative assets – current	-	91
Prepayments	136	115
	361,747	218,596
Deferred Debits and Other Assets:
Investments in subsidiary companies, at equity	2,531,536	2,637,567
Accumulated deferred income taxes	9,965	-
Other	11,604	12,997
	2,553,105	2,650,564
Total Assets	$       2,914,852	$       2,869,160
LIABILITIES AND CAPITALIZATION
Current Liabilities:
Notes payable to banks	$            32,000	$          100,000
Long-term debt - current portion	21,000	26,000
Accounts payable	511	7
Accounts payable to affiliated companies	261	1,015
Accrued taxes	12,103	-
Accrued interest	5,357	5,790
Other	473	327
	71,705	133,139
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	-	3,525
Derivative liabilities - long-term	5,211	-
Other	1,072	1,933
	6,283	5,458
Capitalization:
Long-Term Debt	407,620	433,852
Common shares, $5 par value - authorized
225,000,000 shares; 174,897,704 shares issued and
153,225,892 shares outstanding in 2005 and
151,230,981 shares issued and
129,034,442 outstanding in 2004	874,489	756,155
Capital surplus, paid in	1,437,561	1,116,106
Deferred contribution plan - employee
stock ownership plan	(46,884)	(60,547)
Retained earnings	504,301	845,343
Accumulated other comprehensive income/(loss)	19,987	(1,220)
Treasury stock, 19,645,511 shares in 2005
and 19,580,065 outstanding in 2004	(360,210)	(359,126)
Common Shareholders' Equity	2,429,244	2,296,711
Total Capitalization	2,836,864	2,730,563
Total Liabilities and Capitalization	$       2,914,852	$       2,869,160

SCHEDULE I
NORTHEAST UTILITIES (PARENT)
FINANCIAL INFORMATION OF REGISTRANT
STATEMENTS OF (LOSS)/INCOME
YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003
(Thousands of Dollars, Except Share Information)
	2005	2004	2003
Operating Revenues	$                             -	$                              -	$                           -
Operating Expenses:
Other	8,314	8,417	7,720
Operating Loss	(8,314)	(8,417)	(7,720)
Interest Expense	33,068	24,868	22,186
Other (Loss)/Income, Net:
Equity in (losses)/earnings of subsidiaries	(240,179)	131,127	123,647
Other, net	17,577	13,538	11,041
Other (Loss)/Income, Net	(222,602)	144,665	134,688
(Loss)/Income Before Income Tax Benefit	(263,984)	111,380	104,782
Income Tax Benefit	(10,496)	(5,208)	(11,629)
(Loss)/Earnings for Common Shares	$                (253,488)	$                 116,588	$                116,411
Basic and Fully Diluted Earnings Per Common Share	$                      (1.93)	$                        0.91	$                      0.91
Basic Common Shares Outstanding (weighted average)	131,638,953	128,245,860	127,114,743
Fully Diluted Common Shares Outstanding (weighted average)	131,638,953	128,396,076	127,240,724

NORTHEAST UTILITIES (PARENT)
FINANCIAL INFORMATION OF REGISTRANT
STATEMENTS OF CASH FLOWS
AT DECEMBER 31, 2005, 2004 AND 2003
(Thousands of Dollars)
	2005	2004	2003
Operating Activities:
Net (loss)/income	$        (253,488)	$         116,588	$         116,411
Adjustments to reconcile to net cash flows
used in operating activities:
Equity in losses/(earnings) of subsidiaries	240,179	(131,127)	(123,647)
Deferred income taxes	(13,563)	(811)	(411)
Other non-cash adjustments	9,857	14,850	11,147
Other sources of cash	2,900	1,011	1,234
Other uses of cash	(405)	-	(3,702)
Changes in current assets and liabilities:
Receivables, net	(5,436)	3,834	(1,918)
Other current assets	(20)	(3,779)	(2,554)
Accounts payable	(250)	(837)	(716)
Accrued taxes	18,394	-	(2,460)
Other current liabilities	(287)	(277)	148
Net cash flows used in operating activities	(2,119)	(548)	(6,468)
Investing Activities:
Investment in subsidiaries	(255,650)	(72,126)	(199,575)
Cash dividends received from subsidiary companies	142,709	85,846	114,921
NU Money Pool lending	(142,100)	-	-
Other investing activities	2,572	(1,136)	1,897
Net cash flows (used in)/provided by investing activities	(252,469)	12,584	(82,757)
Financing Activities:
Issuance of common shares	450,827	10,937	13,654
Repurchase of common shares	-	-	(20,537)
(Decrease)/increase in short-term debt	(68,000)	35,000	16,000
Issuance of long-term debt	-	-	150,000
Reacquisitions and retirements of long-term debt	(26,000)	(24,000)	(23,000)
NU Money Pool borrowing	-	49,000	29,500
Cash dividends on common shares	(87,554)	(80,177)	(73,090)
Other financing activities	(14,539)	(2,552)	(3,927)
Net cash flows provided by/(used in) financing activities	254,734	(11,792)	88,600
Net increase/(decrease) in cash	146	244	(625)
Cash - beginning of year	244	-	625
Cash - end of year	$                390	$                244	$                     -
Supplemental Cash Flow Information:
Cash paid/(received) during the year for:
Interest, net of amounts capitalized	$           32,765	$            24,447	$            21,496
Income taxes	$           39,101	$                 535	$          (16,818)

Schedule II

Northeast Utilities and Subsidiaries

Valuation and Qualifying Accounts and Reserves

Year Ended December 31, 2005

(Thousands of Dollars)

Column A	Column B		Column C						Column D			Column E
			Additions
			(1)		(2)
Description	Balance at beginning of period		Charged to costs and expenses		Charged to other accounts - describe			Deductions- describe					Balance at end of period
Reserves deducted from assets to which they apply:
Reserves for uncollectible accounts (a)	$	25,325	$	27,528	$	975	(b)	$		28,784	(c)			$	25,044
Reserves not applied against assets:
Operating reserves	$	71,763	$	22,359	$	-		$		26,044	(d)			$	68,078

(a)

Amounts include activity related to accounts that are classified as assets held for sale and discontinued operations.

(b)

Amount relates to uncollectible amounts reserved for that relate to receivables other than those of customers.

(c)

Amounts written off, net of recoveries.  

(d)

Principally payments for environmental remediation, various injuries and damages, employee medical expenses, and expenses in connection therewith.  This amount also includes a reduction to environmental reserves related to land that was sold in 2005.  

Schedule II

Northeast Utilities and Subsidiaries

Valuation and Qualifying Accounts and Reserves

Year Ended December 31, 2004

(Thousands of Dollars)

Column A	Column B		Column C					Column D			Column E
			Additions
			(1)		(2)
Description	Balance at beginning of period		Charged to costs and expenses		Charged to other accounts - describe		Deductions- describe				Balance at end of period
Reserves deducted from assets to which they apply:
Reserves for uncollectible accounts	$	40,846	$	19,062	$	-	$		34,583	(a)	$	25,325
Reserves not applied against assets:
Operating reserves	$	68,658	$	22,574	$	-	$		19,466	(b)	$	71,766

(a)

Amounts written off, net of recoveries.  

(b)

Principally payments for environmental remediation, various injuries and damages, employee medical expenses, inventory reserves and expenses in connection therewith.

Schedule II

Northeast Utilities and Subsidiaries

Valuation and Qualifying Accounts and Reserves

Year Ended December 31, 2003

(Thousands of Dollars)

Column A	Column B		Column C					Column D			Column E
			Additions
			(1)		(2)
Description	Balance at beginning of period		Charged to costs and expenses		Charged to other accounts - describe			Deductions- describe			Balance at end of period
Reserves deducted from assets to which they apply:
Reserves for uncollectible accounts	$	15,425	$	23,229	$	17,205	(a)	$	15,013	(b)	$	40,846
Reserves not applied against assets:
Operating reserves	$	67,127	$	17,688	$	-		$	16,157	(c)	$	68,658

(a)

Amount relates to regulatory assets recorded in conjunction with the bankruptcy of NRG and certain of its subsidiaries and to uncollectible amounts reserved for related capital projects and New Hampshire's low-income assistance program.  

(b)

Amounts written off, net of recoveries.

(c)

Principally payments for environmental remediation, various injuries and damages, employee medical expenses, inventory reserves and expenses in connection therewith.

Schedule II

The Connecticut Light and Power Company and Subsidiaries

Valuation and Qualifying Accounts and Reserves

Year Ended December 31, 2005

(Thousands of Dollars)

Column A	Column B		Column C						Column D			Column E
			Additions
			(1)		(2)
Description	Balance at beginning of period		Charged to costs and expenses		Charged to other accounts - describe			Deductions- describe				Balance at end of period
Reserves deducted from assets to which they apply:
Reserves for uncollectible accounts	$	2,010	$	12,834	$	605	(a)	$		13,467	(b)	$	1,982
Reserves not applied against assets:
Operating reserves	$	27,404	$	8,385	$	-		$		10,634	(c)	$	25,155

(a)     Amount relates to uncollectible amounts reserved for that relate to receivables other than those of customers.

(b)     Amounts written off, net of recoveries.

(c)

Principally payments for environmental remediation, various injuries and damages, employee medical expenses, and expenses in connection therewith.  This amount also includes a reduction to environmental reserves related to land that was sold in 2005.  

Schedule II

The Connecticut Light and Power Company and Subsidiaries

Valuation and Qualifying Accounts and Reserves

Year Ended December 31, 2004

(Thousands of Dollars)

Column A	Column B		Column C					Column D			Column E
			Additions
			(1)		(2)
Description	Balance at beginning of period		Charged to costs and expenses		Charged to other accounts - describe		Deductions- describe				Balance at end of period
Reserves deducted from assets to which they apply:
Reserves for uncollectible accounts	$	21,790	$	1,440	$	-	$		21,220	(a)	$	2,010
Reserves not applied against assets:
Operating reserves	$	21,364	$	10,201	$	-	$		4,160	(b)	$	27,405

(a)

Amounts written off, net of recoveries and other adjustments.

(b)

Principally payments for environmental remediation, various injuries and damages, employee medical expenses, inventory reserves and expenses in connection therewith.

Schedule II

The Connecticut Light and Power Company and Subsidiaries

Valuation and Qualifying Accounts and Reserves

Year Ended December 31, 2003

(Thousands of Dollars)

Column A	Column B		Column C					Column D			Column E
			Additions
			(1)		(2)
Description	Balance at beginning of period		Charged to costs and expenses		Charged to other accounts - describe			Deductions- describe			Balance at end of  period
Reserves deducted from assets to which they apply:
Reserves for uncollectible accounts	$	525	$	5,164	$	16,924	(a)	$	823	(b)	$	21,790
Reserves not applied against assets:
Operating reserves	$	18,241	$	9,712	$	-		$	6,589	(c)	$	21,364

(a)

Amount relates to regulatory assets recorded in conjunction with the bankruptcy of NRG and certain of its subsidiaries and to uncollectible amounts reserved for related to capital projects.  

(b)

Amounts written off, net of recoveries.

(c)

Principally payments for environmental remediation, various injuries and damages, employee medical expenses, inventory reserves and expenses in connection therewith.

Schedule II

Public Service Company of New Hampshire and Subsidiaries

Valuation and Qualifying Accounts and Reserves

Year Ended December 31, 2005

(Thousands of Dollars)

Column A	Column B		Column C						Column D			Column E
			Additions
			(1)		(2)
Description	Balance at beginning of period		Charged to costs and expenses		Charged to other accounts - describe			Deductions- describe				Balance at end of period
Reserves deducted from assets to which they apply:
Reserves for uncollectible accounts	$	1,764	$	3,904	$	252	(a)	$		3,558	(b)	$	2,362
Reserves not applied against assets:
Operating reserves	$	11,461	$	1,890	$	-		$		2,574	(c)	$	10,777

(a)

Amount relates to uncollectible amounts reserved for that relate to receivables other than those of customers.  

(b)     Amounts written off, net of recoveries.   

(c)

Principally payments for environmental remediation, various injuries and damages, employee medical expenses, inventory reserves and expenses in connection therewith.

Schedule II

Public Service Company of New Hampshire and Subsidiaries

Valuation and Qualifying Accounts and Reserves

Year Ended December 31, 2004

(Thousands of Dollars)

Column A	Column B		Column C						Column D			Column E
			Additions
			(1)		(2)
Description	Balance at beginning of period		Charged to costs and expenses		Charged to other accounts - describe			Deductions- describe				Balance at end of period
Reserves deducted from assets to which they apply:
Reserves for uncollectible accounts	$	1,590	$	2,742	$	110	(a)	$		2,678	(b)	$	1,764
Reserves not applied against assets:
Operating reserves	$	13,568	$	5,066	$	-		$		7,173	(c)	$	11,461

(a)

Amount relates to uncollectible amounts reserved for that relate to receivables other than those of customers and New Hampshire's low-income assistance program.  

(b)

Amounts written off, net of recoveries.

(c)

Principally payments for environmental remediation, various injuries and damages, employee medical expenses, inventory reserves and expenses in connection therewith.

Schedule II

Public Service Company of New Hampshire and Subsidiaries

Valuation and Qualifying Accounts and Reserves

Year Ended December 31, 2003

(Thousands of Dollars)

Column A	Column B		Column C						Column D			Column E
			Additions
			(1)		(2)
Description	Balance at beginning of period		Charged to costs and expenses		Charged to other accounts - describe			Deductions- describe				Balance at end of period
Reserves deducted from assets to which they apply:
Reserves for uncollectible accounts	$	1,990	$	1,379	$	102	(a)	$		1,881	(b)	$	1,590
Reserves not applied against assets:
Operating reserves	$	14,089	$	2,585	$	-		$		3,106	(c)	$	13,568

(a)

Amount relates to uncollectible amounts reserved for that relate to receivables other than those of customers and New Hampshire's low-income assistance program.  

(b)

Amounts written off, net of recoveries.

(c)

Principally payments for environmental remediation, various injuries and damages, employee medical expenses, and expenses in connection therewith.

Schedule II

Western Massachusetts Electric Company and Subsidiary

Valuation and Qualifying Accounts and Reserves

Year Ended December 31, 2005

(Thousands of Dollars)

Column A	Column B		Column C						Column D			Column E
			Additions
			(1)		(2)
Description	Balance at beginning of period		Charged to costs and expenses		Charged to other accounts - describe			Deductions- describe				Balance at end of period
Reserves deducted from assets to which they apply:
Reserves for uncollectible accounts	$	2,563	$	3,857	$	37	(a)	$		2,804	(b)	$	3,653
Reserves not applied against assets:
Operating reserves	$	2,355	$	836	$	-		$		892	(c)	$	2,299

(a)

Amount relates to uncollectible amounts reserved for that relate to receivables other than those of customers.  

(b)     

Amounts written off, net of recoveries.

(c)

Principally payments for environmental remediation, various injuries and damages, employee medical expenses, inventory reserves and expenses in connection therewith.

Schedule II

Western Massachusetts Electric Company and Subsidiary

Valuation and Qualifying Accounts and Reserves

Year Ended December 31, 2004

(Thousands of Dollars)

Column A	Column B		Column C					Column D			Column E
			Additions
			(1)		(2)
Description	Balance at beginning of period		Charged to costs and expenses		Charged to other accounts - describe		Deductions- describe				Balance at end of period
Reserves deducted from assets to which they apply:
Reserves for uncollectible accounts	$	2,551	$	4,246	$	-	$		4,234	(a)	$	2,563
Reserves not applied against assets:
Operating reserves	$	2,971	$	1,126	$	-	$		1,742	(b)	$	2,355

(a)

Amounts written off, net of recoveries.

(b)

Principally payments for environmental remediation, various injuries and damages, employee medical expenses, inventory reserves and expenses in connection therewith.

Schedule II

Western Massachusetts Electric Company and Subsidiary

Valuation and Qualifying Accounts and Reserves

Year Ended December 31, 2003

(Thousands of Dollars)

Column A	Column B		Column C					Column D			Column E
			Additions
			(1)		(2)
Description	Balance at beginning of period		Charged to costs and expenses		Charged to other accounts - describe			Deductions- describe			Balance at end of period
Reserves deducted from assets to which they apply:
Reserves for uncollectible accounts	$	1,958	$	4,107	$	179	(a)	$	3,693	(b)	$	2,551
Reserves not applied against assets:
Operating reserves	$	2,855	$	1,501	$	-		$	1,385	(c)	$	2,971

(a)

Amount relates to uncollectible amounts reserved for that relate to receivables other than those of customers.  

(b)

Amounts written off, net of receivables.

(c)

Principally payments for environmental remediation, various injuries and damages, employee medical expenses, and expenses in connection therewith.

EXHIBIT INDEX

Each document described below is incorporated by reference to the files identified, unless designated with a (*), which exhibits are filed herewith.

Exhibit

Number  

Description

2

Plan of acquisition, reorganization, arrangement, liquidation or succession

(A)

NU

2.1

Amended and Restated Agreement and Plan of Merger (Exhibit 1 to NU Form 8-K dated December 2, 1999, File No. 1-5324).

3

Articles of Incorporation and By-Laws

(A)

Northeast Utilities

3.1

Declaration of Trust of NU, as amended through May 10, 2005 (Exhibit A.1, NU Form U-1 dated June 23, 2005, File No. 70-10315).

(B)

The Connecticut Light and Power Company

3.1

Certificate of Incorporation of CL&P, restated to March 22, 1994.  (Exhibit 3.2.1, 1993 NU Form 10-K, File No. 1-5324)

3.1.2

Certificate of Amendment to Certificate of Incorporation of CL&P, dated December 26, 1996. (Exhibit 3.2.2, 1996 NU Form 10-K, File No. 1-5324)

3.1.3

Certificate of Amendment to Certificate of Incorporation of CL&P, dated April 27, 1998. (Exhibit 3.2.3, 1998 NU Form 10-K, File No. 1-5324)

3.2

By-laws of CL&P, as amended to January 1, 1997. (Exhibit 3.2.3, 1996 NU Form 10-K, File No. 1-5324)

(C)

Public Service Company of New Hampshire

3.1

Articles of Incorporation, as amended to May 16, 1991.  (Exhibit 3.3.1, 1993 NU Form 10-K, File No. 1-5324)

3.2

By-laws of PSNH, as amended to November 1, 1993.  (Exhibit 3.3.2, 1993 NU Form 10-K, File No. 1-5324)

(D)

Western Massachusetts Electric Company

3.1

Articles of Organization of WMECO, restated to February 23, 1995.  (Exhibit 3.4.1, 1994 NU Form 10-K, File No. 1-5324)

3.2

By-laws of WMECO, as amended to April 1, 1999. (Exhibit 3.1,  NU Form 10-Q for the Quarter Ended June 30, 1999, File No. 1-5324)

3.1.2

By-laws of WMECO, as further amended to May 1, 2000.  (Exhibit 3.1,  NU Form 10-Q for the Quarter Ended June 30, 2000, File No. 1-5324)

4

Instruments defining the rights of security holders, including indentures

(A)

Northeast Utilities

4.1

Indenture dated as of December 1, 1991 between Northeast Utilities and IBJ Schroder Bank & Trust Company, with respect to the issuance of Debt Securities.  (Exhibit 4.1.1, 1991 NU Form 10-K, File No. 1-5324)

4.1.1

First Supplemental Indenture dated as of December 1, 1991 between Northeast Utilities and IBJ Schroder Bank & Trust Company, with respect to the issuance of Series A Notes.  (Exhibit 4.1.2, 1991 NU Form 10-K, File No. 1-5324)

4.1.2

Second Supplemental Indenture dated as of March 1, 1992 between Northeast Utilities and IBJ Schroder Bank & Trust Company with respect to the issuance of 8.38% Amortizing   Notes.  (Exhibit 4.1.3, 1992 NU Form 10-K, File No. 1-5324)

4.2

Rights Agreement dated as of February 23, 1999, between Northeast Utilities and Northeast Utilities Service Company, as Rights Agent.  (Exhibit 1 to NU's Registration Statement on Form 8-A, filed on April 12, 1999, File No. 001-05324).

4.2.1

Amendment to Rights Agreement. (Exhibit 3 to NU Form 8-K dated October 13, 1999, File No. 1-5324).

4.2.2

Second Amendment to Rights Agreement.  (Exhibit B-3 to NU 35-CERT, dated February 1, 2002, File No. 070-09463).

4.3

Indenture dated as of April 1, 2002, between NU and the Bank of New York as Trustee. (Exhibit A-3 to NU 35-CERT filed April 9, 2002, File No. 70-9535)

4.3.1

First Supplemental Indenture dated as of April 1, 2002, between NU and the Bank of New York as Trustee, relating to $263M of Senior Notes, Series A, due 2012.  (Exhibit A-4 to NU 35-CERT filed April 9, 2002, File No. 70-9535)  

4.3.2

Second Supplemental Indenture dated as of June 1, 2003, between NU and the Bank of New York as Trustee, relating to $150M of Senior Notes, Series B, due 2008.  (Exhibit A-1.3 to NU 35-CERT filed June 6, 2003, File No. 70-10051)

4.4

Credit Agreement dated as of November 2, 2005 among Northeast Utilities, the Banks Named Therein, the Lenders party thereto and Barclays Bank PLC as Administrative Agent and Fronting Bank (Exhibit B-1 to NU 35-CERT filed November 10, 2005, File No. 70-10315)

4.5

Amended and Restated Credit Agreement dated December 9, 2005 between NU, the Banks Named Therein, Union Bank of California, N.A. as Administrative Agent, and Barclays Bank, PLC, JPMorgan Chase Bank, N.A. and Union Bank of California, N.A., as Fronting Banks (Exhibit 99.1, NU Form 8-K dated December 9, 2005, File No. 1-5324)

(B)

The Connecticut Light and Power Company

4.1

Indenture of Mortgage and Deed of Trust between CL&P and Bankers Trust Company, Trustee, dated as of May 1, 1921.  (Composite including all twenty-four amendments to May 1, 1967.)  (Exhibit 4.1.1, 1989 NU Form 10-K, File No. 1-5324)

4.1.1

Supplemental Indenture to the Composite May 1, 1921 Indenture of Mortgage and Deed of Trust between CL&P and Bankers Trust Company, dated as of June 1, 1994.  (Exhibit 4.2.15, 1994 NU Form 10-K, File No. 1-5324)

4.1.2

Supplemental Indentures to the Composite May 1, 1921 Indenture of Mortgage and Deed of Trust between CL&P and Bankers Trust Company, dated as of October 1, 1994.  (Exhibit 4.2.16, 1994 NU Form 10-K, File No. 1-5324)

4.1.3

Series A Supplemental Indenture between CL&P and Deutsche Bank Trust Company Americas, as Trustee, dated as of September 1, 2004 (Exhibit 99.2 to CL&P Form 8-K filed September 22, 2004).

4.1.4

Form of Composite Indenture of Mortgage, as proposed to be amended and restated (included as Schedule C to the Series A Supplemental Indenture) dated as of May 1, 1921, as amended and supplemented (Exhibit 99.4 to CL&P Form 8-K filed September 22, 2004).  

4.1.5

Series B Supplemental Indenture between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of September 1, 2004 (Exhibit 99.5 to CL&P Form 8-K filed September 22, 2004).

4.1.6

Supplemental Indenture (2005 Series A Bonds and 2005 Series B Bonds)  between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of April 1, 2005 (Exhibit 99.2 to CL&P Form 8-K filed April 13, 2005, File No. 0-00404)

4.1.7

Supplemental Indenture (2005 Series A Bonds and 2005 Series B Bonds)  between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of April 1, 2005 ("Supplemental Indenture") (Exhibit 99.2 to CL&P Form 8-K filed April 13, 2005, File No. 0-00404)

4.2

Financing Agreement between Industrial Development Authority of the State of New Hampshire and CL&P (Pollution Control Bonds, 1986 Series) dated as of December 1, 1986.  (Exhibit C.1.47, 1986 NU Form U5S, File No. 30-246)

4.3

Financing Agreement between Industrial Development Authority of the State of New Hampshire and CL&P (Pollution Control Bonds, 1988 Series) dated as of October 1, 1988.  (Exhibit C.1.55, 1988 NU Form U5S, File No. 30-246)

4.4

Loan and Trust Agreement among Business Finance Authority of the State of New Hampshire, CL&P and the Trustee (Pollution Control Bonds, 1992 Series A) dated as of December 1, 1992.  (Exhibit C.2.33, 1992 NU Form U5S, File No. 30-246)

4.5

Loan Agreement between Connecticut Development Authority and CL&P (Pollution Control Bonds - Series A, Tax Exempt Refunding) dated as of September 1, 1993.  (Exhibit 4.2.21, 1993 NU Form 10-K, File No. 1-5324)

4.6

Loan Agreement between Connecticut Development Authority and CL&P (Pollution Control Bonds - Series B, Tax Exempt Refunding) dated as of September 1, 1993.  (Exhibit 4.2.22, 1993 NU Form 10-K, File No. 1-5324)

4.7

Amended and Restated Loan Agreement between Connecticut Development Authority and CL&P (Pollution Control Revenue Bond - 1996A Series) dated as of May 1, 1996 and Amended and Restated as of January 1, 1997.  (Exhibit 4.2.24, 1996 NU Form 10-K, File No. 1-5324)

4.8

Amended and Restated Indenture of Trust between Connecticut Development Authority and the Trustee (CL&P Pollution Control Revenue Bond-1996A Series), dated as of May 1, 1996 and Amended and Restated as of January 1, 1997.  (Exhibit 4.2.24.1, 1996 NU Form 10-K, File No. 1-5324)

4.9

Standby Bond Purchase Agreement among CL&P, Bank of New York as Purchasing Agent and the Banks Named therein, dated October 24, 2000.  (Exhibit 4.2.24.2 of 2000 NU Form 10-K, File No. 1-5324)

4.9.1

Amendment No. 2 to the Standby Bond Purchase Agreement dated as of September 9, 2002, among CL&P, The Bank of New York, and the Participating Banks referred to therein.  (Exhibit 4.2.7.4,  NU Form 10-Q for the Quarter Ended September 30, 2002, File No. 1-5324)

4.10

AMBAC Municipal Bond Insurance Policy issued by the Connecticut Development Authority (CL&P Pollution Control Revenue Bond-1996A Series), effective January 23, 1997.(Exhibit 4.2.24.3, 1996 NU Form 10-K, File No. 1-5324)

4.11

Compensation and Multiannual Mode Agreement among the Connecticut Development Authority and BNY Capital Markets, Inc. dated September 23, 2003 (Exhibit 4.2.7.5, NU Form 10-Q for the Quarter Ended September 30, 2003, File No. 1-5324)

4.12

Amended and Restated Receivables Purchase and Sale Agreement dated as of March 30, 2001).  (Exhibit 4.2.8, 2002 NU Form 10-K, File No. 1-5324)

4.12.1

Amendment No. 2 to the Purchase and Sale Agreement dated as of July 10, 2002 (Exhibit 4.2.24.2, 2002 NU Form 10-K, File No. 1-5324)

4.12.2

Amendment No. 3 to the Amended and Restated Receivables Purchase and Sales Agreement dated as of July 9, 2003 (Exhibit 4.2.8.2, NU Form 10-Q for the Quarter Ended September 30, 2003, File No. 1-5324)

4.12.3

Amendment No. 4 to the Amended and Restated Receivables Purchase and Sales Agreement dated as of July 7, 2004 (Exhibit 4.12.3 to NU Form 10-Q for the Quarter Ended June 30, 2005, File No. 1-5324)

4.12.4

Amendment No. 5 to the Amended and Restated Receivables Purchase and Sales Agreement dated as of July 7, 2005 (Exhibit 4.12.4 to NU Form 10-Q for the Quarter Ended June 30, 2005, File No. 1-5324)

4.13

Purchase and Contribution Agreement dated as of September 30, 1997 (Exhibit 10.49.1, 1997 NU Form 10-K, File No. 1-5324)

4.13.1

Amendment No. 2 to the Purchase and Contribution Agreement dated as of March 30, 2001 (Exhibit 4.2.9 of 2002 NU Form 10-K, File No. 1-5324)

4.14

Amended and Restated Credit Agreement dated December 9, 2005 between CL&P, WMECO, Yankee Gas and PSNH, the Banks Named Therein, and Citicorp USA, Inc., as Administrative Agent (Exhibit 99.2, CL&P Form 8-K dated December 9, 2005, File No. 0-00404)

(C)

Public Service Company of New Hampshire

4.1

First Mortgage Indenture dated as of August 15, 1978 between PSNH and First Fidelity Bank, National Association, New Jersey, now First Union National Bank, Trustee, (Composite including all amendments to May 16, 1991).  (Exhibit 4.4.1, 1992 NU Form 10-K, File No. 1-5324)

4.1.1

Tenth Supplemental Indenture dated as of May 1, 1991 between PSNH and First Fidelity Bank, National Association, now First Union National Bank.  (Exhibit 4.1, PSNH Form 8-K dated February 10, 1992, File No. 1-6392)

4.1.2

Twelfth Supplemental Indenture dated as of December 1, 2001 between PSNH and First Union National Bank.  (Exhibit 4.3.1.2, 2001 NU Form 10-K, File No. 1-5324)

4.1.3

Thirteenth Supplemental Indenture, dated as of July 1, 2004, between PSNH and Wachovia Bank, National Association, successor to First Union National Bank, as successor to First Fidelity Bank, National Association, as Trustee (Exhibit 99.2 to PSNH Form 8-K filed October 5, 2004, File No. 1-6392)

4.1.4

Fourteenth Supplemental Indenture, dated as of October 1, 2005, between PSNH and Wachovia Bank, National Association successor to First Union National Bank, as successor to First Fidelity Bank, National Association, as Trustee (Exhibit 99.2 to PSNH Form 8-K filed October 6, 2005, File No. 1-6392)

4.2

Series D (Tax Exempt Refunding) Amended and Restated PCRB Loan and Trust Agreement dated as of April 1, 1999.  (Exhibit 4.3.6, 1999 NU Form 10-K, File No. 1-5324)

4.3

Series E (Tax Exempt Refunding) Amended & Restated PCRB Loan and Trust Agreement dated as of April 1, 1999.  (Exhibit 4.3.7, 1999 NU Form 10-K, File No. 1-5324)

4.4

Series A Loan and Trust Agreement among Business Finance Authority of the State of New Hampshire and PSNH and State Street Bank and Trust Company, as Trustee (Tax Exempt Pollution Control Bonds) dated as of October 1, 2001.  (Exhibit 4.3.4, 2001 NU Form 10-K, File No. 1-5324)

4.5

Series B Loan and Trust Agreement among Business Finance Authority of the State of New Hampshire and PSNH and State Street Bank and Trust Company, as Trustee (Tax Exempt Pollution Control Bonds) dated as of October 1, 2001.  (Exhibit 4.3.5, 2001 NU Form 10-K, File No. 1-5324)

4.6

Series C Loan and Trust Agreement among Business Finance Authority of the State of New Hampshire and PSNH and State Street Bank and Trust Company, as Trustee (Tax Exempt Pollution Control Bonds) dated as of October 1, 2001. (Exhibit 4.3.6, 2001 NU Form 10-K, File No. 1-5324)

4.7

Amended and Restated Credit Agreement dated December 9, 2005 between CL&P, WMECO, Yankee Gas and PSNH, the Banks Named Therein, and Citicorp USA, Inc., as Administrative Agent (Exhibit 99.2, PSNH Form 8-K dated December 9, 2005, File No. 1-6392)

(D)

Western Massachusetts Electric Company

4.1

Loan Agreement between Connecticut Development Authority and WMECO, (Pollution Control Bonds - Series A, Tax Exempt Refunding) dated as of September 1, 1993.  (Exhibit 4.4.13, 1993 NU Form 10-K, File No. 1-5324)

4.2

Indenture between WMECO and the Bank of New York, as Trustee, dated as of September 1, 2003 (Exhibit 99.2, WMECO Form 8-K filed October 8, 2003, File No. 0-7624)

4.2.1

First Supplemental Indenture between WMECO and the Bank of New York, as Trustee, dated as of September 1, 2003 (Exhibit 99.3, WMECO Form 8-K filed October 8, 2003, File No. 0-7624)

4.2.2

Second Supplemental Indenture dated as of September 1, 2004, between WMECO and Morgan Stanley & Co. (Exhibit 4.1 to WMECO Form 8-K filed September 27, 2004)

4.2.3

Third Supplemental Indenture between WMECO and The Bank of New York Trust, as Trustee, dated as of August 1, 2005 (Exhibit 4.1, WMECO Form 8-K filed August 12, 2005, File No. 0-7624)

4.3

Amended and Restated Credit Agreement dated December 9, 2005 between CL&P, WMECO, Yankee Gas and PSNH, the Banks Named Therein, and Citicorp USA, Inc., as Administrative Agent (Exhibit 99.2, WMECO Form 8-K dated December 9, 2005, File No. 1-6392)

10

Material Contracts

(A)

NU

10.1

Lease dated as of April 14, 1992 between The Rocky River Realty Company  and Northeast Utilities Service Company with respect to the Berlin, Connecticut headquarters.  (Exhibit 10.29, 1992 NU Form 10-K, File No. 1-5324)

10.2

Loan Agreement dated as of December 2, 1991, by and between NU and Mellon Bank, N.A., as Trustee, with respect to NU's loan of $175 million to an ESOP Trust. (Exhibit 10.46, 1991 NU Form 10-K, File No. 1-5324)

10.2.1

First Amendment to Loan Agreement dated February 7, 1992. (Exhibit 10.36.1, 1993 NU Form 10-K, File No. 1-5324)

10.2.2

Second Amendment to Loan Agreement dated April 9, 1992. (Exhibit 10.36.3, 1993 NU Form 10-K, File No. 1-5324)

10.3

Loan Agreement dated as of March 19, 1992 by and between NU and Mellon Bank, N.A., as Trustee, with respect to NU's loan of $75 million to the ESOP Trust.  (Exhibit 10.49.1, 1992 NU Form 10-K, File No. 1-5324)

10.4

Indenture Mortgage, dated as of October 18, 2001 between NGC and The Bank of New York, as Trustee.  (Exhibit 4.1 to NGC Registration Statement on Form S-4 dated December 6, 2001, File No. 333-74636)

10.4.1

First Supplemental Indenture Mortgage, dated as of October 18, 2001 between NGC and The Bank of New York, as Trustee. (Exhibit 4.2 to NGC Registration Statement on Form S-4 dated December 6, 2001, File No. 333-74636)

10.5

Indenture of Mortgage and Deed of Trust dated July 1, 1989 between Yankee Gas Services Company and the Connecticut National Bank, as Trustee (Exhibit 4.7, Yankee Energy System, Inc. ("YES") Form 10-K for the fiscal year ended September 30, 1990, File No. 0-10721)

10.5.1

First Supplemental Indenture of Mortgage and of Trust dated April 1, 1992 between Yankee Gas Services Company and The Connecticut National Bank, as Trustee (YES Registration Statement on Form S-3, dated October 2, 1992 Form 1992 File No. 33-52750)

10.5.2

Second Supplemental Indenture of Mortgage and Deed of Trust dated December 1, 1992 between Yankee Gas Services Company and The Connecticut National Bank, as Trustee (YES Form 10-K for the fiscal year ended September 30, 1992, File No. 0-17605)

10.5.3

Third Supplemental Indenture of Mortgage and Deed of Trust dated June 1, 1995 between Yankee Gas Services Company and Shawmut Bank Connecticut, N.A. (formerly The Connecticut National Bank), as Trustee. (Exhibit 4.14 YES Form 10-K for the fiscal year ended September 30, 1995, File No. 0-10721)

10.5.4

Fourth Supplemental Indenture of Mortgage and Deed of Trust dated April 1, 1997 between Yankee Gas Services Company and Fleet National Bank (formerly The Connecticut National Bank), as Trustee. (Exhibit 4.15 YES Form 10-K for the fiscal year ended September 30, 1997, File No. 0-10721)

10.5.5

Fifth Supplemental Indenture of Mortgage and Deed of Trust dated January 1, 1999 between Yankee Gas Services Company and The Bank of New York, as Successor Trustee to Fleet Bank (formerly The Connecticut National Bank) (Exhibit 4.2 YES Form 10-Q for the fiscal quarter ended March 31, 1999, File No. 0-10721)

10.5.6

Sixth Supplemental Indenture and Deed of Trust dated January 1, 2004 between Yankee Gas Services Company and The Bank of New York, as Successor Trustee to Fleet Bank (formerly The Connecticut National Bank) (Exhibit 10.5.6, 2004 NU Form 10-K, File No. 1-5324)

10.5.7

Seventh Supplemental Indenture and Deed of Trust dated November 1, 2004 between Yankee Gas Services Company and The Bank of New York, as Successor Trustee to Fleet Bank (formerly The Connecticut National Bank) (Exhibit 10.5.7, 2004 NU Form 10-K, File No. 1-5324)

10.5.8.

Eighth Supplemental Indenture and Deed of Trust dated July 1, 2005 between Yankee Gas Services Company and The Bank of New York, as Successor Trustee to Fleet Bank (formerly the Connecticut National Bank) (Exhibit 10.5.8 to NU Form 10-Q for the Quarter Ended June 30, 2005, File No. 1-5324)

(B)

NU, CL&P, PSNH and WMECO

10.1

Service Contract dated as of July 1, 1966 between each of NU, CL&P and WMECO and Northeast Utilities Service Company (NUSCO).  (Exhibit 10.20, 1993 NU Form 10-K, File No. 1-5324)

10.2

Form of Annual Renewal of Service Contract.  (Exhibit 10.20.3, 1993 NU Form 10-K, File No. 1-5324)

10.3

Memorandum of Understanding between CL&P, HELCO, HP&E, HWP and WMECO dated as of June 1, 1970 with respect to pooling of generation and transmission.  (Exhibit 13.32, File No. 2-38177)

10.3.1

Amendment to Memorandum of Understanding between CL&P, HELCO, HP&E, HWP and WMECO dated as of February 2, 1982 with respect to pooling of generation and transmission.  (Exhibit 10.21.1, 1993 NU Form 10-K, File No. 1-5324)

10.3.2

Amendment to Memorandum of Understanding between CL&P, HELCO, HP&E, HWP and WMECO dated as of January 1, 1984 with respect to pooling of generation and transmission.  (Exhibit 10.21.2, 1994 NU Form 10-K, File No. 1-5324)

10.3.3

Second Amendment to Memorandum of Understanding between CL&P, HELCO, HP&E, HWP and WMECO dated as of June 8, 1999 with respect to pooling of generation and transmission.  (Exhibit 10.23.3, 1999 NU Form 10-K, File No. 1-5324)

10.4

Stockholder Agreement dated as of July 1, 1964 among the stockholders of Connecticut Yankee Atomic Power Company (CYAPC).  (Exhibit 10.1, 1994 NU Form 10-K, File No. 1-5324)

10.5

Capital Funds Agreement dated as of September 1, 1964 between CYAPC and CL&P, HELCO, PSNH and WMECO.  (Exhibit 10.3, 1994 NU Form 10-K, File No. 1-5324)

10.6

Power Purchase Contract dated as of July 1, 1964 between CYAPC and each of CL&P, HELCO, PSNH and WMECO.  (Exhibit 10.2, 1994 NU Form 10-K, File No. 1-5324)

10.7

Additional Power Purchase Contract dated as of April 30, 1984, between CYAPC and each of CL&P, PSNH and WMECO.  (Exhibit 10.2.1, 1994 NU Form 10-K, File No. 1-5324)

10.8

Supplementary Power Contract dated as of April 1, 1987, between CYAPC and each of CL&P, PSNH and WMECO.  (Exhibit 10.2.6, 1987 NU Form 10 K, File No. 1-5324)

10.9

Form of 1996 Amendatory Agreement between CYAPC and  CL&P dated December 4, 1996.  (Exhibit 10 (B) 10.9, 2003 NU Form 10-K, File No. 1-5324)

10.9.1

Form of First Supplemental to the 1996 Amendatory Agreement dated as of February 10, 1997 (Exhibit 10 (B) 10.9.1, 2003 NU Form 10-K, File No. 1-5324)

10.9.2

2000 Amendatory Agreement dated as of July 28, 2000 (Exhibit 10.9.2, 2004 NU Form 10-K, File No. 1-5324)

10.9.3

Amended and Restated Additional Power Contract, dated as of April 30, 1984 and restated as of July 1, 2004 ) (Exhibit 10.9.3, 2004 NU Form 10-K, File No. 1-5324)

10.10

Stockholder Agreement dated December 10, 1958 between Yankee Atomic Electric Company (YAEC) and CL&P, HELCO, PSNH and WMECO.  (Exhibit 10.4, 1993 NU Form 10-K, File No. 1-5324)

10.11

Amended and Restated Power Purchase Contract dated as of April 1, 1985, between YAEC and each of CL&P, PSNH and WMECO.  (Exhibit 10.5, 1988 NU Form 10-K, File No. 1-5324)

10.11.1

Amendment No. 4 to Power Contract, dated May 6, 1988, between YAEC and each of CL&P, PSNH and WMECO.  (Exhibit 10.5.1, 1989 NU Form 10-K, File No. 1-5324)

10.11.2

Amendment No. 5 to Power Contract, dated June 26, 1989, between YAEC and each of CL&P, PSNH and WMECO.  (Exhibit 10.5.2, 1989 NU Form 10-K, File No. 1-5324)

10.11.3

Amendment No. 6 to Power Contract, dated July 1, 1989, between YAEC and each of CL&P, PSNH and WMECO.  (Exhibit 10.5.3, 1989 NU Form 10-K, File No. 1-5324)

10.11.4

Amendment No. 7 to Power Contract, dated February 1, 1992, between YAEC and each of CL&P, PSNH and WMECO.  (Exhibit 10.5.4, 1993 NU Form 10-K, File No. 1-5324)

10.11.5

Form of Amendment No. 8 to Power Contract, dated June 1, 2003, between YAEC and each of CL&P, PSNH and WMECO (Exhibit 10  (B) 10.11.5, 2003 NU Form 10-K, File No. 1-5324)

*10.11.6

Form of Amendment No. 9  to Power Contract, dated November 17, 2005, between YAEC and each of CL&P, PSNH and WMECO

10.12

Stockholder Agreement dated as of May 20, 1968 among stockholders of MYAPC.  (Exhibit 10.6, 1997 NU Form 10-K, File No. 1-5324)

10.13

Capital Funds Agreement dated as of May 20, 1968 between MYAPC and CL&P, PSNH, HELCO and WMECO.  (Exhibit 10.8, 1997 NU Form 10-K, File No. 1-5324)

10.13.1

Amendment No. 1 to Capital Funds Agreement, dated as of August 1, 1985, between MYAPC, CL&P, PSNH and WMECO.  (Exhibit No. 10.8.1, 1994 NU Form 10-K, File No. 1-5324)

10.14

Power Purchase Contract dated as of May 20, 1968 between MYAPC and each of CL&P, HELCO, PSNH and WMECO.  (Exhibit 10.7, 1997 Form 10-K, File No. 1-5324)

10.14.1

Amendment No. 1 to Power Contract dated as of March 1, 1983 between MYAPC and each of CL&P, PSNH and WMECO.  (Exhibit 10.7.1, 1993 NU Form 10-K, File No. 1-5324)

10.14.2

Amendment No. 2 to Power Contract dated as of January 1, 1984 between MYAPC and each of CL&P, PSNH and WMECO.  (Exhibit 10.7.2, 1993 NU Form 10-K, File No. 1-5324)

10.14.3

Amendment No. 3 to Power Contract dated as of October 1, 1984 between MYAPC and each of CL&P, PSNH and WMECO.  (Exhibit No. 10.7.3, 1994 NU Form 10-K, File No. 1-5324)

10.14.4

Additional Power Contract dated as of February 1, 1984 between MYAPC and each of CL&P, PSNH and WMECO.  (Exhibit 10.7.4, 1993 NU Form 10-K, File No. 1-5324)

*10.14.5

1997 Amendatory Agreement dated as of August 6, 1997 between MYAPC and each of CL&P, PSNH and WMECO

10.15

Sharing Agreement between CL&P, WMECO, HP&E, HWP and PSNH dated as of June 1, 1992.  (Exhibit 10.17, 1992 NU Form 10-K, File No. 1-5324)

10.16

Agreements among New England Utilities with respect to the Hydro-Quebec interconnection projects.  (Exhibits 10(u) and 10(v); 10(w), 10(x), and 10(y), 1990 and 1988, respectively, Form 10-K of New England Electric System, File No. 1-3446.)

10.17

NU Incentive Plan, effective as of January 1, 1998. (Exhibit 10.35.1, 1998 NU Form 10-K, File No. 1-5324)

10.17.1

Amendment to NU Incentive Plan, effective as of February 23, 1999.  (Exhibit 10.35.1.1, 1998 NU Form 10-K, File No. 1-5324)

10.18

Supplemental Executive Retirement Plan for Officers of NU System Companies, Amended and Restated effective as of January 1, 1992.  (Exhibit 10.45.1, NU Form 10-Q for the Quarter Ended June 30, 1992, File No. 1-5324)

10.18.1

Amendment 1 to Supplemental Executive Retirement Plan, effective as of August 1, 1993.(Exhibit 10.35.1, 1993 NU Form 10-K, File No. 1-5324)

10.18.2

Amendment 2 to Supplemental Executive Retirement Plan, effective as of January 1, 1994.(Exhibit 10.35.2, 1993 NU Form 10-K, File No. 1-5324)

10.18.3

Amendment 3 to Supplemental Executive Retirement Plan, effective as of January 1, 1996.(Exhibit 10.36.3, 1995 NU Form 10-K, File No. 1-5324)

10.18.4

Amendment 4 to Supplemental Executive Retirement Plan, effective as of February 26, 2002.  (Exhibit 10.35.4, 2001 NU Form 10-K, File No. 1-5324)

10.18.5

Amendment 5 to Supplemental Executive Retirement Plan, effective as of November 1, 2001.  (Exhibit 10.35.5, 2001 NU Form 10-K, File No. 1-5324)

10.18.6

Amendment 6 to Supplemental Executive Retirement Plan, effective as of December 9, 2003 (Exhibit 10 (B) 10.18.6, 2003 NU Form 10-K, File No. 1-5324).

10.18.7

Amendment 7 to Supplemental Executive Retirement Plan, effective as of  February 1, 2005 (Exhibit 10.18.7, 2004 NU Form 10-K, File No. 1-5324)

10.19

Trust under Supplemental Executive Retirement Plan dated May 2, 1994. (Exhibit 10.33, 2002 NU Form 10-K, File No. 1-5324)

10.19.1

First Amendment to Trust, effective as of December 10, 2002 (Exhibit 10 (B) 10.19.1, 2003 NU Form 10-K, File No. 1-5324)

10.20

Special Severance Program for Officers of NU System Companies, as adopted on July 15, 1998.  (Exhibit 10.37, 1998 NU Form 10-K, File No. 1-5324)

10.20.1

Amendment to Special Severance Program, effective as of February 23, 1999. (Exhibit 10.37.1, 1998 NU Form 10-K, File No. 1-5324)

10.20.2

Amendment to Special Severance Program, effective as of September 14, 1999.  (Exhibit 10.3, NU Form 10-Q for the Quarter Ended September 30, 1999, File No. 1-5324)

10.21

Employment Agreement with Cheryl W. Grisé, dated as of April 1, 2003  (Exhibit 10.45.6 to NU Form 10-Q for Quarter Ended March 31, 2003, File No. 1-5324)

10.22

Employment Agreement with Charles W. Shivery dated as of March 31, 2005 (Exhibit 10.24.2 to NU Form 10-Q for the Quarter Ended March 31, 2005, File No. 1-5324)

10.23

Employment Agreement with Gregory B. Butler, dated as of October 1, 2003 (Exhibit 10 (B) 10.31, 2003 NU Form 10-K, File No. 1-5324)

10.24

Northeast Utilities Deferred Compensation Plan for Trustees, amended and restated effective January 1, 2004 (Exhibit 10.32 to NU Form 10-Q for the Quarter Ended March 31, 2004, File No. 1-5324)

*10.24.1

Amendment No. 3 to Northeast Utilities Deferred Compensation Plan for Trustees, effective January 1, 2005.

10.25

Northeast Utilities Deferred Compensation Plan for Executives, amended and restated effective January 1, 2004 (Exhibit 10.33 to NU Form 10-Q for the Quarter Ended March 31, 2004, File No 1-5324)

*10.25.1

Amendment No. 1 to Northeast Utilities Deferred Compensation Plans for Executives, effective January 1, 2005.

10.26

Employment Agreement of Lawrence E. DeSimone, dated as of October 25,2004 (Exhibit 10.28, 2004 NU Form 10-K, File No. 1-5324)

10.27

Transmission Operating Agreement dated as of  February 1, 2005 between the Initial Participating Transmission Owners, Additional Participating Transmission Owners  and ISO New England, Inc. (Exhibit 10.29, 2004 NU Form 10-K, File No. 1-5324)

10.28

Employment Agreement with David R. McHale dated as of March 31, 2005 (Exhibit 10.30 to NU Form 10-Q for the Quarter Ended March 31, 2005, File No. 1-5324)

10.29

Northeast Utilities System's Second Amended and Restated Tax Allocation Agreement dated as of September 21, 2005 (Exhibit D.4 to Amendment No. 1 to U5S Annual Report for the year ended December 31, 2004, filed September 30, 2005, File No. 1-5324)

*10.30

ISO New England, Inc. FERC Electric Tariff No. 3, Section II- Open Access Transmission Tariff, Schedule 21-NU (Northeast Utilities Companies Local Service Schedule), Issued on December 22, 2004 and Effective, With Notice on or after February 1, 2005.

(C)

NU and CL&P

10.1

CL&P Transition Property Purchase and Sale Agreement between CL&P Funding LLC and CL&P, dated as of March 30, 2001.  (Exhibit 10.55, 2001 CL&P Form 10-K, File No. 0-11419)

10.2

CL&P Transition Property Servicing Agreement CL&P Funding LLC and CL&P, dated as of March 30, 2001.  (Exhibit 10.56, 2001 NU Form 10-K, File No. 1-5324)

10.3

Description of terms of employment of Leon J. Olivier (Exhibit 10 (C) 10.3, 2003 NU Form 10-K, File No. 1-5324)

(D)

NU and PSNH

10.1

Revised and Conformed Agreement to Settle PSNH Restructuring, dated August 2, 1999, conformed June 23 and executed on September 22, 2000. (Exhibit 10.15.1, 2001 NU Form 10-K, File No. 1-5324)

10.2

PSNH Purchase and Sale Agreement with PSNH Funding LLC dated as of April 25, 2001.  (Exhibit 10.57, 2001 NU Form 10-K, File No. 1-5324)

10.3

PSNH Servicing Agreement with PSNH Funding LLC dated as of April 25, 2001.  (Exhibit 10.58, 2001 NU Form 10-K, File No. 1-5324)

10.4

PSNH Purchase and Sale Agreement with PSNH Funding LLC2 dated as of January 30, 2002.  (Exhibit 10.59 2001 NU Form 10-K, File No. 1-5324)

10.5

PSNH Servicing Agreement with PSNH Funding LLC2 dated as of January 30, 2002.  (Exhibit 10.60, 2001 NU Form 10-K, File No. 1-5324)

(E)

NU and WMECO

10.1

Lease and Agreement, dated as of December 15, 1988, by and between WMECO and Bank of New England, N.A., with BNE Realty Leasing Corporation of North Carolina. (Exhibit 10.63, 1988 NU Form 10-K, File No. 1-5324.)

10.2

WMECO Transition Property Purchase and Sale Agreement between WMECO Funding LLC and WMECO, dated as of May 17, 2001.  (Exhibit 10.61, 2001 NU Form 10-K, File No. 1-5324)

10.3

WMECO Transition Property Servicing Agreement between WMECO Funding LLC and WMECO, 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

Annual Report of CL&P

13.2

Annual Report of WMECO

13.3

Annual Report of PSNH

*21

Subsidiaries of the Registrant

*23

Consent of the Independent Registered Public Accounting Firm

*31

Rule 13-a - 14(a)/15 d - 14(a)  Certifications

(a)

Northeast Utilities

Certification of Charles W. Shivery, Chairman, President and Chief Executive Officer of NU required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated March 7, 2006

(b)

The Connecticut Light and Power  Company

Certification of Cheryl W. Grisé, Chief Executive Officer of CL&P required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated  March 7, 2006

(c)

Public Service Company of New Hampshire

Certification of Cheryl W. Grisé, Chief Executive Officer of PSNH required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated March 7, 2006

(d)

Western Massachusetts Electric Company

Certification of Cheryl W. Grisé, Chief Executive Officer of WMECO required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934 , as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated  March 7, 2006

*31.1

Rule 13-a - 14(a)/15 d - 14(a) Certifications

(a)

Northeast Utilities

Certification of David R. McHale, Senior Vice President and Chief Financial Officer of NU required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated March 7, 2006

(b)

The Connecticut Light and Power Company

Certification of  David R. McHale, Senior Vice President and Chief Financial Officer of CL&P required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended,  as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated March 7, 2006

(c)

Public Service Company of New Hampshire

Certification of  David R. McHale, Senior Vice President and Chief Financial Officer of  PSNH required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended,  as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated March 7, 2006

(d)

Western Massachusetts Electric Company

Certification  of David R. McHale, Senior Vice President and Chief Financial Officer of  WMECO required by Rule 13a - 14(a)/15d - 14(a) of the Securities Exchange Act of 1934, as amended,  as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated March 7, 2006

*32

Section 1350 Certificates

(a)

Northeast Utilities

Certification of Charles W. Shivery, Chairman, President and Chief Executive Officer of Northeast Utilities, and David R. McHale, Senior 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 7, 2006

(b)

The Connecticut Light and Power Company

Certification of Cheryl W. Grisé, Chief Executive Officer of CL&P, and David R. McHale, Senior 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 7, 2006

(c)

Public Service Company of New Hampshire

Certification of Cheryl W. Grisé, Chief Executive Officer of PSNH, and David R. McHale, Senior 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 7, 2006

(d)

Western Massachusetts Electric Company

Certification of Cheryl W. Grisé, Chief Executive Officer of WMECO, and David R. McHale, Senior 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 7, 2006

 *99.1

Balance sheets of Northeast Generation Company as of December 31, 2005 and 2004 and the related statements of income, comprehensive income, common stockholders’ equity and cash flows for the years then ended.

EX-10.11.6

Exhibit 10.11.6

AMENDMENT NO. 9

TO

POWER CONTRACT

AMENDMENT NO. 9, dated as of the 17th day of November 2005, to the Power

Contract dated June 30, 1959, as heretofore amended and revised effective June 2, 1975, October 1, 1980, April 1, 1985, May 6, 1988, June 26, 1989, July 1, 1989, February 1, 1992, and June 1", 2003, between Yankee Atomic Electric Company ("Yankee"), a Massachusetts corporation, and d  ______________(“Customer”), a ______________ corporation (the “Power Contract”).

WITNESSETH

WHEREAS, pursuant to the Power Contract, Yankee supplied to the Customer and, pursuant to separate power contracts substantially identical to the Power Contract except for the names of the parties, to the other stockholders of Yankee, each of whom is contemporaneously entering into an amendment to its power contract which is identical hereto except for the necessary changes in the names of the parties, all of the capacity and electric energy available from the nuclear generating unit owned by Yankee at a site in Rowe, Massachusetts (such unit, together with the site and all related facilities owned by Yankee, being herein referred to as the "Plant"); and

WHEREAS, the parties to the Power Contract and the Federal Energy Regulatory Commission, which has regulatory jurisdiction over the Power Contract, have consistently recognized that the cost of the capacity and electric energy sold under the Power Contract necessarily included the costs of shutting down, removing from service and decommissioning the Plant after its useful life had ended and the parties have heretofore incorporated in the Power Contract provisions designed to achieve that result, whether or not the Plant produced electricity and whether or not the Plant operated for the full term of the Facility Operating License; and

WHEREAS, Section 6 of the Power Contract allows Yankee to collect its costs of

decommissioning the Plant from the Customer and the other stockholders of Yankee through accruals to a reserve fund, with accruals made over a period extending to December 31, 2010; and

WHEREAS, Section 11 of the Power Contract provides that, upon authorization by its board of directors of a uniform amendment to all customer power contracts, Yankee shall have the right to amend the provisions of Section 6 of the Power Contract by serving an appropriate statement of such amendment upon the Customer and filing the same with the Federal Energy Regulatory Commission, and that the amendment shall thereupon become effective on the date specified therein, subject to any suspension order duly issued by such agency; and

WHEREAS, the estimated costs of completing the decommissioning of the Plant have increased such that Yankee has determined that additional funding under Section 6 of the Power Contract is required to pay for projected future decommissioning costs; and

WHEREAS, the parties to the Power Contract desire to amend Section 6 of the Power Contract to allow accruals to vary from month to month as stated in a rate schedule approved by the Commission so that the costs of decommissioning the Plant can be met through the fund.

NOW, THEREFORE, in consideration of the above, the parties hereto agree that the Power Contract is hereby amended as follows:

1.     Terms used herein and not defined shall have the meanings set forth in the Power Contract.

2.     Section 6 of the Power Contract is hereby amended as follows: The sentence "The levels of such accruals may vary from year to year, but for each such year the accruals will be collected in equal monthly installments" is deleted.

3.     This Amendment shall become effective as of the date first above written, subject to any suspension order duly issued by the Federal Energy Regulatory Commission.

4.     This Amendment may be executed in any number of counterparts, all of which together shall constitute one and the same instrument.

WITNESS WHEREOF, the parties hereto have caused their respective duly authorized representative to execute this Amendment on their behalf as of the date first above written.

YANKEE ATOMIC ELECTRIC COMPANY	PURCHASER
_______________________________ Name:     Michael E. Thomas Title:      Vice President and CFO Address:  YAEC                 49 Yankee Road                  Rowe, MA 01367	____________________________ Name: Title: Address:

EX-10.14.5

Exhibit 10.14.5

MAINE YANKEE ATOMIC POWER COMPANY

1997 Amendatory Agreement

This 1997 Amendatory Agreement, dated as of August 6, 1997, is entered into by and between MAINE YANKEE ATOMIC POWER COMPANY, a Maine corporation ("Maine Yankee" or "Seller"), and ________________________________("Purchaser").

For good and valuable consideration, the receipt of which is hereby acknowledged, it is agreed as follows:

1.

Basic Understandings

Maine Yankee was organized in 1966 to provide a 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 830 megawatts electric (the "Unit") at a site on tidewater in the Town of Wiscasset, Maine. On June 27, 1973, Maine Yankee was issued a full-term, Facility Operating License for the Unit by the Atomic Energy Commission (predecessor to the Nuclear Regulatory Commission which, together with any successor agencies, is hereafter called the "NRC "), which license is now stated to expire on October 21, 2008. The Unit has been in commercial operation since January 1, 1973.

The Unit was conceived to supply economic power on a cost of service formula basis to the Purchasers. Maine Yankee and the Purchaser are parties to a Power Contract dated as Contract and other identical contracts (collectively, the "Power Contracts") between Maine Yankee and the other Purchasers, Maine Yankee contracted to supply to the Purchasers all of the capacity and electric energy available from the Unit for a term of thirty (30) years following January 1, 1973.

Maine Yankee and the Purchaser are also parties to an Additional Power Contract, dated as of February 1, 1984 ("Additional Power Contract"). The Additional Power Contract and other similar contracts (collectively, the "Additional Power Contracts") between Maine Yankee and the other Purchasers provide for an operative term stated to commence on January 2, 2003 (when the Power Contracts terminate) and extending until a date which is the later to occur of (i) 30 days after the date on which the last of the financial obligations of Maine Yankee which constitute elements of the purchase price thereunder has been extinguished by Maine Yankee or (ii) 30 days after the date on which Maine Yankee is finally relieved of any obligations under the last of the licenses (operating and/or possessory) which it holds from, or which may hereafter be issued to it by, the NRC with respect to the Unit under applicable provisions of the Atomic Energy Act of 1954, as amended from time to time (the "Act").

Pursuant to the Power Contract and the Additional Power Contract, the Purchaser is

entitled and obligated to take its entitlement percentage of the capacity and net electrical output of the Unit during the service life of the Unit and is obligated to pay therefor monthly its entitlement percentage of Maine Yankee's cost of service, including decommissioning costs, whether or not the Unit is operated or whether or not net electrical output is delivered. The Power Contracts and the Additional Power Contracts also provide, in the event of their earlier cancellation, for the survival of the decommissioning cost obligation and for the applicable provisions thereof to remain in effect to permit final billings of costs incurred prior to such cancellation.

On August 6, 1997, the board of directors of Maine Yankee, after conducting a thorough review of the economics of continued operation of the Unit for the remainder of the term of the Facility Operating License for the Unit in light of other alternatives available to Maine Yankee and the Purchasers, determined that the Unit should be permanently shut down effective August 6, 1997. The Purchaser concurs in that decision.

As a consequence of the shutdown decision, Maine Yankee and the Purchaser propose at this time to amend the Power Contract and the Additional Power Contract in various respects in order to clarify and confirm provisions for the recovery under said contracts of the full costs previously incurred by Maine Yankee in providing power from the Unit during its useful life and of all costs of decommissioning the Unit, including the costs of maintaining the Unit in a safe condition following the shutdown and prior to its decontamination and dismantlement.

Maine Yankee and each of the other Purchasers are entering into agreements which are identical to this Agreement except for necessary changes in the names of the parties.

2.

Parties' Contractual Commitments

Maine Yankee reconfirms its existing contractual obligations to protect the Unit, to maintain in effect certain insurance and to prepare for and implement the decommissioning of the Unit in accordance with applicable laws and regulations. Consistent with public safety, Maine Yankee shall use its best efforts to accomplish the shutdown of the Unit, the protection and any necessary maintenance of the Unit after shutdown and the decommissioning of the Unit in a cost-effective manner and in compliance with the regulations of the NRC and other agencies having jurisdiction, and shall use its best efforts to ensure that any required storage and disposal of the nuclear fuel remaining in the reactor at shutdown and all spent nuclear fuel or other radioactive materials resulting from operating of the Unit are accomplished consistent with public health and safety considerations and at the lowest practicable cost. The Purchaser reconfirms its obli gations under the Power Contract and Additional Power Contract to pay its entitlement percentage of Maine Yankee's costs as deferred payment in connection with the capacity and net electrical output of the Unit previously delivered by Maine Yankee and agrees that the decision to shut down the Unit described in Section 1 hereof does not give rise to any cancellation right under Section 9 of the Power Contract or Section 10 of the Additional Power Contract.

Except as expressly modified by this Agreement, the provisions of the Power Contract and the Additional Power Contract remain in full force and effect, recognizing that the mutually accepted decision to shut down the Unit renders moot those provisions which by their terms relate solely to continuing operation of the Unit.

3.

Amendment of Provisions of the Power Contract and the Additional Power Contract.

A.

Section 2 of the Additional Power Contract is hereby amended to delete the first two paragraphs thereof and to insert in lieu thereof the following:

This contract shall become effective on such date as may be authorized by the FERC after receipt by the Purchaser of notice that Maine Yankee has entered into Additional Power Contracts, as contemplated by Section 1 above, with each of the other sponsors. The operative term of this contract shall commence on the earlier of (a) the termination, cancellation or expiration of the Power Contract or (b) January 2, 2003, notwithstanding the fact that the useful service life of the Unit terminated prior to that date and shall terminate on the date (the "End of Term Date") which is the later to occur of (i) 30 days after the date on which the last of the financial obligations of Maine Yankee which constitute elements of the purchase price calculated pursuant to Section 7 of this contract has been satisfied in its entirety by Maine Yankee, or (ii) 30 days after the date on which Maine Yankee is finally relieved of any obligations und er the last of any licenses (operating and/or possessory) which it now holds from, or which may hereafter be issued to it by, the NRC with respect to the Unit under applicable provisions of the Atomic Energy Act of 1954, as amended from time to time (the "Act").

B.

The first paragraph of Section 7 of the Additional Power Contract is amended to read as follows:

With respect to each month commencing on or after the commencement of the operative term of this contract, whether or not this contract continues fully or partially in effect, the Purchaser will pay Maine Yankee as further deferred payment for the capacity and output of the Unit provided to the Purchaser by Maine Yankee prior to the permanent shutdown of the Unit on August 6, 1997, an amount equal to the Purchaser's entitlement percentage of the sum of (a) Maine Yankee's total fuel costs for the month with respect to the Unit, (b) the Total Decommissioning Costs for the month with respect to the Unit, plus (c) Maine Yankee's total operating expenses (as hereinafter defined) for the month with respect to the Unit, plus (d) an amount equal to one-twelfth of the composite percentage for such month of the net Unit investment as most recently determined in accordance with this Section 7.

C.

The eighth paragraph of Section 7 of the Power Contract and the eighth paragraph of Section 7 of the Additional Power Contract are each amended by (a) inserting before

the semicolon in the first sentence thereof the following:

, but including for purposes of this contract:

(i)

with respect to each month until the commencement of decommissioning of the Unit, the Purchaser's entitlement percentage of all expenses related to the storage or disposal of nuclear fuel or other radioactive materials, and all expenses related to protection and maintenance of the Unit during such period, including to the extent applicable all of the various sorts of expenses included in the definition of "Decommissioning Expenses", to the extent incurred during the period prior to the commencement of decommissioning;

(ii)

with respect to each month until the amount due from Maine Yankee to the U.S. Department of Energy ("DOE") for disposal of pre-April 7, 1983 spent nuclear fuel and associated high level radioactive material has been paid in full, the Purchaser's entitlement percentage of one-third (1/3) of the interest due to DOE during that calendar quarter on such obligation; and

(iii)

with respect to each month until End of License Term, the Purchaser's entitlement percentage of the monthly amortization of (a) the amount of any unamortized deferred expenses, as permitted from time to time by the Federal Energy Regulatory Commission or its successor agency, plus (b) the remaining unamortized amount of Maine Yankee's investment in plant, nuclear fuel and materials and supplies and other assets, such amortization to be accrued at a rate sufficient to amortize fully such unamortized deferred expenses and Maine Yankee's investments in plant, nuclear fuel and materials and supplies or other assets (the "total investment") over a period extending to October 21, 2008; [provided, that if during any calendar month ending on or before May 1, 2008 either of the following events shall occur: (a) Maine Yankee shall become insolvent or (b) Maine Yankee shall be unable, from available cash or other sources, to mee t when due during such month its obligations to pay principal, interest, premium (if any) or other fees with respect to any indebtedness for money borrowed, then Maine Yankee may adjust upward the accrual for amortization of unrecovered total investment for such month to an amount not exceeding the applicable maximum level specified in Appendix A hereto, provided that concurrently therewith the total investment shall be reduced by an amount equal to the amount of such adjustment, it being understood that at the time of such event, Maine Yankee will furnish the Purchaser with a schedule setting forth the amount of such adjustment;) <FN1>

and (b) by adding at the end thereof the following:

As used herein, "End of License Term" means October 21, 2008 or such later date as may be fixed, by amendment to the Facility Operating License for the Unit, as the end of the term of the Facility Operating License.

D.

The definitions in Section 7 of the Power Contract and in Section 7 of the Additional Power Contract of "Total Decommissioning Costs" and "Decommissioning Expenses" are hereby amended to read as follows:

"Total Decommissioning Costs" for any month shall mean the sum of (x) an amount equal to all accruals in such month to any reserve, as from time to time established by Maine Yankee and approved by its board of directors, to provide for the ultimate payment of the Decommissioning Expenses of the Unit, plus (y), during the Decommissioning Period, the Decommissioning Expenses for the month, to the extent such Decommissioning Expenses are not paid with funds from such reserve, plus (z) Decommissioning Tax Liability for such month. It is understood (i) that funds received pursuant to clause (x) may be held by Maine Yankee or by an independent trust or other separate fund, as determined by said board of directors, (ii) that, upon compliance with applicable regulatory requirements, the amount, custody and/or timing of such accruals may from time to time during the term hereof be modified by said board of directors in its discretion or to comply with applicable statutory or regulatory requirements or to reflect changes in the amount, custody or timing of anticipated Decommissioning Expenses, and (iii) that the use of the term "to decommission" herein encompasses compliance with all requirements of the NRC, as in effect from time to time, for permanent cessation of operation of a nuclear facility and any other activities reasonably related thereto, including provision for disposal of low level waste and the interim storage of spent nuclear fuel.

"Decommissioning Expenses" shall include all expenses of decommissioning the Unit, and all expenses relating to ownership and protection of the Unit during the Decommissioning Period, and shall also include the following:

(1)

All costs and expenses of any NRC-approved method of removing the Unit from service, including without limitation: dismantling, mothballing and entombment of the Unit; removing nuclear fuel and other radioactive material to temporary and/or permanent storage sites; construction, operation, maintenance and dismantling of a spent fuel storage facility; decontaminating, restoring and supervising the site; and any costs and expenses incurred in connection with proceedings before governmental authorities relating to any authorization to decommission the Unit or remove the Unit from service;

(2)

All costs of labor and services, whether directly or indirectly incurred, including without limitation, services of foremen, inspectors, supervisors, surveyors, engineers, security personnel, counsel and accountants,

performed or rendered in connection with the decommissioning of the Unit and the removal of the Unit from service, and all costs of materials, supplies, machinery, construction equipment and apparatus acquired or used (including rental charges for machinery, equipment or apparatus hired) for or in connection with the decommissioning of the Unit and the removal of the Unit from service, and all administrative costs, including services of counsel and financial advisers of any applicable independent trust or other separate fund; it being understood that any amount, exclusive of proceeds of insurance, realized by Maine Yankee as salvage on any machinery, construction equipment and apparatus, the cost of which was charged to Decommissioning Expense, shall be treated as a reduction of the amounts otherwise chargeable on account of the costs of decommissioning of the Unit; and

(3)

All overhead costs applicable to the Unit during the Decommissioning Period, or accrued during such period, including without limiting the generality of the foregoing, taxes (other than taxes on or in respect of income), charges, license fees, excises and assessments, casualties, health care costs, pension benefits and other employee benefits, surety bond premiums and insurance premiums.

E.

Section 7 of the Power Contract and Section 7 of the Additional Power Contract are each hereby amended by adding the following new paragraph after the definition of "Decommissioning Tax Liability":

"Decommissioning Period" shall mean the period commencing with the notification by Maine Yankee to the NRC of the decision of the board of directors of Maine Yankee to cease permanently the operation of the Unit for the purpose of producing electric energy and ending with the date when Maine Yankee has completed the decommissioning of the Unit and the restoration of the site and has been relieved of all its obligations under the last of any licenses issued to it by the NRC.

F.

Section 8 of the Additional Power Contract is hereby amended to change the figure "1%" to "2%".

G.

Section 9 of the Power Contract and Section 10 of the Additional Power Contract are each amended to read as follows:

10.

Cancellation of Contract.

If either

(i)

the Unit is damaged to the extent of being completely or substantially completely destroyed, or

(ii)

the Unit is taken by exercise of the right of eminent domain or a similar right or power,

then and in any such case, the Purchaser may cancel the provisions of this contract, except that in all cases other than those described in clause (ii) above, the Purchaser shall be obligated to continue to make the payments of Total Decommissioning Costs and the other payments required by Section 7 hereof and the provisions of said Section 7 and the related provisions of this contract shall remain in full force and effect, it being recognized that the costs which Purchaser is required to pay pursuant to Section 7 represent deferred payments in connection with power heretofore delivered by Maine Yankee tinder its contractual commitments to the Purchaser. Such cancellation shall be effected by written notice given by the Purchaser to Maine Yankee. In the event of such cancellation, all continuing obligations of the parties hereunder as to subsequently incurred costs of Maine Yankee other than the obligations of the Purchaser to continu e to make the payments required by Section 7 shall cease forthwith (it being understood that the continuing accrual of depreciation of net Unit investment and of fees, interest and other payments under pre-existing contracts subsequent to such cancellation shall not be deemed to be "subsequently incurred costs" for purposes of this sentence). Notwithstanding the preceding sentence, the applicable provisions of this contract shall continue in effect after the cancellation hereof to the extent necessary to permit final billings and adjustments hereunder with respect to obligations incurred through the date of cancellation and the collection thereof. Any dispute as to the Purchaser's right to cancel this contract pursuant to the foregoing provisions shall be referred to arbitration in accordance with the provisions of this contract.

Notwithstanding anything in this contract elsewhere contained, the Purchaser may cancel this contract or be relieved of its obligations to make payments hereunder only as provided in the next preceding paragraph of this Section.

5.

Effective Date

This 1997 Amendatory Agreement shall become effective upon receipt by the Purchaser of notice that Maine Yankee has entered into 1997 Amendatory Agreements, as contemplated by Section 1 hereof, with each of the other Purchasers and receipt of requisite authorization from the FERC.

6.

Interpretation

The interpretation and performance of this 1997 Amendatory Agreement shall be in accordance with and controlled by the laws of the State of Maine.

7.

Addresses

Except as the parties may otherwise agree, any notice, request, bill or other

communication from one party to the other relating to this 1997 Amendatory Agreement, or the rights, obligations or performance of the parties hereunder, shall be in writing and shall be effective upon delivery to the other party. Any such communication shall be considered as duly delivered when mailed to the respective post office address of the other party shown following the signatures of such other party hereto, or such other post office address as may be designated by written notice given in the manner as provided in this Section.

8.

Corporate Obligations

This 1997 Amendatory Agreement is the corporate act and obligation of the parties hereto.

9.

Counterparts

This 1997 Amendatory Agreement may be executed in any number of counterparts and each executed counterpart shall have the same force and effect as an original instrument and as if all the parties to all of the counterparts had signed the same instrument. Any signature page of this 1997 Amendatory Agreement may be detached from any counterpart without impairing the legal effect of any signatures thereon, and may be attached to another counterpart of this 1997 Amendatory Agreement identical in form hereto but having attached to it one or more signature pages.

IN WITNESS WHEREOF, the parties have executed this 1997 Amendatory Agreement by their respective duly authorized officers as of the day and year first named above.

MAINE YANKEE ATOMIC POWER COMPANY

By: ________________________

 Its

       VP Finance & Administration

Address: 329 Bath Road

               Brunswick, ME 04011

By: ________________________

 Its

Address:

------------------------------------------------------------------------------------------------------------

<FN>

<FN1>  Bracketed language would be inserted only if satisfactory work-out is reached with lender banks and insurance companies.

</FN>

------------------------------------------------------------------------------------------------------------

EX-10.24.1

Exhibit 10.24.1

AMENDMENT NO. 3 TO NORTHEAST UTILITIES DEFERRED COMPENSATION PLAN FOR TRUSTEES

Notwithstanding any contrary provision in the Plan, the Plan is amended, effective January 1, 2005 to add Section 11 to the Plan, to read as follows:

Participants will be provided an opportunity to elect, in calendar 2005, to rescind any deferral election, in whole or part, made with respect to amounts which would have been received in 2005 or any prior year, but for the election, and to receive a distribution of such amount.  Such rescission must result in a taxable distribution to the participant prior to January 1, 2006.

EX-10.25.1

Exhibit 10.25.1

AMENDMENT NO. 1 TO NORTHEAST UTILITIES DEFERRED COMPENSATION PLAN FOR EXECUTIVES

Section 6.3 is added to the Plan, to read as follows:

6.3  

Rescission of Prior Election In Conformity With Code Section 409A Transition Rule.  Participants will be provided an opportunity to elect, in calendar 2005, to rescind any deferral election, in whole or part, made with respect to amounts which would have been received in 2005 but for the Participant’s election, and to receive a distribution of such amount.  Such rescission must result in a taxable distribution to the Participant prior to January 1, 2006.

EX-10.30

Exhibit 10.30

ISO New England Inc. FERC Electric Tariff No. 3 Section II - Open Access Transmission Tariff Schedule 21-NU Original Sheet No. 3200

SCHEDULE 21-NU

NORTHEAST UTILITIES COMPANIES

LOCAL SERVICE SCHEDULE

Issued by: Lisa J. Thibdaue Vice President, Rates Regulatory Affairs Northeast Utilities Companies Issued on: December 22, 2004 Effective: With notice, on or after February 1, 2005

I.

COMMON SERVICE PROVISIONS

1.

Definitions

1.1

Ancillary Services: see Tariff II.1.2

1.2

Annual Transmission Costs: The total annual cost of the Transmission System for purposes of Network Integration Transmission Service shall be the amount specified in Attachments NU-H and NU-I, until amended by the Companies or modified by the Commission.

1.3

Annual True Up: The reconciliation to actual costs and actual loads of the estimated costs and loads costs used for billing purposes under Section 7.0 of this Local Service Schedule for any Service Year.

1.4

Application: see Tariff II.1.4

1.5

Category A Load Ratio Share: Ratio of a Transmission Customer's Category A Network Load to the NU Companies’ total load computed in accordance with Sections 34.3 and 34.4 of the Network Integration Transmission Service under Part III of the Tariff and calculated on a rolling twelve month basis. Also referred to as “Load Ratio Share”.

1.6

Category B Load Ratio Share: Ratio of a Transmission Customer’s Category B Network Load for a state or area in which Localized Facilities are located to the monthly transmission system peak Load for the state or area, and calculated on a rolling twelve month basis. Category B Load Ratio share will be calculated for each state or area where Localized Facilities are located.

1.7

Commission: see Tariff I.2.2(c) & II.1.8

1.8

Completed Application: see Tariff II.1.9

1.9

Control Area: see Tariff II.1.11

1.10

Curtailment: see Tariff II.1.15

1.11

Delivering Party: see Tariff II.1.17

1.12

Designated Agent: see Tariff I.2.2(e). Also, the Designated Agent of the NU Companies is the Northeast Utilities Service Company ("NUSCO") which is a subsidiary of Northeast Utilities ("NU").

1.13

Direct Assignment Facilities: see Tariff II.1.18

1.14

Eligible Customer: see Tariff II.1.21

1.15

Facilities Study: see Tariff II.1.29

1.16

Firm Point-To-Point Transmission Service: see Tariff II.1.31

1.17

Good Utility Practice: see Tariff II.1.35

1.18

Hydro-Quebec Facilities: The Phase I and Phase II Direct Current facilities located between the United States/Canadian border, Comerford Substation in New Hampshire and the extension of the line to Sandy Pond Substation in Massachusetts.

1.19

Hydro-Quebec Load Ratio Share: Ratio of a Transmission Customer's monthly maximum usage of the Hydro-Quebec Facilities by its Network Load (expressed in kilowatts) to the average of the NU Companies’ twelve monthly maximum transfer limits (expressed in kilowatts) on its share of the Phase I and Phase II Direct Current Facilities for the calendar year prior to the Service Year.

1.20

Interest: The amount computed in accordance with the Commission’s regulations at 18 CFR §35.19a(a)(2)(iii). Interest on deposits and shall be calculated from the day the deposit check is credited to the NU Companies’ account.

1.21

Interruption: A reduction in non-firm transmission service due to economic reasons pursuant to Schedule 21 I.2(g)

1.22

Load Shedding: see Tariff II.1.49

1.23

Local Point-To-Point Service: see Tariff II.1.60

1.24

Localized Facilities: Facilities, the cost of which, the New England System Operator determines should not be included in Attachment F of the Tariff revenue requirements calculation.

1.25

Long-Term Firm Point-To-Point Transmission Service: see Tariff II.1.32 & II.1.65

1.26

Market Rule 1: see Tariff II.1.68

1.27

Native Load Customers: see Tariff II.1.78

1.28

NEPOOL: see Tariff II.1.80

1.29

NEPOOL Agreement: see Tariff II.1.81

1.30

NEPOOL Tariff: [deleted]

1.31

Network Customer: see Tariff II.1.82

1.32

Network Integration Transmission Service: Also referred to as Local Network Service. See Tariff II.1.58

1.33

Network Load: The load that a Network Customer designates for Network Integration Transmission Service. The Network Customer's Network Load shall include all load served by the output of any Network Resources designated by the Network Customer. A Network Customer may elect to designate less than its total load as Network Load but may not designate only part of the load at a discrete Point of Delivery. Where an Eligible Customer has elected not to designate a particular load at discrete points of delivery as Network Load, the Eligible Customer is responsible for making separate arrangements for any Point-To-Point Transmission Service that may be necessary for such non-designated load.

1.34

Network Operating Agreement: An executed agreement that contains the terms and conditions under which the Network Customer shall operate its facilities and the technical and operational

matters associated with the implementation of Network Integration Transmission Service under Part III of the Tariff.

1.35

Network Operating Committee: [deleted]

1.36

Network Resource: see Tariff II.1.83

1.37

Network Upgrades: Modifications or additions to transmission-related facilities that are integrated with and support the NU Companies’ overall Transmission System for the general benefit of all users of such Transmission System.

1.38

New England System Operator: ISO New England, Inc.(“ISO”) or its successor entity.

1.39

Non-Firm Point-To-Point Transmission Service: see Tariff II.1.87

1.40

Non-PTF: Tariff II.1.89

1.41

.Open Access Same-Time Information System (OASIS): see Tariff II.1.92

1.42

Part I: [deleted]

1.43

Part II: [deleted]

1.44

Part III: [deleted]

1.45

Party(ies): The NU Companies and the Transmission Customer receiving service under the Tariff.

1.46

Point(s) of Delivery: see Tariff II.1.101

1.47

Point(s) of Receipt: see Tariff II.1.102

1.48

Point-To-Point Transmission Service: see Tariff II.1.103

1.49

Power Purchaser: see Tariff II.1.108

1.50

PTF or Pool Transmission Facilities: see Tariff II.1.109

1.51

Receiving Party: see Tariff II.1.116

1.52

Regional Transmission Group (RTG): [deleted]

1.53

Reserved Capacity: The maximum amount of capacity and/or energy that the NU Companies agrees to transmit for the Transmission Customer over the NU Companies’ Transmission System between the Point(s) of Receipt and the Point(s) of Delivery under Part II of the Tariff. Reserved Capacity shall be expressed in increments of 10 kW or greater on a sixty (60) minute interval (commencing on the clock hour) basis.

1.54

Service Agreement: see Tariff II.1.132

1.55

Service Commencement Date: see Tariff II.1.133

1.56

Short-Term Firm Point-To-Point Transmission Service: Firm Point-To-Point Transmission Service with a term of less than one year.

1.57

Service Year: The calendar year in which the Transmission Customer is receiving service under this Local Service Schedule.

1.58

System Impact Study: see Tariff II.1.136

1.59

Tariff: see Tariff I.2.2(hh)

1.60

Third-Party Sale: see Tariff II.1.137

1.61

Transmission Customer: see Tariff I.2.2(gg)

1.62

NU Companies: The Northeast Utilities Companies (or "NU Companies") which consists of The Connecticut Light and Power Company, Western Massachusetts Electric Company, Holyoke Water Power Company, Holyoke Power and Electric Company, and Public Service Company of New Hampshire, each an operating company of Northeast Utilities ("NU").

1.63

NU Companies’ Monthly Transmission System Peak: The maximum firm usage of the NU Companies Transmission System in a calendar month (this does not include load exclusively connected to PTF).

1.64

NU Companies’ Transmission System: The PTF and non-PTF facilities owned, controlled or operated by the NU Companies that are used to provide transmission service under this Local Service Schedule. This includes PTF facilities whose costs are not included in the regional rate.

1.65

Transmission Service: Point-To-Point Transmission Service provided under this Local Service Schedule on a firm and non-firm basis.

2.

Reservation Priority For Existing Firm Service Customers: see Schedule 21 Part I § 1.b

3.

Ancillary Services: Ancillary Services are needed with transmission service to maintain reliability within and among the Control Areas affected by the transmission service. The NU Companies are required to provide (or offer to arrange with the New England System Operator as discussed below), and the Transmission Customer is required to purchase, the following Ancillary Service (i) Scheduling, System Control and Dispatch.

The Transmission Customer serving load within the NU Companies’ Control Area shall also obtain the following ancillary services: (i) Reactive Supply and Voltage Control from Generation Sources, (ii) Regulation and Frequency Response, (iii) Energy Imbalance, (iv) Operating Reserve - Spinning, and (v) Operating Reserve - Supplemental.  The Transmission Customer serving load within the NU Companies’ Control Area is required to acquire the appropriate Ancillary Services, whether from the New England System Operator, NU Companies, another party, or by self-supply.

The Transmission Customer may not decline the NU Companies’ or the New England System Operator’s offers of appropriate Ancillary Services unless it demonstrates that it has acquired the Ancillary Services from another source. The Transmission Customer must list in its Application which Ancillary Services it will purchase from the NU Companies.

If the NU Companies are unable to provide Scheduling, System Control and Dispatch, the NU Companies can fulfill their obligation to provide this Ancillary Service by acting as the Transmission Customer's agent to secure this Ancillary Service from the New England System Operator. The Transmission Customer may elect to (i) have the NU Companies act as its agent to obtain Scheduling, System Control and Dispatch, (ii) secure Scheduling, System Control and Dispatch directly from the New England System Operator, or from a third party.

The NU Companies or New England System Operator shall specify the rate treatment and all related terms and conditions in the event of an unauthorized use of Ancillary Services by the Transmission Customer.

The specific Ancillary Services, prices and/or compensation methods are described on the Schedule that is attached to and made a part of the Tariff. Three principal requirements apply to discounts for Ancillary Services provided by the NU Companies in conjunction with their provision of transmission service as follows: (1) any offer of a discount made by the NU Companies 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. A discount agreed upon for an Ancillary Service must be offered for the same period to all Eligible Customers on the NU Companies’ system

4.

Open Access Same-Time Information System (OASIS): see Tariff II.5

5.

Local Furnishing Bonds: see Tariff II.6

5.1

Facilities Financed by Local Furnishing Bonds see Tariff II.6.1

5.2

Alternative Procedures for Requesting Transmission Service see Tariff II.6.2

6.

Reciprocity: see Tariff II.7

7.

Billing and Payment

7.1

Billing Procedure: Within a reasonable time after the first day of each month, the NU Companies shall submit an invoice to the Transmission Customer for the charges for all services furnished under the Tariff during the preceding month.  The invoice shall be paid by the Transmission Customer within twenty (20) days of receipt. All payments shall be made in immediately available funds payable to the NU Companies, or by wire transfer to a bank named by the NU Companies.  Billing hereunder shall be based on cost estimates made by the NU Companies subject to Annual True-up when actual costs for the Service Year are known.  Such Annual True-up shall occur no later than six (6) months after the close of the Service Year to which the Annual True-up relates.

7.2

Interest on Unpaid Balances: Interest on any unpaid amounts (including amounts placed in escrow) shall be calculated in accordance with the methodology specified for interest on refunds in the Commission's regulations at 18 C.F.R. § 35.19a(a)(2)(iii). Interest on delinquent amounts shall be calculated from the due date of the bill to the date of payment. When payments are made by mail, bills shall be considered as having been paid on the date of receipt by the NU Companies.

7.3

Customer Default: In the event the Transmission Customer fails, for any reason other than a billing dispute as described below, to make payment to the NU Companies on or before the due date as described above, and such failure of payment is not corrected within thirty (30) calendar days after the NU Companies notifies the Transmission Customer to cure such failure, a default by the Transmission Customer shall be deemed to exist. Upon the occurrence of a default, the NU Companies may initiate a proceeding with the Commission to terminate service but shall not terminate service until the Commission so approves any such request. In the event of a billing dispute between the NU Companies and the Transmission Customer, the NU Companies will continue to provide service under the Service Agreement as long as the Transmission Customer (i) continues to make all payments not in dispute, and (ii) pays into an independent escrow account th e portion of the invoice in dispute, pending resolution of such dispute. If the Transmission Customer fails to meet these two requirements for continuation of service, then the NU Companies may provide notice to the Transmission Customer of its intention to suspend service in sixty (60) days, in accordance with Commission policy. Neither Party shall have the right to challenge any monthly bill or to bring any court or administrative action of any kind questioning the propriety of any bill after a period of twenty four (24) months from the date the bill was due; provided, however, that in the case of a bill based on estimates, such twenty-four month period shall run from the due date of the final adjusted bill.

7.4

Transmission Customer Right to Audit: The NU Companies shall keep complete and accurate accounts and records with respect to their performance under this Local Service Schedule and shall maintain such data for a period of at least one (1) year after final billing for audit by a Transmission Customer. The Transmission Customer shall provide 30 days written notice to the NU Companies to request an audit of all such relevant accounts and records for a specific time period. The Transmission Customer shall have the right, during normal business hours and at its own expense, to examine, inspect and make copies of all such accounts and records at such offices where such accounts and records are maintained, insofar as may be necessary for the purpose of ascertaining the reasonableness and accuracy of all relevant data, estimates or statement of charges submitted hereunder. The records supplied to a Transmission Customer for auditing pu rposes hereunder shall be limited to those portions of such accounts and records that relate to such Transmission Customer’s transmission service(s) purchased under this Local Service Schedule for said calendar year.

8.

Accounting for the NU Companies’ Use of the Tariff: The NU Companies shall record the following amounts, as outlined below.

8.1

Transmission Revenues: See Tariff II.8.5.

8.2

Study Costs and Revenues: See Tariff II.8.5.

8.3

ISO Payments/Revenues: Include in separate operating accounts or subaccounts payments made or revenues received under the Tariff.

9.

Regulatory Filings: Nothing contained in the Tariff or any Service Agreement shall be construed as affecting in any way the right of the NU Companies to unilaterally make application to the Commission for a change in rates, terms and conditions, charges, classification of service, Service Agreement, rule or regulation under Section 205 of the Federal Power Act and pursuant to the Commission's rules and regulations promulgated thereunder.

Nothing contained in the Tariff or any Service Agreement shall be construed as affecting in any way the ability of any Party receiving service under the Tariff to exercise its rights under the Federal Power Act and pursuant to the Commission's rules and regulations promulgated there under.

10.

Force Majeure and Indemnification

10.1

Force Majeure: See Schedule 21 Preamble.

10.2

Indemnification: See Schedule 21 Preamble.

11.

Creditworthiness:

For the purpose of determining the ability of the Transmission Customer to meet its obligations related to service hereunder, the NU Companies may require reasonable credit review procedures. This review shall be made in accordance with standard commercial practices. In addition, the NU Companies may require the Transmission Customer to provide and maintain in effect during the term of the Service Agreement, an unconditional and irrevocable letter of credit from an institution rated “A” or better by S&P or “A3” or better by Moody’s as security to meet its responsibilities and obligations under the Tariff, or an alternative form of security proposed by the Transmission Customer and acceptable to the NU Companies and consistent with commercial practices established by the Uniform Commercial Code that protects the NU Companies against the risk of nonpayment.

12.

Dispute Resolution Procedures

12.1

Internal Dispute Resolution Procedures see Tariff I.6

12.2

External Arbitration Procedures Deleted

12.3

Arbitration Decisions Deleted

12.4

Costs Deleted

12.5

Rights Under The Federal Power Act: Nothing in this section shall restrict the rights of any party to file a Complaint with the Commission under relevant provisions of the Federal Power Act.

II.

POINT-TO-POINT TRANSMISSION SERVICE

Preamble

see Schedule 21 § 1

13.

Nature of Firm Point-To-Point Transmission Service

13.1

Schedule 21 Term: see Schedule 21 § 1(a)

13.2

Reservation Priority see Schedule 21 § 1(b)

13.3

Use of Firm Transmission Service by the NU Companies: see Schedule 21 § 1(c)

13.4

Service Agreements: see Schedule 21 § 1(d)

13.5

Transmission Customer Obligations for Facility Additions or Redispatch Costs: see Schedule 21 § 1(e)

13.6

Curtailment of Firm Transmission Service: see Schedule 21 § 1(f)

13.7

Classification of Firm Transmission Service:

(a)

see Schedule 21 I.1(g)(i)

(b)

see Schedule 21 I.1(g)(ii)

(c)

see Schedule 21 I.1(g)(iii). Also, the Transmission Customer will be billed for its Reserved Capacity under the terms of Schedule NU-2 , as appropriate, for Long and Short-Term Firm Point-To-Point Transmission Service. For Firm Point-To-Point Transmission Service over the Hydro-Quebec Facilities, the Transmission Customer will be billed for its Reserved Capacity under the terms Schedule HQ-STF or Schedule HQ-LTF, as appropriate, of Supplement No. 1 to the Tariff. The Transmission Customer may not exceed its firm capacity reserved at each Point of Receipt and each Point of Delivery except as otherwise specified in Section 22. In the event that a Transmission Customer (including Third-Party Sales by the NU Companies) exceeds its firm Reserved Capacity at any Point of Receipt or Point of Delivery (except as otherwise specified in Section 22), the Transmission Customer shall pay, for each day 200% of the charge which is otherwise applicab le for such excess, the daily Schedule NU-2, or if applicable, the daily Schedule HQ-STF for the maximum amount that the Transmission Customer exceeds its firm Reserved Capacity at any Point of Receipt or Point of Delivery in that day.  In the event that the Non-Firm Transmission Service provided to the Transmission Customer for Secondary Receipt and Delivery Points pursuant to Section 22.1 of the Tariff exceeds the capacity reservation under which services are provided, the Transmission Customer shall pay 200% of the charge which is otherwise applicable, for each hour of such excess, the hourly ceiling Schedule NU-3 or, if applicable, the hourly ceiling Schedule HQ-NF charge for the maximum amount that the Transmission Customer exceeds its capacity reservation in that hour.

13.8

Scheduling of Firm Point-To-Point Transmission Service: See Schedule 21 I.1(h). Also; 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 New England Control Area using Firm Point-to-Point Transmission Service shall be dispatched based on economic merit in accordance with Market Rule 1 and will have no physical scheduling or dispatch rights. Transmission Customers will be charged for congestion costs and any other costs associated with such dispatch in accordance with Market Rule 1.

14.

Nature of Non-Firm Point-To-Point Transmission Service

14.1

Term: see Schedule 21 § 2(a)

14.2

Reservation Priority: see Schedule 21 § 2(b)

14.3

Use of Non-Firm Point-To-Point Transmission Service by the NU Companies: see Schedule 21 § 2(c)

14.4

Service Agreements: see Schedule 21 § 2(d)

14.5

Classification of Non-Firm Point-To-Point Transmission Service: see Schedule 21 § 2(e); Also, in the event that a Transmission Customer (including Third-Party Sales by the NU Companies) exceeds its non-firm capacity reservation at any Point of Receipt or Point of Delivery, the Transmission Customer shall pay, for each hour of such excess, 200% of the applicable charge for the maximum amount that the Transmission Customer exceeds its capacity reservation in that hour. Non-Firm Point-To-Point Transmission Service shall include transmission of energy on an hourly basis and transmission of scheduled short-term capacity and/or energy on a daily, weekly or monthly basis, but not to exceed one month's reservation for any one Application, under Schedule NU-3 or, if applicable, under Schedule HQ-NF.

14.6

Scheduling of Non-Firm Point-To-Point Transmission Service: see Schedule 21 § 2(f)

14.7

Curtailment or Interruption of Service: see Schedule 21 § 2(g)

15.

Service Availability

15.1

General Conditions: see Schedule 21 § 3(a)

15.2

Determination of Available Transmission Capability: see Schedule 21 § 3(b)

15.3

Initiating Service in the Absence of an Executed Service Agreement: see Schedule 21 § 3(c)

15.4

Obligation to Provide Transmission Service that Requires Expansion or Modification of the Transmission System: see Schedule 21 § 3(d)

15.5

Deferral of Service: see Schedule 21 § 3(e)

15.6

Other Transmission Service Schedules: see Schedule 21 § 3(f)

15.7

Real Power Losses: Real Power Losses are associated with all transmission service. The NU Companies are not obligated to provide Real Power Losses.  The Transmission Customer is responsible for replacing losses associated with all transmission service as determined under Market Rule 1. The applicable Real Power Loss factors are as follows:

The amount of transmission losses incurred in transmitting power from the POR(s) to the POD(s) ("Loss Amount") shall be determined from time to time by the New England System Operator in accordance with ISO procedures applicable at the time of delivery. The Loss Amounts, when determined by the New England System Operator, shall be posted on the NU Companies’ Open Access Same-Time Information System ("OASIS"). In the event that the New England System Operator, for any reason, does not determine the entire Loss Amount, the losses not determined by the New England System Operator shall be based on average system losses as set forth below:

Cumulative Losses in Percent

POR/POD	Peak*	Off-Peak	24 Hr. Avg.
Bulk Transmission	1.98	2.42	2.21
Bulk Substation	2.46	2.92	2.70
Pri. Distribution	4.58	4.50	4.54

*Peak hours are defined as 0700-2300, Monday-Friday; Off-Peak hours are all other hours.

16.

Transmission Customer Responsibilities:

16.1

Conditions Required of Transmission Customers: See Schedule 21 § 4(a)

16.2

Transmission Customer Responsibility for Third-Party Arrangements: See Schedule 21 § 4(b)

17.

Procedures for Arranging Firm Point-To-Point Transmission Service

17.1

Application: see Schedule 21 § 5(a)

17.2

Completed Application: See Schedule 21 § 5(b)

17.3

Deposit:   A Completed Application for Firm Point-To-Point Transmission Service also shall include a deposit of either three month's charge for Reserved Capacity or the full charge for Reserved Capacity for service requests of less than one month. see Schedule 21 § 5(c)

17.4

Notice of Deficient Application: see Schedule 21 § 5(d)

17.5

Response to a Completed Application: see Schedule 21 § 5(e)

17.6

Execution of Service Agreement: see Schedule 21 § 5(f)

17.7

Extensions for Commencement of Service: see Schedule 21 § 5(g)

18.

Procedures for Arranging Non-Firm Point-To-Point Transmission Service: Schedule 21

18.1

Application: see Schedule 21 § 6(a)

18.2

Completed Application: see Schedule 21 § 6(b)

18.3

Reservation of Non-Firm Point-To-Point Transmission Service: see Schedule 21 § 6(c)

18.4

Determination of Available Transmission Capability: see Schedule 21 § 6(d)

19.

Additional Study Procedures For Firm Point-To-Point Transmission Service Requests: Schedule 21

19.1

Notice of Need for System Impact Study: see Schedule 21 § 7(a)

19.2

System Impact Study Agreement and Cost Reimbursement: see Schedule 21 § 7(b)

19.3

System Impact Study Procedures: see Schedule 21 § 7(c)

19.4

Facilities Study Procedures: see Schedule 21 § 7(d)

19.5

Facilities Study Modifications: see Schedule 21 § 7(e)

19.6

Due Diligence in Completing New Facilities: see Schedule 21 § 7(f)

19.7

Partial Interim Service: see Schedule 21 § 7(g)

19.8

Expedited Procedures for New Facilities: see Schedule 21 § 7(h)

20.

Procedures if The NU Companies are Unable to Complete New Transmission Facilities for Firm Point-To-Point Transmission Service:

20.1

Delays in Construction of New Facilities: see Schedule 21 § 8(a)

20.2

Alternatives to the Original Facility Additions: see Schedule 21 § 8(b)

20.3

Refund Obligation for Unfinished Facility Additions: see Schedule 21 § 8(c)

21.

Provisions Relating to Transmission Construction and Services on the Systems of Other Utilities

21.1

Responsibility for Third-Party System Additions: see Schedule 21 § 9(a)

21.2

Coordination of Third-Party System Additions: see Schedule 21 § 9(b)

22.

Changes in Service Specifications

22.1

Modifications On a Non-Firm Basis: see Schedule 21 § 10(a)

22.2

Modification On a Firm Basis: see Schedule 21 § 10(b)

23.

Sale or Assignment of Transmission Service:

23.1

Procedures for Assignment or Transfer of Service: see Schedule 21 § 11(a)

23.2

Limitations on Assignment or Transfer of Service: see Schedule 21 § 11(b)

23.3

Information on Assignment or Transfer of Service: see Schedule 21 § 11(c)

24. Metering and Power Factor Correction at Receipt and Delivery Points(s):

24.1

Transmission Customer Obligations: see Schedule 21 § 12(a)

24.2

NU Companies Access to Metering Data: see Schedule 21 § 12(b)

24.3

Power Factor: see Schedule 21 § 12(c)

25.

Compensation for Transmission Service

The Transmission Customers taking Point-To-Point Transmission Service shall pay the NU Companies for any Direct Assignment Facilities, Ancillary Services and applicable study costs, along with the following:

25.1

Rates and Charges for Transmission Service: Rates for Firm and Non-Firm Point-To-Point Transmission Services are provided in the Attachments appended to this Local Service Schedule: Firm Point-To-Point Transmission Services (Schedule NU-2); and Non-Firm Point-To-Point Transmission Services (Schedule NU-3).

25.2

Rates for Firm and Non-Firm Point-To-Point Transmission Services Rates for Firm and Non-Firm Point to Point Transmission Services shall be determined as set forth in Attachments NU-2 and NU-3 of this Local Service Schedule on the basis of estimated costs for each Service Year until the actual costs for such Service Year are determined. Thereafter, payments made on such estimated costs shall be recalculated based on actual data for that Service Year, and an appropriate billing adjustment shall be made pursuant to Section 7 of this Local Service Schedule. Rates for Firm and Non-Firm Point-To-Point Transmission Service over the Hydro-Quebec Facilities are provided in Supplement No. 1 to the Tariff. The NU Companies shall use Part II of the Tariff to make their Third-Party Sales. The NU Companies shall account for such use at the applicable Tariff rates, pursuant to Section 8 of this Local Service Schedule.  Within 60 days fol lowing the Commission's issuance of a order accepting and approving a transmission tariff for the New England RTO, the NU Companies will submit a compliance filing in order to conform, as necessary, the provisions in this Local Service Schedule regarding the charges for Localized Facilities (including the Category B Formula Rate referenced in Appendix B to Attachments NU-2 and NU-3) to the provisions of the RTO Tariff, including any necessary conforming changes relating to the specification of the customers subject to Category B charges. The proceeding on such compliance filing will be for the limited purpose of reviewing such filing. The NU Companies will not charge any Transmission Customers under the Category B Formula Rate until such compliance filing has been accepted and approved.

26.

Stranded Cost Recovery: see Schedule 21 Part I Preamble

27.

Compensation for New Facilities and Redispatch Costs: see Schedule 21 Part I § 14

III.

NETWORK INTEGRATION TRANSMISSION SERVICE

Preamble

see Schedule 21 Part II Preamble

28.

Nature of Local Network Integration Transmission Service

28.1

Scope of Service: see Schedule 21 Part II § 2(c)

28.2

NU Companies’ Responsibilities: see Schedule 21 Part II § 2(d)

28.3

Network Integration Transmission Service: see Schedule 21 Part II § 2(e)

28.4

Secondary Service: see Schedule 21 Part II § 2(g)

28.5

Real Power Losses: Real Power Losses are associated with all transmission service. The NU Companies are not obligated to provide Real Power Losses.  The Network Customer is responsible for replacing losses associated with all transmission service as determined under Market Rule 1. The applicable Real Power Loss factors are as follows:

The amount of transmission losses incurred in transmitting power across the NU Companies’ Transmission System to the Network Customer's Network Load shall be determined from time to time by the New England System Operator in accordance with ISO procedures applicable at the time of delivery. The Loss Amounts, when determined by the New England System Operator, shall be posted on the Open Access Same-Time Information System ("OASIS"). In the event that the New England System Operator, for any reason, does not determine the entire Loss Amount, the losses not determined by the New England System Operator shall be based on average system losses as set forth below:

Cumulative Losses in Percent

POR/POD	Peak*	Off-Peak	24 Hr. Avg.
Bulk Transmission	1.98	2.42	2.21
Bulk Substation	2.46	2.92	2.70
Pri. Distribution	4.58	4.50	4.54

*Peak hours are defined as 0700-2300, Monday-Friday; Off-Peak hours are all other hours.

28.6

Restrictions on Use of Service: see Schedule 21 Part II § 2(h)

29.

Initiating Service:

29.1

Condition Precedent for Receiving Service: see Schedule 21 Part II § 3(a)

29.2

Application Procedures: see Schedule 21 Part II § 3(b)

29.3 Technical Arrangements to be Completed Prior to Commencement of Service: see Schedule 21 Part II § 3(c)

29.4

Network Customer Facilities: see Schedule 21 Part II § 3(d)

29.5

Filing of Service Agreement: see Schedule 21 Part II § 3(e)

30.

Network Resources

30.1

Designation of Network Resources: see Schedule 21 Part II § 4(a)

30.2

Designation of New Network Resources: see Schedule 21 Part II § 4(b)

30.3

Termination of Network Resources: see Schedule 21 Part II § 4(c)

30.4

Operation of Network Resources: Deleted

30.5

Network Customer Redispatch Obligation: see Schedule 21 Part II § 4(d)

30.6

Transmission Arrangements for Network Resources Not Physically Interconnected With The NU Companies: see Schedule 21 Part II § 4(e)

30.7

Limitation on Designation of Network Resources: see Schedule 21 Part II § 4(f)

30.8

Use of Interface Capacity by the Network Customer: There is no limitation upon a Network Customer's use of the NU Companies’ Transmission System at any particular interface to integrate the Network Customer's Network Resources (or substitute economy purchases) with its Network Loads. However, a Network Customer's use of the NU Companies’ total interface capacity with other transmission systems may not exceed the Network Customer's Load.

30.9

Network Customer Owned Transmission Facilities: see Schedule 21 Part II § 4(g)

31.

Designation of Network Load

31.1

Network Load: see Schedule 21 Part II § 5(a)

31.2

New Network Loads Connected With the NU Companies: see Schedule 21 Part II § 5(b)

31.3

Network Load Not Physically Interconnected with the NU Companies: see Schedule 21 Part II § 5(c)

31.4

New Interconnection Points: see Schedule 21 Part II § 5(d)

31.5

Changes in Service Requests: see Schedule 21 Part II § 5(e)

31.6

Annual Load and Resource Information Updates: see Schedule 21 Part II § 5(f)

32.

Additional Study Procedures For Network Integration

Transmission Service Requests

32.1

Notice of Need for System Impact Study: see Schedule 21 Part II § 6(a)

32.2

System Impact Study Agreement and Cost Reimbursement: see Schedule 21 Part II § 6(b)

32.3

System Impact Study Procedures: see Schedule 21 Part II § 6(c)

32.4

Facilities Study Procedures: see Schedule 21 Part II § 6(d)

33.

Load Shedding and Curtailments:

33.1

Procedures: see Schedule 21 Part II § 7(a)

33.2

Transmission Constraints: see Schedule 21 Part II § 7(b)

33.3

Cost Responsibility for Relieving Transmission Constraints: see Schedule 21 Part II § 7(c)

33.4

Curtailments of Scheduled Deliveries: see Schedule 21 Part II § 7(d)

33.5

Allocation of Curtailments: see Schedule 21 Part II § 7(e)

33.6

Load Shedding: see Schedule 21 Part II § 7(f)

33.7

System Reliability: see Schedule 21 Part II § 7(g)

34.

Rates and Charges

The Network Customer shall pay the NU Companies for any Direct Assignment Facilities, Ancillary Services, and applicable study costs, consistent with Commission policy, along with the following:

34.1

Rates and Charges Rates for Network Integration Transmission Service shall be determined as set forth in Schedule NU-4 on the basis of estimated costs for each Service Year until the actual costs for such Service Year are determined.  Thereafter, payments made on such estimated costs shall be recalculated based on actual data for that Service Year, and an appropriate billing adjustment shall be made pursuant to Section 7 of this Local Service Schedule.

34.2

Eligible Customers Taking Service Under the ISO Tariff: Any Eligible Customer taking Regional Network Service under the ISO Tariff in a state or  area in which Localized Facilities are located, and which is not subject to the Monthly Demand Charges set forth in Section 34.3 of this Local Service Schedule, shall pay to the NU Companies the customer’s Category B Load Ratio Share of the Formula Requirements as calculated in Schedule NU-4, Appendix B for such state or area. The NU Companies shall file a Service Agreement under this Local Service Schedule, in the form set forth in Attachment NU-E, to recover such charges from such customer. The NU Companies shall not charge any such customer any such costs until such Service Agreement has been accepted by the Commission.

34.3

Monthly Demand Charge: The Network Customer shall pay monthly Demand Charges, which shall be determined by multiplying its Category A Load Ratio Share times one twelfth (1/12) of the Formula Requirements in Schedule NU-4, Appendix A, and by multiplying its Category B Load Ratio Share for each state or area in which localized Facilities are located times one twelfth (1/12) of the Formula Requirements in Schedule NU-4, Appendix B for such state or area.  For Network Service over the Hydro-Quebec Facilities, the Network Customer shall pay a monthly Demand Charge, which shall be determined by multiplying its Hydro-Quebec Load Ratio Share times one twelfth (1/12) of the NU Companies’ Hydro-Quebec Annual Transmission Revenue Requirement

specified in Attachment HQ-NETWORK of Supplement No. 1 to this local service schedule.

Within 60 days following the Commission's issuance of a order accepting and approving a transmission tariff for the New England RTO, the NU Companies will submit a compliance filing in order to conform, as necessary, the provisions in this Local Service Schedule regarding the charges for Localized Facilities (including the Category B Formula Rate referenced in Appendix B to Schedule NU-4) to the provisions of the Tariff, including any necessary conforming changes relating to the specification of the customers subject to Category B charges. The proceeding on such compliance filing will be for the limited purpose of reviewing such filing. The NU Companies will not charge any Transmission Customers under the Category B Formula Rate until such compliance filing has been accepted and approved.

34.4

Determination of Network Customer's Monthly Network Load: The Network Customer's Monthly Category A Network Load is its hourly load (including its designated Network Load not physically interconnected with the NU Companies under Schedule 21 Part II § 5) coincident with the NU Companies’ Monthly Transmission System Peak.

The Network Customer’s Monthly Category B Load for a state or area in which Localized Facilities are located is its hourly load in such state or area coincident with the monthly transmission system peak load for such state or area.

34.5

Determination of NU Companies’ Monthly Transmission System Load:

The NU Companies’ Monthly Transmission System Category A Load is the NU Companies’ Monthly Transmission System Peak minus the coincident peak usage of all Firm Point-To-Point Transmission Service customers pursuant to this Local Service Schedule plus the Reserved Capacity of all Firm Point-To-Point Transmission Service customers.<FN1>

The NU Companies’ Monthly Transmission System Category B Load for a state or area in which Localized Facilities are located is the monthly transmission system peak load for such state or area.1

34.6

Redispatch Charge: The Network Customer shall pay its Load Ratio Share of any redispatch costs allocated between the Network Customer and the NU Companies pursuant to Schedule 21 Part II § 7. To the extent that the NU Companies incurs an obligation to the Network Customer for redispatch costs in accordance with Section 33, such amounts shall be credited against the Network Customer's bill for the applicable month.

34.7

Stranded Cost Recovery: See Schedule 21 Part II § 2(b)

35.

Operating Arrangements

35.1

Operation under The Network Operating Agreement: The Network Customer shall plan, construct, operate and maintain its facilities in accordance with Good Utility Practice and in conformance with the Network Operating Agreement.

35.2

Network Operating Agreement: The terms and conditions under which the Network Customer shall operate its facilities and the technical and operational matters associated with the implementation of Part III of the Tariff shall be specified in the Network Operating Agreement. The Network Operating Agreement shall provide for the Parties to (i) operate and maintain equipment necessary for integrating the Network Customer within the NU Companies’ Transmission System (including, but not limited to, remote terminal units, metering, communications equipment and relaying equipment), (ii) transfer data between the NU Companies and the Network Customer (including, but not limited to, heat rates and operational characteristics of Network Resources, generation schedules for units outside the NU Companies’ Transmission System, interchange schedules, unit outputs for redispatch required under Section 33, voltage schedules, loss fact ors and other real time data), (iii) use software programs required for data links and constraint dispatching, (iv) exchange data on forecasted loads and resources necessary for long-term planning, and (v) address any other technical and operational considerations required for implementation of Part III of the Tariff, including scheduling protocols. The Network Operating Agreement will recognize that the Network Customer shall either (i) operate as a Control Area under applicable guidelines of the North American Electric Reliability Council (NERC) and the Northeast Power Coordinating Council (NPCC), (ii) satisfy its Control Area requirements, including all necessary Ancillary Services, by contracting with the NU Companies, or (iii) satisfy its Control Area requirements, including all necessary Ancillary Services, by contracting with another entity, consistent with Good Utility Practice, which satisfies NERC and NPCC requirements. The NU Companies shall not unreasonably refuse to accept contractual arrangemen ts with another entity for Ancillary Services. The Network Operating Agreement is included in Attachment NU-G.

35.3

Network Operating Committee: A Network Operating Committee (Committee) shall be established to coordinate operating criteria for the Parties' respective responsibilities under the Network Operating Agreement. Each Network Customer shall be entitled to have at least one representative on the Committee. The Committee shall meet from time to time as need requires, but no less than once each calendar year.

SCHEDULE NU-1

Scheduling, System Control and Dispatch Service

This service is required to schedule the movement of power through, out of, within, or into a Control Area. This service can be provided only by the operator of the Control Area in which the transmission facilities used for transmission service are located. Scheduling, System Control and Dispatch Service is to be provided directly by the NU Companies (if the NU Companies are the Control Area operator) or indirectly by the NU Companies making arrangements with the New England System Operator that performs this service for the NU Companies’ Transmission System. The Transmission Customer must purchase this service from the NU Companies or the New England System Operator. The charges for Scheduling, System Control and Dispatch Service are to be based on the rates set forth below. To the extent the New England System Operator performs this service for the NU Companies, charges to the Transmission Customer are to reflect only a pass-thr ough of the costs charged to the NU Companies by that New England System Operator.

Each Point-To-Point Transmission Customer under this Local Service Schedule will be charged for Transmission Scheduling, System Control and Dispatch Services for the total Reserved Capacity

specified in each reservation for Point-To-Point Transmission Service made under this Local Service Schedule at the rates set forth in Appendix A of this Schedule NU-1.

Each Network Customer under this Local Service Schedule will be charged a monthly Transmission Scheduling, System Control and Dispatch Service Demand Charge, which shall be determined by multiplying its Load Ratio Share times one twelfth (1/12) of the Formula Requirements specified in Appendix B of this Schedule NU-1.

Each Transmission Customer with generation within the New England Control Area shall be required also to provide for Scheduling, System Control and Dispatch Service for that generation. It is anticipated that the Transmission Customer will obtain these services from the ISO. The NU Companies will make available Generation Scheduling, System Control and Dispatch Service at the rates set forth in Appendix C of this Schedule NU-1.

Each Transmission Customer with generation located outside of the New England Control Area shall be required to provide for Scheduling, System Control and Dispatching Service for that generation. It is anticipated that the Transmission Customer will obtain these services by contracting for these services from the provider of these services within the Control Area where the generation is located.

The NU Companies shall have the right, at any time, unilaterally to file for a change in any of the provisions of this Schedule NU-1 in accordance with Section 205 of the Federal Power Act and the Commission's implementing regulations.

SCHEDULE NU-1

Appendix A

DETERMINATION OF

THE NU COMPANIES' POINT-TO-POINT FORMULA RATE

FOR TRANSMISSION SCHEDULING, SYSTEM CONTROL AND DISPATCH

SERVICE

The NU Companies' Formula Rate for Point-To-Point Transmission Scheduling, System Control

and Dispatch Service ("Formula Rate") is an annual rate determined from the following formula.

Formula Ratei = (Ai-1 – Bi-1) / Ci-1 WHERE:

•

i equals the calendar year during which service is being rendered ("Service Year").

•

Ai-1 is the Annual Control Center Expenses (expressed in dollars) of the NU Companies for the calendar year prior to the Service Year. The Annual Control Center Expenses are determined pursuant to the formula specified in Exhibit 1 to this Appendix A of Schedule NU-1.

•

Bi-1 is the actual transmission scheduling, system control and dispatch revenues (expressed in dollars) provided from the provision of transmission services to others.  The actual transmission scheduling and dispatch revenues shall be those recorded on the books of the NU Companies in FERC Account No. 456 pertaining to Transmission of Electricity for Others and such other applicable FERC accounts for the calendar year prior to the Service Year.

•

Ci-1 is the average NU Companies’ Monthly Transmission System Category A Load (expressed in kilowatts).

SCHEDULE NU-1

Appendix A

Exhibit 1

DETERMINATION OF ANNUAL CONTROL CENTER EXPENSES

The rate formula for determination of the annual control center expenses revenue requirements for each of the NU Companies is determined as follows:

A.

ANNUAL CONTROL CENTER EXPENSES  = The NU Companies' System Control and Load Dispatching Expense, for the calendar year prior to the Service Year, as recorded in FERC Account 561.

SCHEDULE NU-1

Appendix B

DETERMINATION OF

THE NU COMPANIES'

NETWORK FORMULA REQUIREMENTS

FOR TRANSMISSION SCHEDULING, SYSTEM CONTROL

AND DISPATCH SERVICE

The NU Companies' formula requirements for Network Transmission Scheduling, System Control and Dispatch Service is determined from the following formula.

Formula Requirements = (Ai-1 - Bi-1 )

WHERE:

•

i equals the calendar year during which service is being rendered ("Service Year").

•

Ai-1 is the Annual Control Center Expenses (expressed in dollars) of the NU Companies for the calendar year prior to the Service Year. The Annual Control Center Expenses are determined pursuant to the formula specified in Exhibit 1 to this Appendix B of Schedule NU-1.

•

Bi-1 is the actual transmission scheduling, system control and dispatch revenues (expressed in dollars) provided from the provision of transmission services to others.  The actual transmission scheduling, system control and dispatch revenues shall be those recorded on the books of the NU Companies in FERC Account No. 456 pertaining to Transmission of Electricity for Others and such other applicable FERC Account for the calendar year prior to the Service Year.

SCHEDULE NU-1

Appendix B

Exhibit 1

DETERMINATION OF ANNUAL CONTROL CENTER EXPENSES

The rate formula for determination of the annual control center expenses for each of the NU Companies is determined as follows:

A.

ANNUAL CONTROL CENTER EXPENSES = The NU Companies' System Control and Load Dispatching Expense), for the calendar year prior to the Service Year as recorded in FERC Account 561.

SCHEDULE NU-1

Appendix C

DETERMINATION OF

THE NU COMPANIES' FORMULA RATE

FOR GENERATION SCHEDULING, SYSTEM CONTROL AND DISPATCH SERVICE

The NU Companies' Formula Rate for Generation Scheduling, System Control and Dispatch Service ("Formula Rate") shall be calculated using the Point-to-Point Formula Rate for Transmission Scheduling, System Control, and Dispatch Service in Appendix A of Schedule NU-1.

SCHEDULE NU-2

Firm Point-To-Point Transmission Service

Charge Provisions

I.

Each month, NUSCO shall bill the Transmission Customer for Long-Term Firm and Short-Term Firm Transmission Service and the Transmission Customer shall be obligated to pay the NU Companies the charges as set forth in this Schedule NU-2, as applicable.

A.

TRANSMISSION CHARGES

1.

Determination of Transmission Charges

The Transmission Charges will provide for recovery of the costs of the transmission facilities of the NU Companies. There are two sets of Transmission Charges, the Category A Transmission Charges and the Category B Transmission Charges. The Category A Transmission Charges for each month will equal the sum of the Category A Charges for each monthly (or longer term), weekly or daily transaction during such month, and the Category B Transmission Charges for each month will equal the sum of the Category B Charges for each monthly (or longer term), weekly or daily transaction during such month.

The Category A Charge for each monthly (or longer term) transactions will be the product of: (a) the NU Companies' Category A Formula Rate (expressed in $ per kilowatt-year), divided by twelve (12) months, and (b) the Reserved Capacity set forth for such monthly (or longer term) transaction (expressed in kilowatts).

The Category A Charge for each weekly transaction will be the product of: (a) the NU Companies' Weekly Category A Short-Term Firm Point- To-Point Transmission Rate (expressed in $ per kilowatt-week), and (b) the Reserved Capacity set forth for such weekly transaction (expressed in kilowatts). The NU Companies' Weekly Category A Rate is the NU Companies' Category A Formula Rate for Firm Point-To-Point Transmission Service divided by fifty-two (52) weeks.  The Category A Charge for each daily transaction will be the product of: (a) the NU Companies' Daily Category A Short-Term Firm Point-To-Point Transmission Rate (expressed in $ per kilowatt-day), and (b) the Reserved Capacity set forth for such daily transaction (expressed in kilowatts). The NU Companies' Daily Category A Rate is the NU Companies' Weekly Category A Rate for Short-Term Firm Point-To-Point Transmission Service divided by five (5) days. The total of the Transmissio n Customer’s charges for daily transactions, under an individual reservation, in a seven (7) day period shall not exceed the charges based on the Weekly Category A Rate and the Transmission Customer’s maximum Reserved Capacity in the period.

The Category B Charge for each monthly (or longer term) transaction in a state or area in which Localized Facilities are located will be the product of: (a) the NU Companies' Category B Formula Rate (expressed in $ per kilowatt-year) for such state or area, divided by twelve (12) months, and (b) the Reserved Capacity set forth for such monthly (or longer term)  transaction (expressed in kilowatts).

The Category B Charge for each weekly transaction in a state or area in which Localized Facilities are located will be the product of: (a) the NU Companies' Weekly Category B Short-Term Firm Point-To-Point Transmission Rate (expressed in $ per kilowatt-week) for such state or area, and (b) the Reserved Capacity set forth for such weekly transaction (expressed in kilowatts). The NU Companies' Weekly Category B Rate is the NU Companies' Category B Formula Rate for Firm Point-To-Point Transmission Service divided by fifty-two (52) weeks.

The Category B Charge for each daily transaction in a state or area in which Localized Facilities are located will be the product of: (a) the NU Companies' Daily Category B Short-Term Firm Point-To-Point Transmission Rate (expressed in $ per kilowatt-day), and (b) the Reserved Capacity set forth for such daily transaction (expressed in kilowatts). The NU Companies' Daily Category B Rate is the NU Companies' Weekly Category B Rate for Short-Term Firm Point-To-Point Transmission Service divided by five (5) days. The total of the Transmission Customer’s charges for daily transactions, under an individual reservation, in a seven (7) day period shall not exceed the charges based on the Weekly Category B Rate and the Transmission Customer’s maximum Reserved Capacity in the

period.

2.

NU Companies’ Formula Rates

The NU Companies' Formula Rates for Long-Term Firm and Short-Term Firm Point-To-Point Service shall be determined in accordance with the rate formulas specified in Appendices A and B of this Schedule NU-2.

3.

Tax Rates and Taxes

The NU Companies’ Formula Rates set forth in this schedule in effect during a Service Year shall be based on the local, state, and federal tax rates and taxes in effect during the Service Year. If, at any time, additional or new taxes are imposed on the NU Companies or existing taxes are removed, the NU Companies’ Formula Rate will be appropriately modified and filed with the Commission in accordance with Part 35 of the Commission's regulations.

4.

Provision re: Exchanges

With respect to Entitlement Transactions or Energy Transactions or other transactions that involve an exchange, each party to such transaction shall be treated as an individual Transmission Customer under this Local Service Schedule. Accordingly, a separate Schedule NU-2 or other applicable charge(s) will be calculated for, and a separate bill will be rendered to, each such individual Transmission Customer.

5.

Discounts

Three principal requirements apply to discounts for transmission service as follows: (1) any offer of a discount made by the NU Companies 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 NU Companies 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 Transmission System.

II.

In addition to the applicable charges set forth in Parts I and II of this Local Service Schedule, and as otherwise specified in the Service Agreement, the Transmission Customer shall pay to NUSCO each month the following additional charges for Long-Term, and Short-Term Firm Point-To-Point Transmission Service provided during such month.

A.

Taxes and Fees Charge

B.

Regulatory Expenses Charge

C.

Other

A.

TAXES AND FEES CHARGE

If any governmental authority requires the payment of any fee or assessment or imposes any form of tax with respect to payments made for Long-Term Firm or Short Term Firm Point-To-Point Transmission Service provided under this Local Service Schedule, not specifically provided for in any of the charge or rate provisions under this Local Service Schedule, including any applicable interest charged on any deficiency assessment made by the taxing authority, together with any further tax on such payments, the obligation to make payment for any such fee, assessment, or tax shall be borne by the Transmission Customer. The NU Companies will make a separate filing with the Commission for recovery of any such costs in accordance with Part 35 of the Commission's regulations.

B.

REGULATORY EXPENSES CHARGE

The NU Companies shall have the right to make a Section 205 filing for recovery of regulatory expenses associated with this Local Service Schedule and the Service Agreements.

C.

OTHER

The NU Companies shall have the right, at any time, unilaterally to file for a change in any of the provisions of this Schedule NU-2 in accordance with Section 205 of the Federal Power Act and the Commission's implementing regulations.

SCHEDULE NU-2

Appendix A

DETERMINATION of

THE NU COMPANIES’ CATEGORY A FORMULA RATE

FIRM POINT-TO-POINT TRANSMISSION SERVICE

The NU Companies' Category A Formula Rate for Long-Term Firm and Short-Term Firm Point-To-Point Transmission Service ("Formula Rate") is an annual rate determined from the following formula.

Formula Ratei = (Ai - Bi + Ci - Di) / Ei

WHERE:

•

i equals the Service Year.

•

A is the annual Total Transmission Revenue Requirements (expressed in dollars) as described in Attachment NU-H,

•

B is the revenues received (expressed in dollars) from the provision of transmission and other related services, to others as recorded in FERC Accounts 456 and 454 to the extent that such transactions are not included in the determination of load (E), <FN2> minus any incremental revenues associated with FERC-approved adders for RTO participation and new transmission investment.

•

C is the transmission payments (expressed in dollars) to the New England System Operator as recorded in FERC Account 565 in accordance with the Tariff.  • D is the sum of the annual revenues received (expressed in dollars) for the costs associated with the Localized Facilities.

•

E is the average NU Companies’ Monthly Transmission System Category A Load (expressed in kilowatts).

SCHEDULE NU-2

Appendix B

DETERMINATION of

THE NU COMPANIES' CATEGORY B FORMULA RATE

FIRM POINT-TO-POINT TRANSMISSION SERVICE

The NU Companies' Category B Formula Rate for Long-Term Firm and Short-Term Firm Point- To-Point Transmission Service ("Formula Rate") is an annual rate determined from the following formula and separately determined for each state or area in which Localized Facilities are located:

Formula Ratei = (Di / Ei)

WHERE:

•

i equals the Service Year.

•

D is the annual Localized Transmission Revenue Requirements (expressed in dollars) of the Localized Facilities of the NU Companies for a state or area in which Localized Facilities are located, as described in Attachment NU-I.

•

E is the average Monthly Transmission System Category B Load (expressed in kilowatts) for the state or area for which the Revenue Requirements in D are calculated.

SCHEDULE NU-3

Non-Firm Point-To-Point Transmission Services

I.

The NU Companies shall bill the Transmission Customer for Non-Firm Point-To-Point Transmission Service, and the Transmission Customer shall be obligated to pay the NU Companies the charges as set forth in this Schedule NU-3 as applicable.

A.

TRANSMISSION CHARGES

1.

General

There are two sets of Transmission Charges, the Category A Transmission Charges and the Category B Transmission Charges. The Transmission Customer shall pay to NUSCO each month the sum of the Category A Transmission Charges and Category B Transmission Charges calculated for all of the Transmission Customer’s monthly transactions, weekly transactions, daily transactions and hourly transactions, each as set forth below.

With respect to any wholesale transactions that involve an exchange, each party to such transaction shall be an individual Transmission Customer under this Local Service Schedule. Accordingly, a Transmission Charge, as applicable, will be calculated for, and a separate bill will be rendered to, each such Transmission Customer.

The Category A Transmission Charge for each month applicable to a monthly transaction shall be determined as the product of: (a) the Category A rate posted on NU's Open Access Same-Time Information System ("OASIS") at the time the service is reserved, not to exceed the NU Companies' Annual Category A Rate for Non-Firm Point-To-Point Transmission Service divided by twelve (12) months and (b) the Reserved Capacity set forth in the Transmission Customer's applicable Reservation for such month (expressed in kilowatts).

The Category A Transmission Charge for each month applicable to weekly transactions shall be the sum of the transmission charges determined for each weekly transaction during such month. The transmission charge for each weekly transaction shall be determined as the product of: (a) the Category A rate posted on the NU Companies’ OASIS at the time the service is reserved, not to exceed the NU Companies' Weekly Category A Firm Point-To-Point Transmission Charge Rate (expressed in $ per kilowatt-week), and (b) the Reserved Capacity set forth in the Transmission Customer's applicable Reservation for such week (expressed in kilowatts). The NU Companies' Weekly Category A Rate is the NU Companies' Annual Category A Rate for Non-Firm Point-To-Point Transmission Service divided by fifty-two (52) weeks.

The Transmission Charge for each month applicable to daily transactions will be the sum of the transmission charges determined for each daily transaction. The transmission charge for each daily transaction shall be determined as the product of: (a) the rate posted on the NU Companies’ OASIS at the time the service is reserved, not to exceed the NU Companies' Daily Category A Firm Point-To-Point Transmission Charge Rate (expressed in $ per kilowatt-day), and (b) the Reserved Capacity set forth in the Transmission Customer's applicable Reservation for such day (expressed in kilowatts). The NU

Companies' Daily Category A On-Peak Rate is the NU Companies' Weekly Category A Rate for Non-Firm Point-To-Point Transmission Service divided by five (5) days. The NU Companies' Daily Category A Off-Peak Rate is the NU Companies' Weekly Category A Rate for Non-Firm Point-To-Point Transmission Service divided by seven (7) days. The total of the Transmission Customer’s charges for daily transactions, under an individual Reservation, in a seven (7) day period shall not exceed the charges based on the Weekly Category A Rate and the Transmission Customer’s maximum Reserved Capacity in the period.

The Transmission Charge for each month applicable to hourly transactions will be the sum of the transmission charges determined for each hourly transaction during such month. The transmission charge for each hour of an hourly Transaction shall be determined as the product of: (a) the rate posted on the NU Companies’ OASIS at the time the service is reserved, not to exceed the NU Companies' Daily Category A Firm Point-To-Point Transmission Service Rate divided by sixteen (16) hours (expressed in $ per kilowatt-hour), and (b) the Reserved Capacity as set forth in the Transmission Customer's applicable Reservation for such hour (expressed in kilowatts). The NU Companies' Hourly Category A On-Peak Rate is equal to the NU Companies' Daily Category A Rate for Non-Firm Transmission Service divided by sixteen (16) hours. The NU Companies' Hourly Category A Off-Peak Rate is equal to the NU Companies' Daily Category A Rate for Non-Firm Tra nsmission Service divided by twenty-four (24) hours. The total of the Transmission Customer’s charges for hourly transactions, under an individual Reservation, in a twenty-four (24) hour period shall not exceed the charges based on the Daily Category A Rate and the Transmission Customer’s maximum Reserved Capacity in the period.

The Category B Transmission Charge for each month applicable to a monthly transaction in a state or area in which Localized Facilities are located shall be determined as the product of: (a) the Category B rate posted on NU's Open Access Same-Time Information System ("OASIS") for such state or area at the time the service is reserved, not to exceed the NU Companies' Annual Category B Rate for Non-Firm Point-To-Point Transmission Service for such state or area divided by twelve (12) months and (b) the Reserved Capacity set forth in the Transmission Customer's applicable Reservation for such month (expressed in kilowatts).

The Category B Transmission Charge for each month applicable to weekly transactions in a state or area in which Localized Facilities are located shall be the sum of the transmission charges determined for each weekly transaction during such month. The transmission charge for each weekly transaction shall be determined as the product of: (a) the Category B rate posted on the NU Companies’ OASIS for such state or area at the time the service is reserved, not to exceed the NU Companies' Weekly Category B Firm Point-To-Point Transmission Charge Rate (expressed in $ per kilowatt-week) for such state or area, and (b) the Reserved Capacity set forth in the Transmission Customer's applicable Reservation for such week (expressed in kilowatts). The NU Companies' Weekly Category B Rate is the NU Companies' Annual Category B Rate for Non-Firm Point-To-Point Transmission Service divided by fifty-two (52) weeks.

The Transmission Charge for each month applicable to daily transactions in a state or area in which Localized Facilities are located will be the sum of the transmission charges determined for each daily transaction during such month. The transmission charge for each daily transaction shall be determined as the product of: (a) the rate posted on the NU

Companies’ OASIS for such state or area at the time the service is reserved, not to exceed the NU Companies' Daily Category B Firm Point-To-Point Transmission Charge Rate (expressed in $ per kilowatt-day) for such state or area, and (b) the Reserved Capacity set forth in the Transmission Customer's applicable Reservation for such day (expressed in kilowatts).  The NU Companies' Daily Category B On-Peak Rate is the NU Companies' Weekly Category B Rate for Non-Firm Point-To-Point Transmission Service divided by five (5) days. The NU Companies' Daily Category B Off-Peak Rate is the NU Companies' Weekly Category B Rate for Non-Firm Point-To-Point Transmission Service divided by seven (7) days. The total of the Transmission Customer’s charges for daily transactions, under an individual Reservation, in a seven (7) day period shall not exceed the charges based on the Weekly Category B Rate and the Tra nsmission Customer’s maximum Reserved Capacity in the period.

The Transmission Charge for each month applicable to hourly transactions in a state or area in which Localized Facilities are located will be the sum of the transmission charges determined for each hourly transaction during such month. The transmission charge for each hour of an hourly transaction shall be determined as the product of: (a) the rate posted on the NU Companies’ OASIS for such state or area at the time the service is reserved, not to exceed the NU Companies' Daily Category B Firm Point-To-Point Transmission Service Rate divided by sixteen (16) hours (expressed in $ per kilowatt-hour) for such state or area, and (b) the Reserved Capacity as set forth in the Transmission Customer's applicable Reservation for such hour (expressed in kilowatts). The NU Companies' Hourly Category B On-Peak Rate is equal to the NU Companies' Daily Category B Rate for Non-Firm Transmission Service divided by sixteen (16) hours. The NU Comp anies' Hourly Category B Off-Peak Rate is equal to the NU Companies' Daily Category B Rate for Non-Firm Transmission Service divided by twenty four (24) hours. The total of the Transmission Customer’s charges for hourly transactions, under an individual Reservation, in a twenty-four (24) hour period shall not exceed the charges based on the Daily Category B Rate and the Transmission Customer’s maximum Reserved Capacity in the period.

2.

Discounts

Three principal requirements apply to discounts for transmission service as follows: (1) any offer of a discount made by the NU Companies 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 NU Companies 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 Transmission System.

3.

Credit to the Transmission Charge

Whenever service provided hereunder is interrupted or curtailed by the NU Companies, the Local Control Center or the New England System Operator, the Transmission Charges to the Transmission Customer calculated pursuant to Section A, of this Schedule NU-3 shall be credited by an amount equal to the sum of the credits calculated for each hour of interruption or curtailment in service. The credit to the Transmission Customer

for each such hour of interruption or curtailment shall be calculated as the product of (i) the applicable equivalent hourly charge for hourly, daily, weekly, or monthly transactions, and (ii) the kilowatts of service interruption or curtailment during such hour.

4.

NU Companies' Annual Formula Rate for Non-Firm Point-To-Point Transmission Service

The NU Companies' Annual Formula Rates for Non-Firm Point-To-Point Transmission Service shall be expressed in $ per kilowatt-year and shall be determined in accordance with the rate formulas specified in Appendices A and B of this Schedule NU-3 ("Formula Rates”).

5.

Tax Rates and Taxes

The Formula Rates set forth in this Schedule NU-3 in effect during a Service Year shall be based on local, state, and federal tax rates and taxes in effect during the Service Year. If, at any time, additional or new taxes are imposed on the NU Companies or existing taxes are removed, the Formula Rate will be appropriately modified and filed with the Commission in accordance with Part 35 of the Commission's regulations.

II.

In addition to the applicable charges set forth in Parts I and II of this Local Service Schedule, and as otherwise specified in the Service Agreement, the Transmission Customer shall pay NUSCO each month the following additional charges for Non-firm Point-To-Point Transmission Service provided during such month.

A.

Taxes and Fees Charge

B.

Regulatory Expenses Charge

C.

Other

A.

TAXES AND FEES CHARGE

If any governmental authority requires the payment of any fee or assessment or imposes any form of tax with respect to payments made for Non-Firm Point-To-Point Transmission Service provided under this Local Service Schedule, not specifically provided for in any of the charge or rate provisions under this Local Service Schedule, including any applicable interest charged on any deficiency assessment made by the taxing authority, together with any further tax on such payments, the obligation to make payment for such fee, assessment, or tax shall be borne by the Transmission Customer. The NU Companies will make a separate filing with the Commission for recovery of any such costs in accordance with Part 35 of the Commission's regulations.

B.

REGULATORY EXPENSES

The NU Companies reserve their rights to make a Section 205 filing for recovery of their costs to administer this Local Service Schedule and the Service Agreements.

C.

OTHER

The NU Companies shall have the right, at any time, unilaterally to file for a change in any of the provisions of this Schedule NU-3 in accordance with Section 205 of the Federal Power Act and the Commission's implementing regulations.

SCHEDULE NU-3

Appendix A

DETERMINATION OF

THE NU COMPANIES' CATEGORY A FORMULA RATE

FOR NON-FIRM POINT-TO-POINT TRANSMISSION SERVICE

The NU Companies' Category A Formula Rate for Non-Firm Point-To-Point Transmission Service ("Formula Rate") is an annual rate determined from the following formula.

Formula Ratei = (Ai - Bi + Ci - Di) / Ei

WHERE:

•

i equals the Service Year.

•

A is the annual Total Transmission Revenue Requirements (expressed in dollars) as described in Attachment NU-H.

•

B is the revenues received (expressed in dollars) from the provision of transmission and other related services to others as recorded in FERC Accounts 456 and 454 to the extent that such transactions are not included in the determination of load (E), <FN3> minus any incremental revenues associated with FERC-approved adders for RTO participation and new transmission investment.

•

C is the transmission payments (expressed in dollars) to the New England System Operator as recorded in FERC Account 565 in accordance with the Tariff.

•

D is the sum of the annual revenues received (expressed in dollars) for the costs associated with the Localized Facilities.

•

E is the average NU Companies’ Monthly Transmission System Category A Load (expressed in kilowatts).

SCHEDULE NU-3

Appendix B

DETERMINATION OF

THE NU COMPANIES' CATEGORY B FORMULA RATE

FOR NON-FIRM POINT-TO-POINT TRANSMISSION SERVICE

The NU Companies' Category B Formula Rate for Non-Firm Point-To-Point Transmission Service ("Formula Rate") is an annual rate determined from the following formula, and separately determined for each state or area in which Localized Facilities are located.

Formula Ratei = (Di / Ei)

WHERE:

•

i equals the Service Year.

•

D is the annual Localized Transmission Revenue Requirements (expressed in dollars) of the Localized Facilities of the NU Companies for a state or area in which Localized Facilities are located, as described in Attachment NU-I.

•

E is the average Monthly Transmission System Category B Load (expressed in kilowatts) for the state or area for which the Revenue Requirements in D are calculated.

SCHEDULE NU-4

Charge Provisions For Network Integration Transmission Service

I.

Network Customers will pay the following demand charges for Network Integration Transmission Service.

A.

DEMAND CHARGE A

1.

Determination of Demand Charge:

The Demand Charge will be determined in accordance with Section 34.3 of this Local Service Schedule.

2.

NU Companies’ Annual Transmission Revenue Requirements:

The annual Transmission Revenue Requirements shall be determined in accordance with the formula specified in Appendix A of this Schedule NU-4 (“Formula Requirements”).

B.

DEMAND CHARGE B

1.

Determination of Demand Charge:

The Demand Charge will be determined in accordance with Section 34.3 of this Local Service Schedule.

2.

NU Companies' Annual Transmission Revenue Requirements:

The annual Transmission Revenue Requirements for a state or area in which Localized Facilities are located shall be determined in accordance with the formula specified in Appendix B of this Schedule NU-4 ("Formula Requirements”).

C.

TAX RATES AND TAXES

The Formula Requirements set forth in this Schedule NU-4 in effect during a Service Year shall be based on local, state, and federal tax rates and taxes in effect during the Service Year. If, at any time, additional or new taxes are imposed on the NU Companies or existing taxes are removed, the Formula Requirements will be appropriately modified and filed with the Commission in accordance with Part 35 of the Commission's regulations.

II.

In addition to the applicable charges set forth in Parts I and III of this Local Service Schedule, and as otherwise specified in the Service Agreement, the Transmission Customer shall pay to NUSCO each month the following additional charges for Network Integration Transmission Service provided during such month.

A.

Taxes and Fees Charge

B.

Regulatory Expenses Charge

C.

Other

A.

TAXES AND FEES CHARGE

If any governmental authority requires the payment of any fee or assessment or imposes any form of tax with respect to payments made for service provided under this Local Service Schedule, not specifically provided for in any of the charge or rate provisions under this Local Service Schedule, including any applicable interest charged on any deficiency assessment by the taxing authority, together with any further tax on such payments, the obligation to make payment for any such fee, assessment, or tax shall be borne by the Transmission Customer. The NU Companies will make a separate filing with the Commission for recovery of any such costs in accordance with Part 35 of the Commission's regulations.

B.

REGULATORY EXPENSES CHARGE

The NU Companies shall have the right to make a Section 205 filing for recovery of regulatory expenses associated with this Local Service Schedule and the Service Agreements.

C.

OTHER

The NU Companies shall have the right, at any time, unilaterally to file for a change in any of the provisions of this Schedule NU-4 in accordance with Section 205 of the Federal Power Act and the Commission's implementing regulations.

SCHEDULE NU-4

Appendix A

DETERMINATION OF

THE NU COMPANIES’ NETWORK

FORMULA REQUIREMENTS

FOR TRANSMISSION SERVICE

CATEGORY A COSTS

The NU Companies' formula requirements for Network Integration Transmission Service is determined from the following formula.

Formula Requirementsi = Ai – Bi + Ci - Di

WHERE:

•

i equals the Service Year.

•

A is the annual Total Transmission Revenue Requirements (expressed in dollars) as described in Attachment NU-H.

•

B is the revenues received (expressed in dollars) from the provision of transmission and other related services to others as recorded in FERC Accounts 456 and 454 to the extent that such transactions are not included in the determination of load, <FN4>  minus any incremental revenues associated with FERC-approved adders for RTO participation and new transmission investment.

•

C is the transmission payments to (expressed in dollars) the New England System Operator as recorded in FERC Accounts 565 in accordance with the Tariff. • D is the sum of the annual revenues received (expressed in dollars) for the costs associated with Localized Facilities.

SCHEDULE NU-4

Appendix B

DETERMINATION OF

THE NU COMPANIES’ NETWORK

FORMULA REQUIREMENTS

FOR TRANSMISSION SERVICE

CATEGORY B COSTS

The NU Companies' formula requirements for Network Integration Transmission Service and for Eligible Customers taking Regional Network Service under this Tariff in a state or area in which Localized Facilities are located, is determined from the following formula, and separately determined for each state or area in which Localized Facilities are located.

Formula Requirementsi = Di

WHERE:

•

i equals the Service Year.

•

D is the annual Localized Transmission Revenue Requirements (expressed in dollars) of the Localized Facilities of the NU Companies for a state or area in which Localized Facilities are located, as described in Attachment NU-I.

ATTACHMENT NU-E

Service Agreement For Eligible Customers Taking Service

Under the Tariff

This Service Agreement, dated as of , is entered into by and between the Northeast Utilities Service Company ("NUSCO" or "COMPANY"), acting as agent for The Connecticut Light and Power Company, Western Massachusetts Electric Company, Holyoke Water Power Company, Holyoke Power and Electric Company, Public Service Company of New Hampshire and("Transmission Customer").

The Transmission Customer is ________________________________and has been determined by NUSCO to be an Eligible Customer taking Regional Network Service under the Tariff who is located in the state or area in which Localized Facilities have been identified under Section 34.2 of this Schedule on file with, and as may be revised from time to time in accordance with the rules of the Federal Energy Regulatory Commission. The Transmission Customer agrees to pay its portion of the cost of Localized Facilities as provided in the Tariff. Service under this agreement shall commence on the later of: (1) 0001 hours on _____________________, or (2) such other date as it is permitted to become effective by the Commission. Service under this agreement shall terminate on 2400 hours on ______________________.

Other special provisions (if any)

___________________________________________________________.

Any notice or request made to or by any Party regarding this Service Agreement shall be made in writing and shall be telecommunicated or delivered either in person, or by prepaid mail (return receipt requested) to the representative of the other Party as indicated below. Such representative and address for notices or requests may be changed from time to time by notice by one Party to the other.

COMPANY:

_________________________________________

_________________________________________

_________________________________________

TRANSMISSION CUSTOMER:

_________________________________________

_________________________________________

_________________________________________

Any exhibits to this Service Agreement and the Tariff are incorporated herein and made a part hereof. This Service Agreement may be amended, from time to time, as provided in Section 9 of Schedule 21-NU of the OATT.

IN WITNESS WHEREOF, the Parties have caused this Service Agreement to be executed by their respective authorized officials as of the date first above written.

NORTHEAST UTILITIES SERVICE COMPANY

By:

              Its Vice President

TRANSMISSION CUSTOMER

ATTACHMENT NU-GA

Network Operating Agreement

This Network Operating Agreement is an appendix to Schedule 21-NU (this Local Service Schedule) of the OATT and operates as an implementing agreement for Network Integration Transmission Service under this Local Service Schedule. This Network Operating Agreement is subject to and in accordance with Part III of this Local Service Schedule. All definitions and other terms and conditions of this Local Service Schedule are incorporated herein by reference.

1.0

Definitions:

1.1

Data Acquisition Equipment: Supervisory control and data acquisition ("SCADA"), remote terminal units ("RTUs") to obtain information from a Party's facilities, telephone equipment, leased telephone circuits, fiber optic circuits, and other communications equipment necessary to transmit data to remote locations, and any other equipment or service necessary to provide for the telemetry and control requirements of this Local Service Schedule.

1.2

Data Link: The direct communications link between the Transmission Customer's energy control center and the NU Companies' designated location(s) that will enable the NU Companies to receive real time telemetry and data from the Transmission Customer.

1.3

Metering Equipment: High accuracy, solid state kW, kVAR, kWh meters, metering cabinets, metering panels, conduits, cabling, high accuracy current transformers and high accuracy potential transformers, which directly or indirectly provide input to meters or transducers, metering recording devices, telephone circuits, signal or pulse dividers, transducers, pulse accumulators, metering sockets, test switch devices, enclosures, conduits, and any other metering, telemetering or communication equipment necessary to implement the provisions of this Local Service Schedule.

1.4

Protective Equipment: Protective relays, relaying panels, relaying cabinets, circuit breakers, conduits, cabling, current transformers, potential transformers, coupling capacitor voltage transformers, wave traps, transfer trip and fault recorders, which directly or indirectly provide input to relays, fiber optic communication equipment, power line carrier equipment and telephone circuits, and any other protective equipment necessary to implement the protection provision of this Local Service Schedule.

2.0

Term:

The term shall be as provided in the Service Agreement consistent with Section 29 of this Local Service Schedule(including, but not limited to, application procedures, commencement of service, and effect of termination).

3.0

Point(s) Of Interconnection:

Network Integration Transmission Service will be provided by the NU Companies at the point(s) of interconnection specified in Appendix __, as amended from time to time. Each point of interconnection in this listing shall have a unique identifier, meter location, meter number, metered voltage, terms on meter compensation and designation of current or future year of in service.

4.0

Cogeneration And Small Power Production Facilities:

If a Qualifying Facility is located or locates in the future on the System of the Transmission Customer, and the owner or operator of such Qualifying Facility sells the output of such Qualifying Facility to an entity other than the Transmission Customer, the delivery of such Qualifying Facility's power shall be subject to and contingent upon transmission arrangements being established with the NU Companies prior to commencement of delivery of any such power and energy.

5.0

Character Of Service: Network Transmission Service at the points of interconnection shall be in the form of single phase or balanced three-phase alternating current at a frequency of sixty (60) hertz. The Transmission Customer shall operate and maintain its electric system in a manner that avoids: (i) the generation of harmonic frequencies exceeding the limits established by the latest revision of IEEE-519; (ii) voltage flicker exceeding the limits established by the latest revision of IEEE-141; (iii) negative sequence currents; (iv) voltage or current fluctuations; (v) frequency variations; or (vi) voltage or power factor levels that could adversely affect the NU Companies' electrical equipment or facilities or those of its customers, and in a manner that complies with all applicable NERC, NPCC, ISO and the NU Companies', operating criteria, rules, regulations, procedures, guidelines and interconnection standards as amended fr om time to time.

6.0

Continuity Of Service: (a) The NU Companies and the Transmission Customer shall operate and maintain their respective network systems, in accordance with Good Utility Practice, and in a manner that will allow the NU Companies to safely and reliably operate the NU Transmission System in accordance with this Local Service Schedule, so that either Party shall not unduly burden the other Party; provided, however, that notwithstanding any other provision of this Local Service Schedule, the NU Companies shall retain the sole responsibility and authority for all operating decisions that could affect the integrity, reliability and security of the NU Transmission System.

(b) The NU Companies shall exercise reasonable care and Due Diligence to ensure Network Integration Transmission Service hereunder in accordance with Good Utility Practice; provided, however, that the NU Companies shall not be responsible for any failure to ensure electric power service, nor for interruption, reversal or abnormal voltage of the service, if such failure, interruption, reversal or abnormal voltage is due to a Force Majeure.

7.0

Power Factor:

(a) Where Network Integration Transmission Service provided under this Local Service Schedule is for delivery of power to a load center of the Transmission Customer served from the NU Companies’ Transmission System, the Transmission Customer shall maintain load power factor levels, during both on- and off- peak hours, appropriate to meet the operating requirements of the NU Companies, and shall follow the ISO standards and practices, as set forth in the Service Agreement.

(b) Where Network Integration Transmission Service provided under this Local Service Schedule is for delivery of power from a generating facility connected to the NU Companies’ Transmission System, the Transmission Customer shall deliver power at a lagging or leading power factor as set forth in the Service Agreement.

(c) Where Network Integration Transmission Service provided under this Local Service Schedule is for delivery of power from outside the NU Companies’ Transmission System, the obligation to

maintain proper sending and receiving end voltages rests with the Transmission Customer, as set forth in the Service Agreement.

(d) In the event that the power factor levels and reactive supply requirements set forth in the Service Agreement are not maintained by the Transmission Customer, the NU Companies shall thereupon have the right to take the appropriate corrective action and to charge the Transmission Customer for the costs thereof. The NU Companies shall have the right, at any time, unilaterally to make a Section 205 filing with the Commission for the recovery of any such costs.

8.0

Metering:

(a) The Transmission Customer shall, at its expense, purchase all necessary metering equipment to accurately account for the electric power being transmitted under this Local Service Schedule. The NU Companies may require the installation of telemetering equipment for the purposes of billing, power factor measurements and to allow the NU Companies to maximize economic and reliable operation of their transmission system.  Such metering equipment shall meet the specifications and accepted metering practices of the NU Companies and applicable criteria, rules, standards and operating procedures, or such successor rules and standards. At the NU Companies' option, communication metering equipment may be installed in order to transmit meter readings to the NU Companies' designated locations.

(b) Electric power being transmitted under this Local Service Schedule will be measured by meters at all points of interconnection and/or on generating facilities (Network and non-Network Resources) located on and outside the Transmission Customer's system as required by the NU Companies.

(c) The Transmission Customer shall purchase meters capable of time-differentiated (by hour) measurement of the instantaneous flow in kW and net active power flow in kWh and of reactive power flow. All meters shall compensate for applicable line and/or transformer losses in accordance with Good Utility Practice when measurement is made at any location other than the point of interconnection.

(d) The NU Companies reserve the right: (i) to determine metering equipment ownership; (ii) to determine the equipment installation at each point of interconnection; (iii) to require the Transmission Customer to install the equipment -- or -- install the equipment with the Transmission Customer supplying without cost to the NU Companies a suitable place for the installation of such equipment; (iv) to determine other equipment allowed in the metering circuit; (v) to determine metering accuracy requirements; (vi) to determine the responsibilities for operation, maintenance, testing and repair of metering equipment.

(e) The NU Companies shall have access to metering data, including telephone line access, which may reasonably be required to facilitate measurement and billing under this Local Service Schedule. The NU Companies may require the Transmission Customer provide, at its expense, a separate dedicated voice grade telephone circuit for the NU Companies and the Transmission Customer to remotely access each meter. Metering equipment and data shall be accessible at all reasonable hours for purposes of inspection and reading.

(f) All metering equipment shall be tested in accordance with practices of the NU Companies, applicable criteria, rules, standards and operating procedures or upon the request by the NU Companies. If at any time metering equipment fails to register or is determined to be inaccurate, in accordance with the NU Companies' practices and applicable criteria, rules, standards and

operating procedures, the Transmission Customer shall make the equipment accurate as soon thereafter as practicable, and the meter readings and rate computation for the period of such inaccuracy, insofar as can reasonably be ascertained, shall be adjusted; provided, however, that no adjustment to charges shall be required for any period exceeding two (2) months prior to the date of the test.  Representatives of the NU Companies will be afforded opportunity to witness such tests.

9.0

Network Load: The Transmission Customer shall provide the NU Companies with the actual hourly Network Load for each calendar month by the seventh day of the following calendar month.

10.0

Data Transfer:

(a) The Transmission Customer shall provide timely, accurate real time information to the NU Companies in order to facilitate performance of its obligations under this Local Service Schedule.

(b) The selection of real time telemetry and data to be received by the NU Companies and the Transmission Customer shall be necessary for safety, reliability, security, economics, and/or monitoring of real-time conditions that affect the NU Transmission System. This telemetry shall include, but is not limited to, loads, line flows (MW and MVAR), voltages, generator output, and status of substation equipment at any of the Transmission Customer's transmission and generation facilities. To the extent that the NU Companies or the Transmission Customer requires data that are not available from existing equipment, the Transmission Customer shall, at its expense and at locations designated by the NU Companies or the Transmission Customer, install any metering equipment, data acquisition equipment, or other equipment and software necessary for the telemetry to be received by the NU Companies or the Transmission Customer. The NU Companies shal l have the right to inspect equipment and software associated with the data transfer in order to assure conformance with Good Utility Practices.

11.0

Maintenance of Equipment:

The Transmission Customer shall, on a regular basis in accordance with Network Operating Committee procedures, practices of the NU Companies, applicable criteria, rules, standards and operating procedures or at the request of the NU Companies, and at its expense, test, calibrate, verify and validate the data link, metering equipment, data acquisition equipment, transmission equipment, protective equipment and other equipment or software used to implement the provisions of this Local Service Schedule.  The NU Companies shall have the right to inspect such tests, calibrations, verifications and validations of the data link, metering equipment, data acquisition equipment, transmission equipment, protective equipment and other equipment or software used to implement the provisions of this Local Service Schedule. Upon The NU Companies' request, the Transmission Customer will provide the NU System Companies a copy of the installation, test and calibration records of the data link, metering equipment, data acquisition equipment, transmission equipment, protective equipment and other equipment or software. The NU Companies shall, at the Transmission Customer's expense, have the right to monitor the factory acceptance test, the field acceptance test, and the installation of any metering equipment, data acquisition equipment, transmission equipment, protective equipment and other equipment or software used to implement the provisions of this Local Service Schedule.

12.0

Notification:

(a) The Transmission Customer shall notify and coordinate with the NU Companies prior to the commencement of any work or maintenance by the Transmission Customer, Network Member, or contractors or agents performing on behalf of either or both, which may directly or indirectly

have an adverse effect on the Transmission Customer or The NU Companies' data link, or the reliability of the NU Transmission System. All notifications for scheduled outages of the data link, metering equipment, data acquisition equipment, transmission equipment, protective equipment and other equipment or software must meet the requirements of the ISO and the NU Companies.

13.0

Emergency System Operations:

(a) The Transmission Customer, at its expense, shall be subject to all applicable emergency operation standards promulgated by NERC, NPCC, ISO and the NU Companies which may include but not limited to underfrequency relaying equipment, load shedding equipment and voltage reduction equipment.

(b) The NU Companies reserve the right to take whatever actions they deem necessary to preserve the integrity of the NU Companies’ Transmission System during emergency operating conditions. If the Network Integration Transmission Service at the points of interconnection is causing harmful physical effects to the NU Transmission System facilities or to its customers (e.g., harmonics, undervoltage, overvoltage, flicker, voltage variations, etc.), the NU Companies shall promptly notify the Transmission Customer and if the Transmission Customer does not take the appropriate corrective actions immediately, the NU Companies shall have the right to interrupt Network Integration Transmission Service under this Local Service Schedule in order to alleviate the situation and to suspend all or any portion of Network Integration Transmission Service under this Local Service Schedule until appropriate corrective action is taken.

(c) In the event of any adverse condition or disturbance on the NU Transmission System or on any other system directly or indirectly interconnected with the NU Transmission System, the NU Companies may, as they deem necessary, take actions or inactions that, in the NU Companies' sole judgment, result in the automatic or manual interruption of Network Integration Transmission Service in order to: (i) limit the extent or damage of the adverse condition or disturbance; (ii) prevent damage to generating or transmission facilities; (iii) expedite restoration of service; or (iv) preserve public safety.

14.0

Cost Responsibility:

(a) The Transmission Customer shall be responsible for the costs incurred by the Transmission Customer and the NU Companies to implement the provisions of this Local Service Schedule including, but not limited to, engineering, administrative and general expenses, material and labor expenses associated with the specifications, design, review, approval, purchase, installation, maintenance, modification, repair, operation, replacement, checkouts, testing, upgrading, calibration, removal, and relocation of equipment, or software.

(b) Additionally, the Transmission Customer shall be responsible for all costs incurred by the Transmission Customer and the NU Companies for on-going operation and maintenance of the metering, telecommunications and safety protection facilities and equipment required to implement the provisions of this Local Service Schedule. Such work shall include, but not limited to, normal and extraordinary engineering, administrative and general expenses, material, and labor expenses associated with the specifications, design, review, approval, purchase, installation, maintenance, modification, repair, operation, replacement, checkouts, testing, upgrading, calibration, removal, or relocation of equipment required to accommodate service under this Local Service Schedule.

15.0

Default:

The Transmission Customer's failure to implement the terms and conditions of this Network Operating Agreement will be deemed to be a default under this Local Service Schedule and will result in the NU Companies seeking, consistent with FERC rules and regulations, immediate termination of service under this Local Service Schedule.

16.0

Regulatory Filings:

Nothing contained in this Local Service Schedule or any associated Service Agreement, including this Network Operating Agreement, shall be construed as affecting in any way the right of the NU Companies to unilaterally make application to the Commission for a change in any portion of this Network Operating Agreement under Section 205 of the Federal Power Act and pursuant to the Commission's rules and regulations promulgated thereunder.

IN WITNESS WHEREOF, the Parties have caused this Network Operating Agreement to be executed by their respective authorized officials as of the date written.

Date: __________

Northeast Utilities Service Company

by: ______________________________

its Vice President

Transmission Customer

by: ______________________________

its ______________________________

ATTACHMENT NU-H

Annual Transmission Revenue Requirements

for Transmission Service

Attachment NU-H Methodology:

This formula sets forth the method that the NU Companies’ will use to determine their annual Total Transmission Revenue Requirements. The Transmission Revenue Requirements reflect the NU Companies’ total cost to own, operate and maintain the transmission facilities used for providing Open Access Transmission Service to transmission customers under this Local Service Schedule. The Transmission Revenue Requirements will be an annual formula rate calculation, effective for an initial term commencing on the effective date established by FERC and ending on May 31 of the following year. The calculation will be based on the previous calendar year’s FERC Form 1 data, with an estimate of the NU Companies’ current year average plant additions.  Plant additions will be multiplied by a fixed charge carrying cost and updated thereafter each June 1 based on actual costs from the Service Year. The true-up information will be based on actual da ta, in lieu of allocated data if specifically identified in the FERC Form 1.

I.

Definitions

Capitalized terms not otherwise defined in the Tariff and as used in this formula have the following definitions:

A. Allocation Factors

1.

Transmission Wages and Salaries Allocation Factor shall equal the ratio of the NU Companies’ Transmission-related direct wages and salaries to the NU Companies’ total direct wages and salaries excluding administrative and general wages and salaries.

2.

Plant Allocation Factor shall equal the ratio of the sum of total investment in Transmission Plant and Transmission Related General Plant to Total Plant in Service.

B.

Terms

Administrative and General Expense shall equal The NU Companies’ expenses as recorded in FERC Account Nos. 920-935, excluding FERC Account Nos. 924,928 and 930.1.

Amortization of Loss on Reacquired Debt shall equal the NU Companies’ expenses as recorded in FERC Account No. 428.1.

Amortization of Investment Tax Credits shall equal the NU Companies’ credits as recorded in FERC Account No. 411.4.

Depreciation Expense for Transmission Plant shall equal The NU Companies’ transmission expense as recorded in FERC Account No. 403.

General Plant shall equal The NU Companies’ gross plant balance as recorded in FERC Account Nos. 389-399.

General Plant Depreciation Expense shall equal the NU Companies’ general plant expenses as recorded in FERC Account No. 403.

General Plant Depreciation Reserve shall equal the NU Companies’ general plant reserve balance as recorded in FERC Account No. 108.

Other Regulatory Assets/Liabilities – FAS 106 shall equal the net of the NU Companies’ FAS 106 balance as recorded in FERC Account No. 182.3 and any FAS 106 balance as recorded in the NU Companies’ FERC Account No. 254.

Other Regulatory Assets/Liabilities – FAS 109 shall equal the net of the NU Companies’ FAS 109 balance in FERC Account No. 182.3 and any FAS 109 balance as recorded in the NU Companies’ FERC Account No. 254.

Payroll Taxes shall equal those payroll expenses as recorded in the NU Companies’ FERC Account Nos. 408.1 and 409.1.

Plant Held for Future Use shall equal the NU Companies’ balance in FERC Account No. 105.

Prepayments shall equal the NU Companies’ prepayment balance as recorded in FERC Account No. 165.

Property Insurance shall equal the NU Companies’ expenses as recorded in FERC Account No. 924.

Total Accumulated Deferred Income Taxes shall equal the net of the NU Companies’ deferred tax balance as recorded in FERC Account Nos. 281-283 and the NU Companies’ deferred tax balance as recorded in FERC Account No. 190.

Total Loss on Reacquired Debt shall equal the NU Companies’ expenses as recorded in FERC Account 189.

Total Municipal Tax Expense shall equal the NU Companies’ expenses as recorded in FERC Account Nos. 408.1, 409.1.

Total Plant in Service shall equal the NU Companies’ total gross plant balance as recorded in FERC Account Nos. 301-399.

Total Transmission Depreciation Reserve shall equal the NU Companies’ Transmission reserve balance as recorded in FERC Account 108.

Transmission Operation and Maintenance Expense shall equal the NU Companies’ expenses as recorded in FERC Account Nos. 560, 562-564 and 566- 573 and shall exclude all HQ HVDC expenses booked to accounts 560 through 573 and expenses already included in Transmission Support Expense, as described in Section I below, that are included in FERC Account Nos. 560-573.

Transmission Plant shall equal the NU Companies’ gross plant balance as recorded in FERC Account Nos. 350-359.

Transmission Plant Materials and Supplies shall equal the NU Companies’ balance as assigned to transmission, as recorded in FERC Account 154.

II.

Calculation of Transmission Revenue Requirements

The Transmission Revenue Requirement shall equal the sum of the NU Companies’ (A) Return and Associated Income Taxes, (B) Transmission Depreciation Expense, (C) Transmission Related Amortization of Loss on Reacquired Debt, (D) Transmission Related Amortization of Investment Tax Credits, (E) Transmission Related Municipal Tax Expense, (F) Transmission Related Payroll Tax Expense, (G) Transmission Operation and Maintenance Expense, (H) Transmission Related Administrative and General Expense (I) Transmission Support Expense, and(J) Transmission Related Taxes and Fees Charge.

A.

Return and Associated Income Taxes shall equal the product of the Transmission Investment Base and the Cost of Capital Rate.

1.

Transmission Investment Base

The Transmission Investment Base will be the average balances of (a) Transmission Plant, plus (b) Transmission Related General Plant, plus (c) Transmission Plant Held for Future Use, less (d) Transmission Related Depreciation Reserve, less (e) Transmission Related Accumulated Deferred Taxes, plus (f) Transmission Related Loss on Reacquired Debt, plus (g) Other Regulatory Assets/Liabilities, plus (h) Transmission Prepayments, plus (i) Transmission Materials and Supplies, plus (j) Transmission Related Cash Working Capital.

(a) Transmission Plant will equal the balance of the NU Companies’ investment in Transmission Plant.

(b) Transmission Related General Plant shall equal the NU Companies’ balance of investment in General Plant multiplied by the Transmission Wages and Salaries Allocation Factor.

(c) Transmission Plant Held for Future Use shall equal the balance of Transmission Plant Held for Future Use.

(d) Transmission Related Depreciation Reserve shall equal the balance of Total Transmission Depreciation Reserve, plus the balance of Transmission Related General Plant Depreciation Reserve. Transmission Related General Plant Depreciation Reserve shall equal the product of General Plant Depreciation Reserve and the Transmission Wages and Salaries Allocation Factor.

(e) Transmission Accumulated Deferred Taxes shall equal the NU Companies’ electric balance of Total Accumulated Deferred Income Taxes multiplied by the Plant Allocation Factor.

(f) Transmission Related Loss on Reacquired Debt shall equal the NU Companies’ electric balance of Total Loss on Reacquired Debt multiplied by the Plant Allocation Factor.

(g) Other Regulatory Assets/Liabilities shall equal the NU Companies’ electric balance of any deferred rate recovery of FAS 106 expense multiplied by the Transmission Wages

and Salaries Allocation Factor, plus the NU Companies’ electric balance of FAS 109 multiplied by the Plant Allocation Factor.

(h) Transmission Prepayments shall equal the NU Companies’ electric balance of Prepayments multiplied by the Transmission Wages and Salaries Allocation Factor.

(i) Transmission Materials and Supplies shall equal the NU Companies’ electric balance of Transmission Plant Materials and Supplies.

(j) Transmission Related Cash Working Capital shall be a 12.5% allowance (45 days/360 days) of Transmission Operation and Maintenance Expense and Transmission Related Administrative and General Expense.

2.

Cost of Capital Rate

The Cost of Capital Rate will equal (a) the NU Companies’ Weighted Cost of Capital, plus (b) Federal Income Tax plus (c) State Income Tax.

(a)

The Weighted Cost of Capital will be calculated based upon the capital structure at the end of each year and will equal the sum of:

(i)

the long term debt component, which equals the product of the actual weighted average embedded cost to maturity of the NU Companies’ long-term debt then outstanding and the ratio that long-term debt is to the NU Companies’ total capital.

(ii)

the preferred stock component, which equals the product of the actual weighted average embedded cost to maturity of the NU Companies’ preferred stock then outstanding and the ratio that preferred stock is to the NU Companies’ total capital.

(iii)

the return on equity component, shall equal the product of Northeast Utilities’ return on equity (“ROE”) of 12.8% and the ratio that common equity is to Northeast Utilities’ total capital.

(b)

Federal Income Tax shall equal

[(A+[(C+B)/D]x (FT)] divided by (1-FT)

where FT is the Federal Income Tax Rate and A is the sum of the preferred stock component and the return on equity component, as determined in Sections II.A.2.(a)(ii) and (iii) above, B is Transmission Related Amortization of Investment Tax Credits, as determined in Section II.D., below, C is the Equity AFUDC component of Transmission Depreciation Expense, as defined in Section II.B., and D is Transmission Investment Base, as Determined in II.A.1., above.

(c)

State Income Tax shall equal

[A+[(C+B)/D] + Federal Income Tax)x(ST)] divided by (1-ST)

where ST is the State Income Tax Rate, A is the sum of the preferred stock component and return on equity component determined in Sections II.A.2.(a)(ii) and (iii) above, B is the Amortization of Investment Tax Credits as determined in Section II.D. below, C is the equity AFUDC component of Transmission Depreciation Expense, as defined in Section II.B., D is the Transmission Investment Base, as determined in II.A.1., above and Federal Income Tax is the rate determined in Section II.A.2.(b) above.

B.

Transmission Depreciation Expense shall equal the sum of Depreciation Expense for Transmission Plant, plus an allocation of General Plant Deprecation Expense calculated by multiplying General Plant Depreciation Expense by the Transmission Wages and Salaries Allocation Factor.

C.

Transmission Related Amortization of Loss on Reacquired Debt shall equal the NU Companies’ electric Amortization of Loss on Reacquired Debt multiplied by the Plant Allocation Factor.

D.

Transmission Related Amortization of Investment Tax Credits shall equal the NU Companies’ electric Amortization of Investment Tax Credits multiplied by the Plant Allocation Factor.

E.

Transmission Related Municipal Tax Expense shall equal the NU Companies’’ electric Total Municipal Tax Expense multiplied by the Plant Allocation Factor.

F.

Transmission Related Payroll Tax Expense shall equal the NU Companies’ electric Payroll Tax expense, multiplied by the Transmission Wages and Salaries Allocation Factor.

G.

Transmission Operation and Maintenance Expense shall equal Transmission Operation and Maintenance Expenses.

H.

Transmission Related Administrative and General Expenses shall equal the sum of (1) the NU Companies’ Administrative and General Expenses multiplied by the Transmission Wages and Salaries Allocation Factor, (2) Property Insurance multiplied by the Transmission Plant Allocation Factor, (3) Expenses included in Account 928 related to FERC Assessments multiplied by the Plant Allocation Factor, plus any other Federal and State transmission related expenses or assessments in Account 928 plus specific transmission related expenses included in Account 930.1 and, (4) specific transmission related public education expenses included in Account 426.54.

I.

Transmission Support Expense shall equal the expense paid by the NU Companies’ for transmission support.

J.

Transmission Related Taxes and Fees Charge shall include any fee or assessment imposed by any governmental authority on service provided under this Local Service Schedule that is not specifically identified under any other section of this Local Service Schedule.

ATTACHMENT NU-I

Annual Revenue Requirements

For Localized Transmission Facilities

Attachment NU-I Methodology

This formula sets forth the method that the NU Companies’ will use to determine their annual total revenue requirements for Localized Facilities costs (“Localized Transmission Revenue Requirements”) for each state or area where Localized Facilities are located (subsequent references in this formula to Localized Facilities refer to Localized Facilities for each such state or area). The Localized Transmission Revenue Requirements will be an annual formula rate calculation, effective for an initial term commencing when the NU Companies incur the Localized Facilities costs and ending the immediately succeeding May 31st, and continuing thereafter for successive 12 month periods commencing each June 1 (“Rate Year”).  The calculation will be based on the previous calendar year’s Localized Transmission Revenue Requirements, plus the forecasted revenue requirements of Localized Facilities in service the upcoming Rate Year. Each June 1st, the Localized Transmission Revenue Requirements in effect during the previous calendar year will be trued-up based on actual costs from the most recent calendar year. The true-up information will be based on actual data, in lieu of allocated data if specifically identified in the FERC Form 1, or based on allocated data if such specific information is not identified.

I.

Definitions

Capitalized terms not otherwise defined in the Tariff and as used in this formula have the following definitions:

A.

Allocation Factors

1.

Localized Transmission Allocation Factor shall equal the ratio of Localized Transmission Plant in Service to total investment in Transmission Plant.

2.

Total Localized Plant Allocation Factor shall equal the ratio of Localized Transmission Plant in Service to Total Plant in Service.

3.

Transmission Wages and Salaries Allocation Factor shall equal the ratio of the NU Companies’ Transmission-related direct wages and salaries, including those of affiliated companies, to the NU Companies’ total direct wages and salaries, including those of affiliated companies, and excluding administrative and general wages and salaries.

B.

Terms

Administrative and General Expense shall equal the NU Companies’ expenses as recorded in FERC Account Nos. 920-935, excluding FERC Account Nos. 924, 928 and 930.1.

Amortization of Loss on Reacquired Debt shall equal the NU Companies’ expenses as recorded in FERC Account No. 428.1.

Amortization of Investment Tax Credits shall equal the NU Companies’ expenses as recorded in FERC Account No. 411.4.

Depreciation Expense for Localized Transmission Plant shall equal the NU Companies’ Localized Facilities expenses as recorded in FERC Account No. 403.

General Plant shall equal the NU Companies’ gross plant balance as recorded in FERC Account Nos. 389-399.

General Plant Depreciation Expense shall equal the NU Companies’ general plant expenses as recorded in FERC Account No. 403.

General Plant Depreciation Reserve shall equal the NU Companies’ general plant reserve balance as recorded in FERC Account No. 108.

Payroll Taxes shall equal those payroll expenses as recorded in NU Companies’ FERC Account Nos. 408.1 and 409.1.

Prepayments shall equal the NU Companies’ prepayment balance as recorded in FERC Account No. 165.

Property Insurance shall equal the NU Companies’ expenses as recorded in FERC Account No. 924.

Total Accumulated Deferred Income Taxes shall equal the net of the NU Companies’ deferred tax balance as recorded in FERC Account Nos. 281-283 and NU Companies’ deferred tax balance as recorded in FERC Account No. 190.

Total Loss on Reacquired Debt shall equal the NU Companies’ expenses as recorded in FERC Account 189.

Total Municipal Tax Expense shall equal the NU Companies’ expenses as recorded in FERC Account Nos. 408.1, 409.1.

Localized Transmission Plant in Service shall equal the NU Companies’ Localized Facilities gross plant balance as recorded in FERC Account Nos. 350-359.

Localized Transmission Depreciation Reserve shall equal the NU Companies’ Localized Facilities reserve balance as recorded in FERC Account 108.

Transmission Operation and Maintenance Expense shall equal NU Companies’ expenses as recorded in FERC Account Nos. 560, 562-564 and 566-573 and shall exclude all HQ HVDC expenses booked to accounts 560 through 573 and expenses already included in Transmission Support Expense, as described in Section I below, which are included in FERC Account Nos. 560-573.

Transmission Plant shall equal the NU Companies’ gross plant balance as recorded in FERC Account Nos. 350-359.

Transmission Plant Materials and Supplies shall equal the NU Companies’ balance as assigned to transmission, as recorded in FERC Account 154.

Total Plant in Service shall equal the NU Companies’ total gross plant balance as recorded in FERC Account Nos. 301-399.

II. Calculation of Localized Transmission Revenue Requirements

The Localized Transmission Revenue Requirements shall equal the sum of the NU Companies’ (A) Localized Return and Associated Income Taxes, (B) Localized Transmission Depreciation Expense, (C) Localized Transmission Related Amortization of Loss on Reacquired Debt, (D) Localized Transmission Related Amortization of Investment Tax Credits, (E) Localized Transmission Related Municipal Tax Expense, (F) Localized Transmission Related Payroll Tax Expense, (G) Localized Transmission Operation and Maintenance Expense, (H) Localized Transmission Related Administrative and General Expense , (I) Localized Transmission Support Expense, and (J) Localized Transmission Related Taxes and Fees Charge.

A.

Localized Return and Associated Income Taxes shall equal the product of the Localized Transmission Investment Base and the Cost of Capital Rate.

1.

Localized Transmission Investment Base The Localized Transmission Investment Base will be the average balances of (a) Localized Transmission Plant, less (b) Localized Transmission Related Depreciation Reserve, less (c) Localized Transmission Related Accumulated Deferred Taxes, plus (d) Localized Transmission Related Loss of Reacquired Debt, plus (e) Localized Transmission Prepayments, plus (f) Localized Transmission Materials and Supplies, plus (g) Localized Transmission Related Cash Working Capital.

(a)

Localized Transmission Plant will equal the balance of (1) the NU Companies’ investment in Localized Transmission Plant plus, (2) the NU Companies’ balance of investment in General Plant multiplied by the Transmission Wages and Salaries Allocation Factor, further multiplied by the Localized Transmission Allocation Factor.

(b)

Localized Transmission Related Depreciation Reserve shall equal the balance of Localized Transmission Depreciation Reserve plus the balance of Localized Transmission Related General Plant Depreciation Reserve. Localized Transmission Related General Plant Depreciation Reserve shall equal the product of General Plant Depreciation Reserve and the Transmission Wages and Salaries Allocation Factor, further multiplied by the Localized Transmission Allocation Factor.

(c)

Localized Transmission Related Accumulated Deferred Taxes shall equal the NU Companies’ electric balance of Total Accumulated Deferred Income Taxes, multiplied by the Total Localized Plant Allocation Factor.

(d)

Localized Related Loss on Reacquired Debt shall equal the NU Companies’ electric balance of Total Loss on Reacquired Debt multiplied by the Total Localized Plant Allocation Factor.

(e)

Localized Transmission Prepayments shall equal the NU Companies’ electric balance of Prepayments multiplied by the Transmission Wages and Salaries Allocation Factor and further multiplied by the Localized Transmission Allocation Factor.

(f)

Localized Transmission Materials and Supplies shall equal the NU Companies’ electric balance of Transmission Plant Materials and Supplies multiplied by the Localized Transmission Allocation Factor.

(g)

Localized Transmission Related Cash Working Capital shall be a 12.5% allowance (45 days/360 days) of (i) Localized Transmission Operation and Maintenance Expense, plus (ii) Localized Administrative and General Expense.

2.

Cost of Capital Rate

The Cost of Capital Rate will equal (a) the NU Companies’ Weighted Cost of Capital, plus (b) Federal Income Tax plus (c) State Income Tax.

(a)

The Weighted Cost of Capital will be calculated based upon the average capital structure and will equal the sum of:

(i) the long term debt component, which equals the product of the actual weighted average embedded cost to maturity of the NU Companies’ long-term debt then outstanding and the ratio that long-term debt is to the NU Companies’ total capital.

(ii) the preferred stock component, which equals the product of the actual weighted average embedded cost to maturity of the Northeast Utilities’ preferred stock then outstanding and the ratio that preferred stock is to the Northeast Utilities’ total capital.

(iii) the return on equity component, shall equal the product of the NU Companies’ return on equity (“ROE”) of 12.8% and the ratio that common equity is to the NU Companies’ total capital.

(b)

Federal Income Tax shall equal

[(A+[(C+B)/D]x (FT)] divided by (1-FT)

where FT is the Federal Income Tax Rate and A is the sum of the preferred stock component and the return on equity component, as determined in Sections II.A.2.(a)(ii) and (iii) above, B is Localized Transmission Related Amortization of Investment Tax Credits, as determined in Section II.D., below, C is the Equity AFUDC component of Localized Transmission Depreciation Expense, as defined in Section II.B., and D is Localized Transmission Investment Base, as Determined in II.A.1., above.

( c)

State Income Tax Shall equal:

[(A+[(C+B)/D] + Federal Income Tax) x (ST)] divided by (1-ST)

where ST is the State Income Tax Rate, A is the sum of the preferred stock component and return on equity component determined in Sections II.A.2.(a)(ii) and (iii) above, B is the Localized Transmission Related Amortization of Investment Tax Credits as determined in Section II.D. below, C is the equity AFUDC component of Localized Transmission Depreciation Expense, as defined in Section II.B., D is the Localized Transmission Investment Base, as determined in II.A.1. above and Federal Income Tax is the rate determined in Section II.A.2.(b) above.

B.

Localized Transmission Depreciation Expense shall equal the sum of Depreciation Expense for Localized Transmission Plant, plus an allocation of General Plant Deprecation Expense calculated by multiplying General Plant Depreciation Expense by the Transmission Wages and Salaries Allocation Factor and further multiplied by the Localized Transmission Allocation Factor.

C.

Localized Transmission Related Amortization of Loss on Reacquired Debt shall equal the NU Companies’ electric Amortization of Loss on Reacquired Debt multiplied by the Total Localized Plant Allocation Factor.

D.

Localized Transmission Related Amortization of Investment Tax Credits shall equal the NU Companies’ electric Amortization of Investment Tax Credits multiplied by the Total Localized Plant Allocation Factor.

E.

Localized Transmission Related Municipal Tax Expense shall equal the NU Companies’ Total Municipal Tax Expense multiplied by the Total Localized Plant Allocation Factor.

F.

Localized Transmission Related Payroll Tax Expense shall equal the NU Companies’ electric Payroll Taxes expense, multiplied by the Transmission Wages and Salaries Allocation Factor, and further multiplied by the Localized Transmission Allocation Factor.

G.

Localized Transmission Operation and Maintenance Expense shall equal the NU Companies’ Transmission Operation and Maintenance Expense multiplied by the Localized Transmission Allocation Factor.

H.

Localized Transmission Related Administrative and General Expense shall equal the sum of (1) the NU Companies’ Administrative and General Expense multiplied by the Transmission Wages and Salaries Allocation Factor and further multiplied by the Localized Transmission Allocation Factor, (2) Property Insurance multiplied by the Total Localized Plant Allocation Factor, (3) Expenses included in Account 928 related to FERC Assessments multiplied by the Total Localized Plant Allocation Factor, (4) Federal and State transmission related expenses or assessments in Account 928 multiplied by the Localized Transmission Allocation Factor, (5) specific transmission related expenses included in Account No. 930.1, multiplied by the Localized Transmission Allocation Factor, and (6) specific Localized Facility related public education expenses included in Account 426.54.

I.

Transmission Support Expense shall equal the expense paid by the NU Companies’ for transmission support for Localized Facilities.

J.

Transmission Related Taxes and Fees Charge shall include any fee or assessment imposed by any governmental authority on transmission service provided under this Local Service Schedule that is not specifically identified under any other section of this Local Service Schedule, multiplied by the Localized Transmission Allocation Factor.

SUPPLEMENT NO. 1 TO

Schedule 21-NU

Service Over Hydro-Quebec Facilities

I.

Definitions:

Unless otherwise provided, capitalized terms used herein shall have the definitions provided in the Tariff including Schedule 21-NU to the OATT.

II.

Transmission Service Over Hydro-Quebec Facilities:

Transmission service over the Hydro-Quebec Facilities is provided pursuant to the terms and conditions of this Local Service Schedule.

III.

Rates For Transmission Service Over Hydro-Quebec Facilities:

A.

Rates for Point-To-Point Transmission Service over the Hydro-Quebec Facilities are set forth in the following rate schedules attached to this Supplement No. 1:  Rate Schedule HQ-LTF for Long-Term Firm Point-To-Point Transmission Service; Rate Schedule HQ-STF for Short-Term Firm Point-To-Point Transmission Service; and Rate Schedule HQ-NF for Non-Firm Point-To-Point Transmission Service.

B.

Rates for Network Transmission Service over the Hydro-Quebec Facilities are set forth in Attachment HQ-NETWORK attached to this Supplement No. 1.

SCHEDULE HQ-LTF

Hydro-Quebec Facilities

Long-Term Firm Point-To-Point

Transmission Service

CHARGE PROVISIONS

III.

For each month of service, NUSCO will bill the Transmission Customer the difference between: (1) the higher of the cumulative annual Embedded Cost Charges or the cumulative annual Opportunity Costs Charges, calculated on a monthly basis for each calendar year and (2) the cumulative annual amount of charges for Embedded Costs and Opportunity Costs preceding the service month for which the bill is being rendered. In January of each calendar year the cumulative billed amount for (2) above will be reset to zero (0).

A.

EMBEDDED COST CHARGE

1.

Determination of Embedded Cost Charge

The Embedded Cost Charge will provide for recovery of the embedded costs of the Hydro-Quebec Facilities of the NU Companies. The Embedded Cost Charge for each month will be the product of: (a) the "NU Companies' Formula Rate" (expressed in $ per kilowatt-year), divided by twelve (12) months, and (b) the Reserved Capacity (expressed in kilowatts).

2.

NU Companies Formula Rate

The NU Companies' formula rate shall be determined in accordance with the rate formulas specified in Appendix A of this Schedule HQ-LTF ("Formula Rate"), being applied to the costs recorded on each of the NU Companies' books of account (i.e., FERC Form 1). The Formula Rate shall be determined on the basis of estimated costs for each year until the actual NU Companies' costs for such year are determined. Thereafter, payments made on such estimate shall be recalculated based on actual data for that year, and an appropriate billing adjustment shall be made pursuant to Section 7 of this Local Service Schedule.

3.

Tax Rates and Taxes

The Formula Rate in effect during a Service Year shall be based on the local, state, and federal tax rates and taxes in effect during the prior year.  If, at any time, additional or new taxes are imposed on the NU Companies or existing taxes are removed, the Formula Rate will be appropriately modified and filed with the Commission in accordance with Part 35 of the Commission's regulations.

4.

Provision re: Exchanges

With respect to Entitlement Transactions or Energy Transactions or other transactions that involve an exchange, each party to such transaction shall be treated as an individual Transmission Customer under the Tariff. Accordingly, a separate Schedule HQ-LTF or other applicable charge(s) will be calculated for,

and a separate bill will be rendered to, each such individual Transmission Customer.

5.

Discounts

Three principal requirements apply to discounts for transmission service as follows: (1) any offer of a discount made by the NU Companies 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 NU Companies 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 Transmission System.

D.

OPPORTUNITY COSTS CHARGE

The Opportunity Costs Charge shall be determined each month in accordance with the provisions set forth in Appendix B of this Schedule HQ-LTF and the Service Agreement.

II.

In addition to the applicable charges set forth in Parts I and II of the Tariff, and as otherwise specified in the Service Agreement, the Transmission Customer shall pay to NUSCO each month the following additional charges for Hydro-Quebec Facilities Long- Term Firm Transmission Service provided during such month.

A.

Taxes and Fees Charge

B.

Regulatory Expenses Charge

C.

Other

A.

TAXES AND FEES CHARGE

If any governmental authority requires the payment of any fee or assessment or imposes any form of tax with respect to payments made for Hydro-Quebec Facilities Long-Term Firm Point-To-Point Transmission Service provided under the Tariff, not specifically provided for in any of the charge or rate provisions under the Tariff, including any applicable Interest charged on any deficiency assessment made by the taxing authority, together with any further tax on such payments, the obligation to make payment for any such fee, assessment, or tax shall be borne by the Transmission Customer. The NU Companies will make a separate filing with the Commission for recovery of any such costs in accordance with Part 35 of the Commission's regulations.

B.

REGULATORY EXPENSES CHARGE

The NU Companies shall have the right to make a Section 205 filing for recovery of regulatory expenses associated with the Tariff and the Service Agreements.

C.

OTHER

The NU Companies shall have the right, at any time, unilaterally to file for a change in any of the provisions of this Schedule HQ-LTF in accordance with Section 205 of the Federal Power Act and the Commission's implementing regulations.

SCHEDULE HQ-LTF

Appendix A

DETERMINATION OF

THE NU COMPANIES' FORMULA RATE

FOR HYDRO-QUEBEC FACILITIES

LONG-TERM FIRM POINT-TO-POINT TRANSMISSION SERVICE

The NU Companies' Formula Rate for Hydro-Quebec Facilities Long-Term Firm Point-To-Point

                                        A_i1 - B _i1

Formula Rate_{i   =}                         C _i1

Transmission Service ("Formula Rate") is an annual rate determined from the following formula.

WHERE:

•

i equals the calendar year during which service is being rendered (“Service Year”).

•

Ai-1 is the Annual Cost (expressed in dollars) of the Hydro-Quebec Facilities of the NU Companies for the calendar year prior to the Service Year. The Annual Revenue Requirements are determined pursuant to the formula specified in Exhibit 1 to this Appendix A.

•

Bi-1 is the actual transmission revenues (expressed in dollars) provided from the provision of transmission services over the Hydro-Quebec Facilities to others. The actual transmission revenues shall be those recorded on the books of the NU Companies in FERC Account Nos. 447 and 456 pertaining to Transmission of Electricity for Others and such other applicable FERC Account for the calendar year prior to the Service Year.

•

Ci-1 is the average of the NU Companies twelve monthly maximum transfer limits (expressed in kilowatts) on its share of the Hydro-Quebec Facilities for the calendar year prior to the Service Year.

SCHEDULE HQ-LTF

Appendix A

Exhibit 1

DETERMINATION OF ANNUAL TRANSMISSION REVENUE REQUIREMENTS

The Annual Transmission Cost for the NU Companies' Hydro-Quebec Facilities are the costs assessed by each of them in owning, operating, maintaining, and supporting those facilities, plus any applicable leasing costs and an allocable share of General Plant and other such plant and equipment. These costs shall be computed on a calendar-year basis using costs, from the calendar year prior to the Service Year.

In making such determinations, the provisions of the Uniform System of Accounts prescribed by FERC for Class A and Class B Public Utilities and Licensees shall be controlling.

The rate formula for determination of the annual revenue requirements for the Hydro-Quebec Facilities of the NU Companies are determined pursuant to this Appendix A of Schedule HQLTF, as follows:

A.

ANNUAL COST =

Sum of [each NU Company's Hydro-Quebec Facilities

transmission costs - Chester Static VAR Compensator].

SCHEDULE HQ-LTF

Appendix B

PROVISIONS FOR RECOVERY OF OPPORTUNITY COSTS FOR

HYDRO-QUEBEC FACILITIES

The types of Opportunity Costs that may be incurred by the NU Companies and charged to Transmission Customers in connection with the provision of Hydro-Quebec Facilities Long-  Term Firm Point-To-Point Transmission Service pursuant to a Service Agreement are described below.

1.

OUT OF RATE COSTS

1.1

Out of Rate Costs are incurred when: (i) the NU Companies are required under an ISO dispatch order to limit the operation of any of their generation Entitlements below the output level under economic dispatch or to "must run" any of their generation Entitlements above the levels associated with economic dispatch; and (ii) the ISO dispatch order adversely impacts the NU Companies' settlement billing or the settlement billing of another Transmission Customer that has a contractual right (through the purchase of an Entitlement from the NU Companies) to pass the cost back to the NU Companies; and (iii) the ISO does not grant a waiver of the Out of Rate Costs incurred pursuant to (i) and (ii) above.

1.2

The information required from the ISO to establish the existence and level of Out of Rate Costs and the Transmission Customer's responsibility for such costs will normally not be available to the NU Companies by the end of the billing month in which the Out of Rate Costs are incurred. Accordingly, the bills rendered for Hydro-Quebec Facilities Long-Term Firm Point-To-Point Transmission Service pursuant to Section 7 of the Tariff shall be subject to subsequent adjustment, as provided in Section F.2 of this Appendix B of Schedule HQ-LTF.

1.3

In circumstances where multiple transactions across a constrained transmission path are causing the incurrence of Out of Rate Costs, the Out of Rate Costs will be allocated first to the Hydro-Quebec Facilities Non-Firm Point-To-Point Transmission Service customers under the Tariff to the extent that their service is not curtailed or interrupted pursuant to the provisions of the Tariff. If, after curtailment or interruption of such Hydro-Quebec Facilities Non-Firm Point-To-Point Transmission Service and/or the allocation of Out of Rate Costs to Hydro-Quebec Facilities Non-Firm Point-To-Point Transmission Service customers under the Tariff, Out of Rate Costs remain, such remaining costs will be allocated to Hydro-Quebec Facilities Long-Term and Hydro-Quebec Facilities Short-Term Firm Point-To-Point Transmission Service customers with the latest date (latest means, the latest dated Service Agreement for Hydro-Quebec Facilities Firm Point - -To-Point Transmission Service or latest dated Reservation for Hydro-Quebec Facilities Non-Firm Point-To-Point Transmission Service). Where the reduction in the number of megawatts of Hydro-Quebec Facilities Non-Firm Point-To-Point Transmission Service and of Hydro-Quebec Facilities Long-Term and Hydro-Quebec Facilities Short-Term Firm Point-To-Point Transmission Service that would have been required to eliminate the need for the ISO limitation or "must run" in any hour exceeds the megawatts of actual Hydro-Quebec Facilities Non-Firm Point-To-Point

Transmission Service and Hydro-Quebec Facilities Long-Term and Short-Term Firm Point-To-Point Transmission Service of the latest applicable transaction in such hour, the excess Out of Rate Costs will be allocated to the next latest transaction and so on until the total additional megawatts of Hydro-Quebec Facilities Long-Term and Hydro-Quebec Facilities Short-Term Firm Point-To-Point Transmission Service that is required to be reduced to eliminate the need for such ISO limitation or "must run" order has been achieved. Whenever the transactions across a constrained transmission path that are causing the incurrence of Out of Rate Costs include off-system sales by the NU Companies, such NU Companies' off-system sales shall be included on the same basis as Hydro-Quebec Facilities Non-Firm Point-To-Point Transmission Service and Hydro-Quebec Facilities Long-Term and Hydro-Quebec Facilities Short-Term Fir m Point-To-Point Transmission Service transactions in determining responsibility for Out of Rate Costs and the date of the off-system sales contract or wholesale transaction shall be used to determine its "service agreement" or "reservation" date.

2.

OPPORTUNITY COSTS ON HYDRO-QUEBEC FACILITIES

2.1

Short-Term Power Transfers into New England The NU Companies' lost opportunities to purchase economic short-term power will occur when the amount of power that would be economical for the NU Companies to purchase in the market (at a validated, quoted delivered price below their decremental energy cost) exceeds the amount of the NU Companies' allocated share of Hydro-Quebec Facilities transfer capacity not then committed to others for Non-Firm Point-To-Point Transmission Service and Hydro-Quebec Facilities Long-Term and Hydro-Quebec Facilities Short-Term Firm Point-To-Point Transmission Service into New England and for purchases on behalf of Native Load Customers ("Short-Term Available Import Capacity"). Operating conditions in New England or elsewhere and/or the location of the seller may affect the amount of Short-Term Available Import Capacity.

The following steps comprise the procedures to be used in assigning such Opportunity Costs on Hydro-Quebec Facilities to Firm Transmission Service customers under the Tariff after assignment of any Opportunity Costs to Hydro-Quebec Facilities Non-Firm Point-To-Point Transmission Service customers under the Tariff, pursuant to the provisions of the Tariff.

2.1.1

The megawatt (MW) difference, if any, between the aggregate of economic power purchase opportunities available and Short-Term Available Import Capacity will be determined hourly ("Import Shortfall").

2.1.2

To assign such Opportunity Costs on Hydro-Quebec Facilities to Transmission Customers, Service Agreements for Hydro-Quebec Facilities Long-Term and Hydro-Quebec Facilities Short-Term Firm Point-To-Point Transmission Service will be ordered (stacked) by date of execution of the Service Agreement under the Tariff, with the Hydro-Quebec Facilities Firm Point-To-Point Transmission Customers under the Tariff having the latest date being assigned the highest order number.

2.1.3

Firm Transmission Customers under the Tariff contributing to the MW amount of lost opportunities will be determined by aggregating MWs of the Reserved Capacity counting backward from the highest order number Firm Point-To-Point

Service Agreement under the Tariff until the aggregate MWs equals the Import Shortfall.

2.1.4

Such Opportunity Costs on Hydro-Quebec Facilities for each hour associated with the lowest cost purchase opportunity foregone will be assigned to the highest order numbered Hydro-Quebec Facilities Firm Point-To-Point Service Agreement(s) under the Tariff up to the MWs of such foregone purchase.

2.1.5

The MWs of the next lowest cost purchase foregone will be assigned to the MWs of the next following Hydro-Quebec Facilities Firm Point-To-Point Service Agreement under the Tariff or (next highest order number not fully included in the calculation in d. above) and so on until the MWs used to calculate the lost opportunities equals the Import Shortfall.

2.1.6

Such Opportunity Costs on Hydro-Quebec Facilities will be calculated for each hour by computing the difference between the cost of the economic power offered to, but not able to be taken by, the NU Companies and the decremental energy cost for the NU Companies for an equivalent amount of megawatt-hours (after reflecting applicable losses) of such foregone purchases. If however, the NU Companies elect to purchase power from an alternative supplier involving an unconstrained interface, such Opportunity Costs on Hydro-Quebec Facilities for each hour will be calculated as the difference between the cost of the economic power for the foregone transaction and the cost of economic power for the alternative transaction. The Service Agreement will set forth the method for calculating charges for Opportunity Costs on Hydro- Quebec Facilities associated with such foregone purchases.

2.1.7

Short-Term Power Transfers Out of New England The NU Companies' lost opportunities to sell short-term power will occur when the amount of power that would be economical for the NU Companies to sell in the market (at validated, quoted prices that exceed their incremental energy cost) exceeds the amount of the NU Companies' allocated share of the Hydro-Quebec Facilities transfer capacity out of New England not then committed for Hydro-Quebec Facilities Long-Term and Hydro-Quebec Facilities Short-Term Firm Point-To-Point Transmission Service out of New England ("Short-Term Available Export Capacity"). It is recognized that operating conditions in New England or elsewhere and/or the location of the buyer may affect the amount of Hydro-Quebec Facilities Short-Term Available Export Capacity.

2.2

The following steps comprise the procedures to be used in assigning such Opportunity Costs on Hydro-Quebec Facilities to Firm Point-To-Point Transmission Service Customers under the Tariff after assignment of Opportunity Costs to Hydro-Quebec Facilities Non-Firm Point-To-Point Transmission Service customers under the Tariff, pursuant to the provision of the Tariff.

2.2.1

The megawatt (MW) difference, if any, between the aggregate of economic power sales opportunities and the Hydro-Quebec Facilities Short-Term Available Export Capacity will be determined hourly ("Export Shortfall").

2.2.2

To assign such Opportunity Costs on Hydro-Quebec Facilities to Firm Point-To-Point Transmission Customers, the date of Service Agreements under the Tariff

for transmission service out of New England will be ordered (stacked) by date of the Hydro-Quebec Facilities Firm Point-To-Point Service Agreement under the Tariff (for NU Companies off-system sales, transmitted under the Tariff, the date used shall be the date of the sales contract or wholesale transaction), with the Hydro-Quebec Facilities Firm Point-To-Point Transmission Customers under the Tariff (or the NU Companies) having the latest execution date being assigned the highest order number.

2.2.3

Hydro-Quebec Facilities Firm Point-To-Point Transmission Customers under the Tariff (and/or the NU Companies) contributing to the MW amount of lost opportunities will be determined by aggregating MWs of Reserved Capacity (including contract or transaction amount of such NU Companies' sales) counting backward from the highest order number Hydro-Quebec Facilities Firm Point-To-Point Service Agreement under the Tariff (or contract or transaction of such NU Companies' sales) until the aggregate MWs equals the Export Shortfall.

2.2.4

Such Opportunity Costs on Hydro-Quebec Facilities for each hour associated with the highest priced sale opportunity foregone will be assigned to the highest order numbered Hydro-Quebec Facilities Firm Point-To-Point Service Agreement(s) under the Tariff (or contract or transaction for such NU Companies' sales) up to the MWs of such foregone sale.

2.2.5

The MWs of the next highest price sale foregone will be assigned to the  MWs of the next following Hydro-Quebec Facilities Firm Point-To-Point Service Agreement under the Tariff or NU Companies' off-system sale (next highest order number not fully included in the calculation in d. above) and so on until the MWs used to calculate the lost opportunities equals the Export Shortfall.

2.2.6

Such Opportunity Costs on Hydro-Quebec Facilities for each hour will be calculated by computing the difference between the price of the power for which willing buyers exist, but to whom sales cannot be made because of limited Hydro-Quebec Facilities Short-Term Available Export Capacity, and the incremental energy cost for the NU Companies for an equivalent amount of megawatt-hours (after reflecting applicable losses) of such foregone sales. If, however, the NU Companies elect to sell power to an alternative supplier involving an unconstrained interface, such Opportunity Costs on Hydro-Quebec Facilities will be calculated as the difference between the delivered price of power of the foregone transaction and the delivered price of power for the alternative transaction.  The Service Agreement will set forth the methodology for calculating charges for Opportunity Costs on Hydro-Quebec Facilities associated with such foregone sales.< /P>

3.

TIE LINE ADJUSTMENT COSTS

Service across the Hydro-Quebec Facilities into New England that results in a decrease in the amount of tie line benefits (expressed in kilowatts) reflected in the NU Companies' Capability Responsibility will be subject to claims for Opportunity Costs to account for reduction in such tie line benefits. The Service Agreement will set forth the methodology to determine the reduced tie line benefit to the NU Companies and to calculate the charge for recovery of such Opportunity Costs.

4.

OTHER OPPORTUNITY COSTS

Nothing in this Appendix B of Schedule HQ-LTF shall be construed to limit the right of the NU Companies to file unilaterally under Section 205 of the Federal Power Act for recovery of other Opportunity Costs incurred by the NU Companies in connection with Hydro-Quebec Facilities Long-Term Firm Point-To-Point Transmission Service to a Transmission Customer.

5.

LIMIT OF OPPORTUNITY COSTS

5.1

The aggregate annual Opportunity Costs billed across a given constrained interface shall be limited by the estimated annual levelized revenue requirement associated with new facilities that are technically and economically feasible to build and, if built, would increase the transfer capacity of the applicable interface to a level that would eliminate such costs. Such facilities and their costs will be designated in the Service Agreement. Opportunity Costs for all transactions will be accumulated and compared on an annual basis to the annual levelized revenue requirements associated with expanding the system as described above. The annual levelized revenue requirement so determined is the maximum cumulative Opportunity Costs that will be billed for that year for that interface for service in the applicable direction ("Cost Cap").

5.2

The Cost Cap shall not apply during the construction period set forth in the Service Agreement. The Companies shall not be restricted from filing a request for a waiver of the Cost Cap with the Commission on a case-by-case basis.

6.

OTHER PROVISIONS

6.1

Whenever the NU Companies determine in advance that they expect to charge the Transmission Customer for Opportunity Costs hereunder, the NU Companies will, if practicable, notify the Transmission Customer, based on the information then available, and give such Customer the option of interrupting its scheduled deliveries for an identified day in order to avoid charges for Opportunity Costs. It is explicitly recognized that the NU Companies may not unilaterally interrupt service to avoid the incurrence of Opportunity Costs, and the option to permit interruption rests solely with the Transmission Customer. It is also explicitly recognized that the NU Companies may not have the ability to make this determination on a timely basis and to provide notice in advance of scheduling deadlines and they shall not be liable in any manner for failure to provide advance notice under this paragraph or for changes in operating conditions that impact on anticipated availability of transmission capacity.

6.2

For any hour that the NU Companies incur an Opportunity Cost pursuant to this Appendix B of Schedule HQ-LTF and NUSCO determines that the Opportunity Cost would not have been incurred if the NU Companies were not providing Hydro-Quebec Facilities Long-Term Firm Point-To-Point Transmission Service to the Transmission Customer, NUSCO shall be obligated to notify the Transmission Customer within one month of the date on which it had knowledge of the incurrence of the Opportunity Costs. In the event that the then calculated annual cumulative Opportunity Costs exceed the annual cumulative charges previously billed to the Transmission Customer for Embedded Costs or Opportunity Costs pursuant to Section I. of Schedule LTF, NUSCO may render an immediate billing adjustment.

6.3

All claims for Opportunity Costs shall be accompanied by a written statement or other documentation: (i) showing that the Opportunity Costs were incurred; (ii) showing the calculation for the Opportunity Costs incurred and claimed; and (iii) showing that the Opportunity Costs would not have been incurred in the absence of the transaction being charged. If the Transmission Customer, in good faith, disputes NUSCO's claim for Opportunity Costs, such dispute must be made within a ninety (90) day period following the end of the Service Year for which the Opportunity Costs were claimed by NUSCO.

6.4

The NU Companies shall have the right, at any time, unilaterally to file for a change in any of the provisions of this Appendix B of Schedule HQ-LTF in accordance with Section 205 of the Federal Power Act and the Commission's implementing regulations.

SCHEDULE HQ-STF

Hydro-Quebec Facilities              Short-Term Firm Point-To-Point

Transmission Service

CHARGE PROVISIONS

I.

For each daily, weekly or monthly Transaction, NUSCO will bill the Transmission Customer the higher of: (1) the Embedded Cost Charge or (2) the Opportunity Cost Charges, calculated for the term of each such Transaction. For Transaction having a term greater than one month, NUSCO will bill the Transmission Customer the difference between: (1) the higher of the cumulative Embedded Cost Charges or the cumulative Opportunity Costs Charges, calculated from the effective date of Hydro-Quebec Facilities Short-Term Firm Point-To-Point Transmission Service through the end of the service month and (2) the cumulative billed amount of charges for Embedded Costs and Opportunity Costs preceding the service month for which the bill is being rendered.

A.

EMBEDDED COST CHARGE

1.

Determination of Embedded Cost Charge

The Embedded Cost Charge will provide for recovery of the embedded costs of the Hydro-Quebec Facilities of the NU Companies. The Embedded Cost Charge for each month will equal the sum of the Embedded Cost Charges for each monthly (or longer term), weekly, or daily Transaction during such month.

The Embedded Cost Charge for each monthly Transaction shall be determined as the product of: (a) the NU Companies' Annual Rate for Hydro-Quebec Facilities Short-Term Firm Point-To-Point Transmission Service ÷ twelve (12) months (expressed in $ per kilowatt-month) and (b) the Reserved Capacity set forth for such monthly Transaction (expressed in kilowatts).

The Embedded Cost Charge for each weekly Transaction shall be determined as the product of: (a) the NU Companies' Weekly Hydro-Quebec Facilities Short-Term Firm Point-To-Point Transmission Rate (expressed in $ per kilowatt-week), and (b) the Reserved Capacity set forth for such weekly Transaction (expressed in kilowatts). The NU Companies' Weekly Rate is the NU Companies' Annual Rate for Hydro-Quebec Facilities Short-Term Firm Point-To-Point Transmission Service ÷ fifty-two (52) weeks.

The Embedded Cost Charge for each daily Transaction shall be determined as the product of: (a) the NU Companies' Daily Hydro-Quebec Facilities Short-Term Firm Point-To-Point Transmission Rate (expressed in $ per kilowatt-day), and (b) the Reserved Capacity set forth for such daily Transaction (expressed in kilowatts). The NU Companies' Daily Rate is the NU Companies' Weekly Rate for Hydro-Quebec Facilities Short-Term Firm Point-To-Point Transmission Service ÷ five (5) days. The total of the charges for daily Transactions, under an individual reservation, in a seven (7) day period shall not exceed the charges based on the Weekly Rate and the maximum Reserved Capacity in the period.

2.

NU Companies' Annual Formula Rate for Hydro-Quebec Facilities Short-Term Transmission Service

The NU Companies' Annual Formula Rate for Hydro-Quebec Facilities Short-Term Firm Point-To-Point Transmission Service shall be expressed in $ per kilowatt-year and shall be determined in accordance with the rate formula specified in Appendix A of this Schedule HQ-STF ("Formula Rate") being applied to the costs recorded on the NU Companies' books of account (i.e., FERC Form 1). The Formula Rate shall be determined on the basis of estimated costs for each year until the actual NU Companies' costs for such year are determined. Thereafter, payments made on such estimate shall be recalculated based on actual data for that year, and an appropriate billing adjustment shall be made pursuant to Section 7 of the Tariff.

3.

Tax Rates and Taxes

The Formula Rate set forth in this Schedule HQ-STF in effect during a Service Year shall be based on the local, state, and federal tax rates and taxes in effect during the prior year. If, at any time, additional or new taxes are imposed on the Companies or existing taxes are removed, the Formula Rate will be appropriately modified and filed with the Commission in accordance with Part 35 of the Commission's regulations.

4.

Provision re: Exchanges

With respect to Entitlement Transactions or Energy Transactions or other transactions that involve an exchange, each party to such transaction shall be treated as an individual Transmission Customer under the Tariff.   Accordingly, a separate Schedule HQ-STF or other applicable charge(s) will be calculated for, and a separate bill will be rendered to, each such individual Transmission Customer.

5.

Discounts

Three principal requirements apply to discounts for transmission service  as follows: (1) any offer of a discount made by the NU Companies 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 NU Companies 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 Transmission System.

B.

OPPORTUNITY COSTS CHARGE

The Opportunity Costs Charge shall be determined each month in accordance with the provisions set forth in Appendix B of this Schedule HQ-STF and the Service Agreement.

II.

In addition to the applicable charges set forth in Section I of this Schedule HQ-STF, and as otherwise specified in the Service Agreement, the Transmission Customer shall pay to NUSCO

each month the following additional charges for Hydro-Quebec Facilities Short-Term Firm Point-To-Point Transmission Service provided during such month.

A.

Taxes and Fees Charge

B.

Regulatory Expenses Charge

C.

Other

A.

TAXES AND FEES CHARGE

If any governmental authority requires the payment of any fee or assessment or imposes any form of tax with respect to payments made for Hydro-Quebec Facilities Short-Term Firm Point-To-Point Transmission Service provided under the Tariff, not specifically provided for in any of the charge or rate provisions under the Tariff, including any applicable interest charged on any deficiency assessment made by the taxing authority, together with any further tax on such payments, the obligation to make payment for any such fee, assessment, or tax shall be borne by the Transmission Customer. The NU Companies will make a separate filing with the Commission for recovery of any such costs in accordance with Part 35 of the Commission's regulations.

B.

REGULATORY EXPENSES CHARGE

The NU Companies shall have the right to make a Section 205 filing for recovery of regulatory expenses associated with the Tariff and the Service Agreements.

C.

OTHER

The NU Companies shall have the right, at any time, unilaterally to file for a change in any of the provisions of this Schedule HQ-STF in accordance with Section 205 of the Federal Power Act and the Commission's implementing regulations.

SCHEDULE HQ-STF

Appendix A

DETERMINATION OF

THE NU COMPANIES' FORMULA RATE

FOR HYDRO-QUEBEC FACILITIES

SHORT-TERM FIRM POINT-TO-POINT TRANSMISSION SERVICE

The NU Companies' Formula Rate for Hydro-Quebec Facilities Short-Term Firm Point-To-Point

                                        A_i1 - B _i1

Formula Rate_{i   =}                         C _i1

Transmission Service ("Formula Rate") is an annual rate determined from the following formula.

WHERE:

•

i equals the calendar year during which service is being rendered ("Service Year").

•

Ai-1 is the Annual Cost (expressed in dollars) of the Hydro-Quebec Facilities of the NU Companies for the calendar year prior to the Service Year. The Annual Revenue Requirements are determined pursuant to the formula specified in Exhibit 1 to this Appendix A of Schedule HQ-STF.

•

Bi-1 is the actual transmission revenues (expressed in dollars) provided from the provision of transmission services over the Hydro-Quebec Facilities to others. The actual transmission revenues shall be those recorded on the books of the NU Companies in FERC Account Nos. 447 and 456 pertaining to Transmission of Electricity for Others and such other applicable FERC Account for the calendar year prior to the Service Year.

•

Ci-1 is the average of NU Companies' twelve monthly maximum transfer limits (expressed in kilowatts) on its share of the Phase I and Phase II DC facilities for the calendar year prior to the Service Year.

SCHEDULE HQ-STF

Appendix A

Exhibit 1

DETERMINATION OF ANNUAL TRANSMISSION REVENUE REQUIREMENTS

The Annual Transmission Cost for the NU Companies' Hydro-Quebec Facilities are the costs assessed by each of them in owning, operating, maintaining, and supporting those facilities, plus any applicable leasing costs and an allocable share of General Plant and other such plant and equipment. These costs shall be computed on a calendar-year basis using costs, from the calendar year prior to the Service Year.

In making such determinations, the provisions of the Uniform System of Accounts prescribed by FERC for Class A and Class B Public Utilities and Licensees shall be controlling.

The rate formulae for determination of the annual revenue requirements for the Hydro-Quebec Facilities of the NU Companies are determined pursuant to this Appendix A of Schedule HQSTF, as follows:

A.

ANNUAL REVENUE REQUIREMENTS = Sum of [each NU Companies' Hydro-Quebec Facilities transmission costs - Chester Static VAR Compensator].

SCHEDULE HQ-STF

Appendix B

PROVISIONS FOR RECOVERY OF OPPORTUNITY COSTS

FOR HYDRO-QUEBEC FACILITIES

The types of Opportunity Costs that may be incurred by the NU Companies and charged to Transmission Customers in connection with the provision of Hydro-Quebec Facilities Short-Term Firm Point-To-Point Transmission Service pursuant to a Service Agreement are described

below.

1

OUT OF RATE COSTS

1.1

Out of Rate Costs are incurred when: (i) the NU Companies are required under an ISO dispatch order to limit the operation of any of their generation Entitlements below the output level under economic dispatch or to "must run" any of their generation Entitlements above the levels associated with economic dispatch; and (ii) the ISO dispatch order adversely impacts the NU Companies' settlement billing or the settlement billing of another Transmission Customer that has a contractual right (through the purchase of an Entitlement from the NU Companies) to pass the cost back to the NU Companies; and (iii) the ISO does not grant a waiver of the Out of Rate Costs incurred pursuant to (i) and (ii) above.

1.2

The information required from the ISO to establish the existence and level of Out of Rate Costs and the Transmission Customer's responsibility for such costs will normally not be available to the NU Companies by the end of the billing month in which the Out of Rate Costs are incurred. Accordingly, the bills rendered for Hydro-Quebec Facilities Short-Term Firm Point-To-Point Transmission Service pursuant to Section 7 of the Tariff shall be subject to subsequent adjustment, as provided in Section E.2 of this Appendix B of Schedule HQ-STF.

1.3

In circumstances where multiple transactions across a constrained transmission path are causing the incurrence of Out of Rate Costs, the Out of Rate Costs will be allocated first to the Hydro-Quebec Facilities Non-Firm Point-To-Point Transmission Service customers under the Tariff to the extent that their service is not curtailed or interrupted pursuant to the provisions of the Tariff. If, after curtailment or interruption of such Hydro-Quebec Facilities Non-Firm Point-To-Point Transmission Service and/or the allocation of Out of Rate Costs to Hydro-Quebec Facilities Non-Firm Point-To-Point Transmission Service customers under the Tariff, Out of Rate Costs remain, such remaining costs will be allocated to Hydro-Quebec Facilities Long-Term and Hydro-Quebec Facilities Short-Term Firm Point-To-Point Transmission Service customers with the latest date (latest means, the latest dated Service Agreement for Firm Point-To-Point Transmission S ervice).  Where the reduction in the number of megawatts of Hydro-Quebec Facilities Long-Term and Hydro-Quebec Facilities Short-Term Firm Point-To-Point Transmission Service that would have been required to eliminate the need for the ISO limitation or "must run" in any hour exceeds the megawatts of actual Hydro-Quebec Facilities Long-Term and Hydro-Quebec Facilities Short-Term Firm Point-To-Point Transmission Service of the latest applicable transaction in such hour, the excess Out of Rate Costs will be allocated to the next latest transaction and so on until the total

additional megawatts of Hydro-Quebec Facilities Long-Term and Hydro-Quebec Facilities Short-Term Firm Point-To-Point Transmission Service that is required to be reduced to eliminate the need for such ISO limitation or "must run" order has been achieved. Whenever the transactions across a constrained transmission path that are causing the incurrence of Out of Rate Costs include off-system sales by the NU Companies, such NU Companies' off-system sales shall be included on the same basis as Hydro-Quebec Facilities Long-Term and Hydro-Quebec Facilities Short-Term Firm Point-To-Point Transmission Service transactions in determining responsibility for Out of Rate Costs and the date of the off-system sales contract or wholesale transaction shall be used to determine its "service agreement" or "transaction" date.

2

OPPORTUNITY COSTS ON HYDRO-QUEBEC FACILITIES

2.1

Short-Term Power Transfers into New England

The NU Companies' lost opportunities to purchase economic short-term power will occur when the amount of power that would be economical for the NU Companies to purchase in the market (at a validated, quoted delivered price below their decremental energy cost) exceeds the amount of the NU Companies' allocated share of Hydro-Quebec Facilities transfer capacity not then committed to others for Hydro-Quebec Facilities Long-Term and Hydro-Quebec Facilities Short-Term Firm Point-To-Point Transmission Service into New England and for purchases on behalf of Native Load Customers ("Short-Term Available Import Capacity"). Operating conditions in New England or elsewhere and/or the location of the seller may affect the amount of Hydro-Quebec Facilities Short-Term Available Import Capacity.

The following steps comprise the procedures to be used in assigning such Opportunity Costs on Hydro-Quebec Facilities to Firm customers under the Tariff after assignment of any Opportunity Costs to Hydro-Quebec Facilities Non-Firm Point-To-Point Transmission Service customers under the Tariff, pursuant to the provisions of the Tariff.

2.1.1

The megawatt (MW) difference, if any, between the aggregate of economic power purchase opportunities available and Hydro-Quebec Facilities Short-Term Available Import Capacity will be determined hourly ("Import Shortfall").

2.1.2

To assign such Opportunity Costs on Hydro-Quebec Facilities to Transmission Customers, Firm Point-To-Point Service Agreements under the Tariff will be ordered (stacked) by date of execution of the Hydro-Quebec Facilities Firm Point-To-Point Service Agreement under the Tariff, with the Firm Point-To-Point Transmission Customers under the Tariff having the latest date being assigned the highest order number.

2.1.3

Hydro-Quebec Facilities Firm Point-To-Point Transmission Customers under the Tariff contributing to the MW amount of lost opportunities will be determined by aggregating MWs of Reserved Capacity counting backward from the highest order number Hydro-Quebec Facilities Firm Point-To-Point Service Agreement under the Tariff until the aggregate MWs equals the Import Shortfall.

2.1.4

Such Opportunity Costs on Hydro-Quebec Facilities for each hour associated with the lowest cost purchase opportunity foregone will be assigned to the

highest order numbered Hydro-Quebec Facilities Firm Point-To-Point Service Agreement(s) under the Tariff up to the MWs of such foregone purchase.

2.1.5

The MWs of the next lowest cost purchase foregone will be assigned to the MWs of the next following Hydro-Quebec Facilities Firm Point-To-Point Service Agreement under the Tariff (next highest order number not fully included in the calculation in d. above) and so on until the MWs used to calculate the lost opportunities equals the Import Shortfall.

2.1.6

Such Opportunity Costs on Hydro-Quebec Facilities will be calculated for each hour by computing the difference between the cost of the economic power offered to, but not able to be taken by, the NU Companies and the decremental energy cost for the NU Companies for an equivalent amount of megawatt-hours (after reflecting applicable losses) of such foregone purchases. If however, the NU Companies elect to purchase power from an alternative supplier involving an unconstrained interface, such Opportunity Costs on Hydro-Quebec Facilities for each hour will be calculated as the difference between the cost of the economic power for the foregone transaction and the cost of economic power for the alternative transaction.  The Service Agreement will set forth the method for calculating charges for Opportunity Costs on Hydro-Quebec Facilities associated with such foregone purchases.

2.2

Short-Term Power Transfers Out of New England

The NU Companies' lost opportunities to sell Hydro-Quebec Facilities short-term power will occur when the amount of power that would be economical for the NU Companies to sell in the market (at validated, quoted prices that exceed their incremental energy cost) exceeds the amount of the NU Companies' allocated share of the Hydro-Quebec Facilities transfer capacity out of New England not then committed for Hydro-Quebec Facilities Long-Term and Hydro-Quebec Facilities Short-Term Firm Point-To-Point Transmission Service out of New England ("Short-Term Available Export Capacity"). It is recognized that operating conditions in New England or elsewhere and/or the location of the buyer may affect the amount of Short-Term Available Export Capacity.

The following steps comprise the procedures to be used in assigning such Opportunity Costs on Hydro-Quebec Facilities to Firm Point-To-Point Customers under the Tariff after assignment of Opportunity Costs to Hydro-Quebec Facilities Non-Firm Point-To-Point Transmission Service customers under the Tariff,  pursuant to the provision of the Tariff.

2.2.1

The megawatt (MW) difference, if any, between the aggregate of economic power sales opportunities and the Short-Term Available Export Capacity will be determined hourly ("Export Shortfall").

2.2.2

To assign such Opportunity Costs on Hydro-Quebec Facilities to Transmission Customers, the date of Hydro-Quebec Facilities Firm Point-To-Point Service Agreements under the Tariff for transmission service out of New England will be ordered (stacked) by date of the Firm Point-To-Point Service Agreement under the Tariff (for NU Companies off-system sales, transmitted under Hydro-Quebec Facilities Firm Point-To-Point Transmission Service under the Tariff, the date used shall be the date of the sales contract or wholesale transaction), with the

Hydro-Quebec Facilities Firm Point-To-Point Transmission Customers under the Tariff (or the NU Companies) having the latest execution date being assigned the highest order number.

2.2.3

Firm Point-To-Point Transmission Customers under the Tariff (and/or the NU Companies) contributing to the MW amount of lost opportunities will be determined by aggregating MWs of Reserved Capacity (including contract or transaction amount of such Companies' sales) counting backward from the highest order number Hydro-Quebec Facilities Firm Point-To-Point Service Agreement under the Tariff (or contract or transaction of such NU Companies' sales) until the aggregate MWs equals the Export Shortfall.

2.2.4

Such Opportunity Costs on Hydro-Quebec Facilities for each hour associated with the highest priced sale opportunity foregone will be assigned to the highest order numbered Hydro-Quebec Facilities Firm Point-To-Point Service Agreement under the Tariff (or contract or transaction for such Companies' sales) up to the MWs of such foregone sale.

2.2.5

The MWs of the next highest price sale foregone will be assigned to the MWs of the next following Firm Point-To-Point Service Agreement under the Tariff or NU Companies' off-system sale (next highest order number not fully included in the calculation in d. above) and so on until the MWs used to calculate the lost opportunities equals the Export Shortfall.

2.2.6

Such Opportunity Costs on Hydro-Quebec Facilities for each hour will be calculated by computing the difference between the price of the power for which willing buyers exist, but to whom sales cannot be made because of limited Hydro-Quebec Facilities Short-Term Available Export Capacity, and the incremental energy cost for the NU Companies for an equivalent amount of megawatt-hours (after reflecting applicable losses) of such foregone sales. If, however, the NU Companies elect to sell power to an alternative supplier involving an unconstrained interface, such Opportunity Costs on Hydro-Quebec Facilities will be calculated as the difference between the delivered price of power of the foregone transaction and the delivered price of power for the alternative transaction. The Service Agreement will set forth the methodology for calculating charges for Opportunity Costs on Hydro-Quebec Facilities associated with such foregone sales.

3

TIE LINE ADJUSTMENT COSTS

Service across the Hydro-Quebec Facilities into New England that results in a decrease in the amount of tie line benefits (expressed in kilowatts) reflected in the NU Companies' Capability Responsibility will be subject to claims for Opportunity Costs to account for reduction in such tie line benefits. The Service Agreement will set forth the methodology to determine the reduced tie line benefit to the NU Companies and to calculate the charge for recovery of such Opportunity Costs.

4

OTHER OPPORTUNITY COSTS

Nothing in this Appendix B of Schedule HQ-STF shall be construed to limit the right of the NU Companies to file unilaterally under Section 205 of the Federal Power Act for recovery of other

Opportunity Costs incurred by the Companies in connection with Hydro-Quebec Facilities Short-Term Firm Point-To-Point Transmission Service to a Transmission Customer.

5

OTHER PROVISIONS

5.1

Whenever the NU Companies determine in advance that they expect to charge the Transmission Customer for Opportunity Costs hereunder, the NU Companies will, if practicable, notify the Transmission Customer, based on the information then available, and give such Customer the option of interrupting its scheduled deliveries for an identified day in order to avoid charges for Opportunity Costs. It is explicitly recognized that the NU Companies may not unilaterally interrupt service to avoid the incurrence of Opportunity Costs, and the option to permit interruption rests solely with the Transmission Customer. It is also explicitly recognized that the NU Companies may not have the ability to make this determination on a timely basis and to provide notice in advance of scheduling deadlines and they shall not be liable in any manner for failure to provide advance notice under this paragraph or for changes in operating conditions that impact on anticipated availability of transmission capacity.

5.2

For any hour that the NU Companies incur an Opportunity Cost pursuant to this Appendix B of Schedule HQ-STF and NUSCO determines that the Opportunity Cost would not have been incurred if the NU Companies were not providing Hydro-Quebec Facilities Short-Term Firm Point-To-Point Transmission Service to the Transmission Customer, NUSCO shall be obligated to notify the Transmission Customer within one month of the date on which it had knowledge of the incurrence of the Opportunity Costs. In the event that the then calculated cumulative Opportunity Costs exceed the cumulative charges previously billed to the Transmission Customer for Embedded Costs or Opportunity Costs pursuant to Section I. of Schedule HQ-STF, NUSCO may render an immediate billing adjustment.

5.3

All claims for Opportunity Costs shall be accompanied by a written statement or other documentation: (i) showing that the Opportunity Costs were incurred; (ii) showing the calculation for the Opportunity Costs incurred and claimed; and (iii) showing that the Opportunity Costs would not have been incurred in the absence of the transaction being charged. If the Transmission Customer, in good faith, disputes NUSCO's claim for Opportunity Costs, such dispute must be made within a ninety (90) day period following the end of the Service Year for which the Opportunity Costs were claimed by NUSCO.

5.4

The NU Companies shall have the right, at any time, unilaterally to file for a change in any of the provisions of this Appendix B of Schedule HQ-STF in accordance with Section 205 of the Federal Power Act and the Commission's implementing regulations.

SCHEDULE HQ-NF

Non-Firm Point-To-Point Hydro-Quebec Facilities

Direct Current Transmission Service

CHARGE PROVISIONS

I.

NUSCO shall bill the Transmission Customer for Hydro-Quebec Facilities Non-Firm Point-To-Point Transmission Service, and the Transmission Customer shall be obligated to pay to NUSCO the charges as set forth in this Schedule HQ-NF as applicable.

A.

TRANSMISSION CHARGE

1.

General

The Transmission Customer shall pay to NUSCO each month the sum of the Transmission Charges calculated for all of its monthly Transactions, weekly Transactions, daily Transactions and hourly Transactions, each as set forth below.

With respect to any wholesale transactions that involve an exchange, each party to such Transaction shall be an individual Transmission Customer under the Tariff. Accordingly, a Transmission Charge, as applicable, will be calculated for, and a separate bill will be rendered to, each such Transmission Customer.

2.

Hydro-Quebec Facilities Non-Firm Point-To-Point Transmission Service For Monthly Transactions

The Transmission Charge for each month applicable to a monthly Transaction shall be determined as the product of: (a) the rate posted on NU's Open Access Same-Time Information System ("OASIS") at the time the service is reserved, not to exceed the NU Companies' Annual Rate for Hydro-Quebec Facilities Non-Firm Point-To-Point Transmission Service divided by twelve (12) months and (b) the Reserved Capacity set forth in the Transmission Customer's applicable Reservation for such month, expressed in kilowatts.

3.

Hydro-Quebec Facilities Non-Firm Point-To-Point Transmission Service For Weekly Transactions

The Transmission Charge for each month applicable to weekly Transactions shall be the sum of the transmission charges determined for each weekly Transaction during such month. The transmission charge for each weekly Transaction shall be determined as the product of: (a) the rate posted on the NU Companies’ OASIS at the time the service is reserved, not to exceed the NU Companies' Weekly Hydro-Quebec Facilities Firm Point-To-Point Transmission Charge Rate (expressed in $ per kilowatt-week), and (b) the Reserved Capacity set forth in the Transmission Customer's applicable Reservation for such week (expressed in kilowatts). The NU Companies' Weekly Rate is the NU Companies' Annual Rate for Hydro-Quebec Facilities Non-Firm Point-To-Point Transmission Service divided by fifty-two (52) weeks.

4.

Hydro-Quebec Facilities Non-Firm Point-To-Point Transmission Service For Daily Transactions

The Transmission Charge for each month applicable to daily Transactions will be the sum of the transmission charges determined for each daily Transaction. The transmission charge for each daily Transaction shall be determined as the product of: (a) the rate posted on the NU Companies’ OASIS at the time the service is reserved, not to exceed the NU Companies' Daily Hydro-Quebec Facilities Firm Point-To-Point Transmission Charge Rate (expressed in $ per kilowatt-day), and (b) the Reserved Capacity set forth in the Transmission Customer's applicable Reservation for such day (expressed in kilowatts). The NU Companies' On-Peak Daily Rate is the Companies' Weekly Rate for Hydro-Quebec Facilities Non-Firm Point-To-Point Transmission Service ÷ five (5) days. The NU Companies' Off-Peak Daily Rate is the NU Companies' Weekly Rate for Hydro-Quebec Facilities Non-Firm Point-To-Point Transmission Service ÷ seven (7) days. The total of the charges for daily Transactions, under an individual Reservation, in a seven (7) day period shall not exceed the charges based on the Weekly Rate and the maximum Reserved Capacity in the period.

5.

Hydro-Quebec Facilities Non-Firm Point-To-Point Transmission Service For Hourly Transactions

The Transmission Charge for each month applicable to hourly Transactions will be the sum of the transmission charges determined for each hourly Transaction. The transmission charge for each hour of an hourly Transaction shall be determined as the product of: (a) the rate posted on the NU Companies’ OASIS at the time the service is reserved, not to exceed the NU System Companies' Daily Hydro-Quebec Facilities Firm Point-To-Point Transmission Service Rate ÷ sixteen (16) hours (expressed in $ per kilowatt-hour), and (b) the Reserved Capacity as set forth in the Transmission Customer's applicable Reservation for such hour (expressed in kilowatts).  The NU Companies' Hourly On-Peak Rate is equal to the NU Companies' Daily Rate for Hydro-Quebec Facilities Non-Firm Transmission Service ÷ sixteen (16) hours. The NU Companies' Hourly Off-Peak Rate is equal to the NU Companies' Daily Rate for Hydro-Quebec Facilities Non-Firm Transmission Service divided by twenty-four (24) hours. The total of the charges for hourly Transactions, under an individual Reservation, in a twenty-four (24) hour period shall not exceed the charges based on the Daily Rate and the maximum Reserved Capacity in the period.

6.

Discounts

Three principal requirements apply to discounts for transmission service as follows: (1) any offer of a discount made by the NU Companies 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 NU Companies 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 Transmission System.

7.

Credit to the Transmission Charge

Whenever service provided hereunder is interrupted or curtailed by the NU Companies, the Local Control Center or the ISO, the Transmission Charges to the Transmission Customer calculated pursuant to Sections A.1 through 5, of this Schedule HQ-NF shall be

credited by an amount equal to the sum of the credits calculated for each hour of interruption or curtailment in service. The credit to the Transmission Customer for each such hour of interruption or curtailment shall be calculated as the product of (i) the applicable equivalent hourly charge for hourly, daily, weekly, or monthly Transactions, and (ii) the kilowatts of service interruption or curtailment during such hour.

8.

NU Companies' Annual Formula Rate for Hydro-Quebec Facilities Non-Firm Point-To-Point Transmission Service

The NU Companies' Annual Formula Rate for Hydro-Quebec Facilities Non-Firm Point-To-Point Transmission Service shall be expressed in $ per kilowatt-year and shall be determined in accordance with the rate formula specified in Appendix A of this Schedule HQ-NF ("Formula Rate"), being applied to the costs recorded on each of the NU Companies' books of account (i.e., FERC Form 1).  The Formula Rate shall be determined on the basis of estimated costs for each year until the actual NU Companies' costs for such year are determined. Thereafter, payments made on such estimate shall be recalculated based on actual data for that year, and an appropriate billing adjustment shall be made pursuant to Section 7 of the Tariff.

9.

Tax Rates and Taxes

The Formula Rate set forth in this Schedule HQ-NF in effect during a Service Year shall be based on local, state, and federal tax rates and taxes in effect during the prior year. If, at any time, additional or new taxes are imposed on the NU Companies or existing taxes are removed, the Formula Rate will be appropriately modified and filed with the Commission in accordance with Part 35 of the Commission's regulations.

II.

In addition to the applicable charges set forth in Parts I and II of the Tariff, and as otherwise specified in the Service Agreement, the Transmission Customer shall pay NUSCO each month the following additional charges for Hydro-Quebec Facilities Non-Firm Point-To-Point Transmission Service provided during such month.

A.

Taxes and Fees Charge

B.

Regulatory Expenses Charge

C.

Other

A.

TAXES AND FEES CHARGE

If any governmental authority requires the payment of any fee or assessment or imposes any form of tax with respect to payments made for Hydro-Quebec Facilities Non-Firm Point-To-Point Transmission Service provided under the Tariff, not specifically provided for in any of the charge or rate provisions under the Tariff, including any applicable interest charged on any deficiency assessment made by the taxing authority, together with any further tax on such payments, the obligation to make payment for such fee, assessment, or tax shall be borne by the Transmission Customer. The NU Companies will make a separate filing with the Commission for recovery of any such costs in accordance with Part 35 of the Commission's regulations.

B.

REGULATORY EXPENSES

The NU Companies reserve their rights to make a Section 205 filing for recovery of their costs to administer the Tariff and the Service Agreements.

C.

OTHER

The NU Companies shall have the right, at any time, unilaterally to file for a change in any of the provisions of this Schedule HQ-NF in accordance with Section 205 of the Federal Power Act and the Commission's implementing regulations.

SCHEDULE HQ-NF

Appendix A

DETERMINATION OF

THE NU COMPANIES' FORMULA RATE

FOR HYDRO-QUEBEC FACILITIES

NON-FIRM POINT-TO-POINT TRANSMISSION SERVICE

The NU Companies' Formula Rate for Hydro-Quebec Facilities Non-Firm Point-To-Point

                                        A_i1 - B _i1

                                    _________

Formula Rate_{i   =}                         C _i1

Transmission Service ("Formula Rate") is an annual rate determined from the following formula.

WHERE:

•

i equals the calendar year during which service is being rendered ("Service Year").

•

Ai-1 is the Annual Cost (expressed in dollars) of the Hydro-Quebec Facilities of the NU Companies for the calendar year prior to the Service Year. The Annual Revenue Requirements are    determined pursuant to the formula specified in Exhibit 1 to this Appendix A of Schedule HQ-NF.

•

Bi-1 is the actual transmission revenues (expressed in dollars) provided from the provision of transmission services over the Hydro-Quebec Facilities to others. The actual transmission revenues shall be those recorded on the books of the NU Companies in FERC Account Nos. 447 and 456 pertaining to Transmission of Electricity for Others and such other applicable FERC Account for the calendar year prior to the Service Year.

•

Ci-1 is the average of the NU Companies’ monthly peak load (expressed in kilowatts of its share of the Hydro-Quebec Facilities of the NU Companies, for the calendar year prior to the Service Year, as reported in FERC Form No. 1.

SCHEDULE HQ-NF

Appendix A

Exhibit 1

DETERMINATION OF ANNUAL TRANSMISSION REVENUE REQUIREMENTS

The Annual Transmission Cost for the NU Companies' Hydro-Quebec Facilities are the costs assessed by each of them in owning, operating, maintaining, and supporting those facilities, plus any applicable leasing costs and an allocable share of General Plant and other such plant and equipment. These costs shall be computed on a calendar-year basis using costs, from the calendar year prior to the Service Year.

In making such determinations, the provisions of the Uniform System of Accounts prescribed by FERC for Class A and Class B Public Utilities and Licensees shall be controlling.

The rate formula for determination of the annual revenue requirements for the Hydro-Quebec Facilities of the NU Companies are determined pursuant this Appendix A of Schedule HQ-NF, as follows:

A.

ANNUAL REVENUE REQUIREMENTS = Sum of [each NU Companies' Hydro-

Quebec Facilities transmission costs-Chster Static VAR Compensator].

ATTACHMENT HQ-NETWORK

Charge Provisions For Hydro-Quebec Facilities Network Integration Transmission Service

I.

CHARGES FOR HYDRO-QUEBEC FACILITIES FOR NETWORK TRANSMISSION SERVICE

A.

DEMAND CHARGE

1.

Determination of Demand Charge

The Demand Charge will be determined in accordance with Section 34.1 of the Tariff.

2.

NU Companies' Annual Transmission Cost

The annual Transmission Cost shall be determined in accordance with the rate formula specified in Appendix A of this Attachment HQ-NETWORK ("Formula Requirement"), being applied to the costs recorded on each of the NU Companies' books of accounts (i.e., FERC Form 1). The Formula Requirement shall be determined on the basis of estimated costs for each year until the actual NU Companies' costs for such year are determined.  Thereafter, payments made on such estimate shall be recalculated based on actual data for that year, and an appropriate billing adjustment shall be made pursuant to Section 7 of the Tariff.

B.

TAX RATES AND TAXES

The Formula Costs set forth in this Attachment HQ-NETWORK in effect during a Service Year shall be based on local, state, and federal tax rates and taxes in effect during the prior year. If, at any time, additional or new taxes are imposed on the NU Companies or existing taxes are removed, the Formula Requirements will be appropriately modified and filed with the Commission in accordance with Part 35 of the Commission's regulations.

II.

In addition to the applicable charges set forth in Parts I and III of the Tariff, and as otherwise specified in the Service Agreement, the Transmission Customer shall pay to NUSCO each month the following additional charges for Hydro-Quebec Facilities Network Transmission Service provided during such month.

A.

Taxes and Fees Charge

B.

Regulatory Expenses Charge

C.

Other

A.

TAXES AND FEES CHARGE

If any governmental authority requires the payment of any fee or assessment or imposes any form of tax with respect to payments made for service provided under the Tariff, not specifically provided for in any of the charge or rate provisions under the Tariff, including any applicable interest charged on any deficiency assessment by the taxing authority, together with any further tax on such payments, the obligation to make payment for any such fee, assessment, or tax shall be borne by the Transmission Customer. The NU Companies will make a separate filing with the Commission for recovery of any such costs in accordance with Part 35 of the Commission's regulations.

B.

REGULATORY EXPENSES CHARGE

The NU Companies shall have the right to make a Section 205 filing for recovery of regulatory expenses associated with the Tariff and the Service Agreements.

C.

OTHER

The NU Companies shall have the right, at any time, unilaterally to file for a change in any of the provisions of this Attachment HQ-NETWORK in accordance with Section 205 of the Federal Power Act and the Commission's implementing regulations.

ATTACHMENT HQ-NETWORK

Appendix A

DETERMINATION OF

THE NU COMPANIES'

HYDRO-QUEBEC FACILITIES

NETWORK FORMULA REQUIREMENTS

FOR TRANSMISSION SERVICE

The NU Companies' formula requirements for Hydro-Quebec Facilities Network Transmission

Formula Requirements   ₌ A_i1 - B _i1

Service is determined from the following formula.

WHERE:

•

i equals the calendar year during which service is being rendered ("Service Year").

•

Ai-1 is the Annual Cost (expressed in dollars) of the Hydro-Quebec Facilities of the NU Companies for the calendar year prior to the Service Year. The Annual Revenue Requirements are determined pursuant to the formula specified in Exhibit 1 to this Appendix A of Attachment HQ-NETWORK.

•

Bi-1 is the actual transmission revenues (expressed in dollars) provided from the provision of transmission services over the Hydro-Quebec Facilities to others. The actual transmission revenues shall be those recorded on the books of the NU Companies in FERC Account Nos. 447 and 456 pertaining to Transmission of Electricity for Others and such other applicable FERC Account for the calendar year prior to the Service Year.

ATTACHMENT HQ-NETWORK

Appendix A

Exhibit 1

DETERMINATION OF ANNUAL TRANSMISSION COSTS

The Annual Transmission Costs for the NU Companies' Hydro-Quebec Facilities are the costs assessed by each of them in owning, operating, maintaining, and supporting those facilities, plus any applicable leasing costs and an allocable share of General Plant and other such plant and equipment. These costs shall be computed on a calendar-year basis using costs, from the calendar year prior to the Service Year.

In making such determinations, the provisions of the Uniform System of Accounts prescribed by FERC for Class A and Class B Public Utilities and Licensees shall be controlling.

The rate formula for determination of the annual Costs for the Hydro-Quebec Facilities of the NU Companies are determined pursuant to this Appendix A of Attachment HQ-NETWORK, as follows:

A.

ANNUAL REVENUE REQUIREMENTS = Sum of [each NU Companies' Hydro-Quebec Facilities transmission costs -Chester Static VAR Compensator costs].

-----------------------------------------------------------------------------------------------------------------------------

<FN>

<FN1>  Excludes MWs associated with lump sum payment transactions identified in footnote 2.

<FN2>  Includes amortization of revenues from point-to-point transmission service provided to Consolidated Edison Energy Massachusetts, Inc. and NRG Energy, Inc. under contracts in which customers paid based on single lump sum payment.

<FN3>  Includes amortization of revenues from point-to-point transmission service provided to Consolidated Edison Energy Massachusetts, Inc. and NRG Energy, Inc. under contracts in which customers paid based on single lump sum payment.

<FN4>  Includes amortization of revenues from point-to-point transmission service provided to Consolidated Edison Energy Massachusetts, Inc. and NRG Energy, Inc. under contracts in which customers paid based on single lump sum payment.

</FN>

-----------------------------------------------------------------------------------------------------------------------------

EX-12

Ratio of Earnings to Fixed Charges					Exhibit 12
(In thousands)
	Year Ended	Year Ended	Year Ended	Year Ended	Year Ended
Earnings, as defined:	December 31, 2005	December 31, 2004	December 31, 2003	December 31, 2002	December 31, 2001
Net (loss)/income from continuing operations before
extraordinary item and cumulative effect of
accounting change	$             (229,223)	$              112,995	$              116,434	$              148,529	$              265,942
Income tax (benefit)/expense	(162,765)	50,728	47,628	72,682	173,952
Equity in earnings of regional nuclear
generating and transmission companies	(3,311)	(2,592)	(4,487)	(11,215)	(3,970)
Dividends received from regional equity investees	687	3,879	8,904	11,056	7,060
Fixed charges, as below	294,525	271,948	264,822	290,590	304,663
Interest capitalized (not including AFUDC)	(395)	(600)	(1,058)	(2,085)	(684)
Preferred dividend security requirements of
consolidated subsidiaries	(9,265)	(9,265)	(9,265)	(9,265)	(12,082)
Total (loss)/earnings, as defined	$             (109,747)	$              427,093	$              422,978	$500,292	$734,881
Fixed charges, as defined:
Interest on long-term debt	$              163,012	$              139,988	$              121,887	$              134,471	$              140,497
Interest on rate reduction bonds	87,439	98,899	108,359	115,791	87,616
Other interest	19,350	8,610	10,333	16,998	51,545
Rental interest factor	7,145	7,433	7,667	5,433	7,033
Amortized premiums, discounts and
capitalized expenses related to indebtedness	7,919	7,153	6,253	6,547	5,206
Preferred dividend security requirements of
consolidated subsidiaries	9,265	9,265	9,265	9,265	12,082
Interest capitalized (not including AFUDC)	395	600	1,058	2,085	684
Total fixed charges, as defined	$              294,525	$              271,948	$              264,822	$              290,590	$              304,663
Ratio of Earnings to Fixed Charges - Pro Forma	(0.37)	1.57	1.60	1.72	2.41

EX-13

Exhibit 13

Management’s Discussion and Analysis

Financial Condition and Business Analysis

Following items in this executive summary are explained in more detail in this annual report.

Strategy, Results and Outlook:

·

In 2005, Northeast Utilities (NU or the company) recorded losses of $253.5 million, or $1.93 per share.  Those results included net income after payment of preferred dividends of $163.4 million, or $1.24 per share, at the regulated Utility Group businesses and losses of $398.2 million, or $3.03 per share, at the competitive NU Enterprises businesses.  

·

On March 9, 2005, NU announced that NU Enterprises would exit its wholesale marketing business and its energy services businesses.  On November 7, 2005, NU announced its decision to exit the remainder of NU Enterprises' competitive businesses, which includes the retail marketing and competitive generation businesses.  NU expects that exiting the NU Enterprises businesses will benefit shareholders by producing a company with a simpler, lower risk business model, and with more predictable financial results and cash flows.  NU expects to use the net proceeds from exiting the NU Enterprises businesses to reduce debt and make equity investments in the Utility Group businesses.  

·

The NU Enterprises 2005 losses of $398.2 million included a net negative after-tax mark-to-market charge of $278.9 million on wholesale energy contracts and after-tax restructuring and impairment charges of $27.3 million.    

·

Included in these negative mark-to-market charges, in 2005 NU Enterprises paid or agreed to pay approximately $242 million to exit all of its New England wholesale energy contracts.  Of the approximately $242 million, in 2005 approximately $186 million was paid.  Also in 2005, NU Enterprises sold two of its energy services businesses for a total of $6.5 million and part of another energy services business in January of 2006 for approximately $2 million.

·

Utility Group 2005 earnings increased by $7.8 million or 5 percent as a result of higher transmission business earnings due to a higher level of investment, retail distribution rate increases at all four regulated companies and a 2.6 percent increase in regulated retail electric sales in 2005.  These results were offset by after-tax employee termination and benefit plan curtailment charges totaling $12.3 million, higher pension, depreciation, and interest expense.    

·

NU expects the Utility Group to invest up to $4.3 billion in its electric transmission and distribution and natural gas distribution businesses from 2006 through 2010.  NU estimates that when it successfully meets this goal, it will achieve significant compounded annual regulated rate base growth through 2010.  After accounting for the dilutive impact of projected issuances of additional common shares beyond 2007 and parent company expenses, the company expects such rate base growth, assuming appropriate regulatory actions, to result in regulated earnings per share growth of between 8 percent and 10 percent annually beginning with 2007.

·

NU projects that 2006 combined earnings for the Utility Group and parent company will be between $1.09 per share and $1.22 per share.  NU is not providing consolidated earnings guidance or guidance for NU Enterprises due to the uncertainty of any potential financial impacts of exiting its competitive businesses.  

Legislative and Legal Items:

·

On July 6, 2005, Connecticut adopted legislation creating a mechanism to true-up annually the retail transmission charge in local electric distribution company rates.  In accordance with this legislation, effective January 1, 2006, The Connecticut Light and Power Company (CL&P) raised its retail transmission rate to collect $21 million of additional revenues over the first six months of 2006.

·

On July 22, 2005, Connecticut also adopted legislation that provides local electric distribution companies, including CL&P, with financial incentives to promote construction of distributed generation.  The Connecticut Department of Public Utility Control (DPUC) is conducting a number of new dockets to implement this legislation.

·

On August 8, 2005, President Bush signed into law comprehensive federal energy legislation with several provisions affecting NU.   As part of this legislation, the Public Utility Holding Company Act of 1935 (PUHCA) was repealed.  Some but not all of the Securities and Exchange Commission's (SEC) responsibilities under PUHCA were transferred to the Federal Energy Regulatory Commission (FERC).  

·

In an opinion dated October 12, 2005, a panel of three judges at the United States Court of Appeals for the Second Circuit (Court of Appeals) held that the shareholders of NU had no right to sue Consolidated Edison, Inc. (Con Edison) for its alleged breach of the parties' Merger Agreement.  NU's request for rehearing was denied on January 3, 2006.  This ruling left intact the remaining claims between NU and Con Edison for breach of contract, which include NU's claim for recovery of costs and expenses of approximately $32 million and Con Edison's claim for damages of "at least $314 million."  NU is currently considering whether to seek review by the United States Supreme Court.  At this stage, NU cannot predict the outcome of this matter or its ultimate effect on NU.  

·

In November of 2005, Public Service Company of New Hampshire (PSNH) and various legislative, state government and environmental leaders announced that they had reached a consensus to propose legislation to reduce the level of mercury emissions from PSNH’s coal-fired plants by

2013 with incentives for early reductions.  As part of the proposed legislation, PSNH's primary long-term alternative to comply with the proposed legislation would be to install wet scrubber technology at its two Merrimack coal units, which combined generate 433 megawatts (MW), at a cost of approximately $250 million.  The proposed legislation is being considered during the 2006 legislative session.

·

The Regional Greenhouse Gas Initiative (RGGI) agreement, signed on December 20, 2005, is a cooperative effort by the states of Connecticut, Delaware, Maine, New Jersey, New Hampshire, New York, and Vermont, to develop a regional program for stabilizing current levels and ultimately reducing carbon dioxide (CO2) emissions by ten percent by 2020 from fossil-fired electric generators.  RGGI may impact PSNH’s Merrimack, Newington and Schiller stations.  At this time, the impact of this agreement on NU cannot be determined.

Regulatory Items:

·

Each of NU's Utility Group regulated electric companies, CL&P, PSNH and Western Massachusetts Electric Company (WMECO), has received regulatory approvals to recover the increased cost of energy being supplied to their customers in 2006.  These increased costs are primarily the result of new solicitations from the market.

·

PSNH’s 2004 stranded cost recovery charge (SCRC) reconciliation filing was filed with the New Hampshire Public Utilities Commission (NHPUC) on May 2, 2005.  In October of 2005, PSNH, the NHPUC staff and the New Hampshire Office of Consumer Advocate (OCA) reached a settlement agreement in this case.  This settlement agreement was approved by the NHPUC on December 22, 2005.  That settlement agreement also recommended that the NHPUC staff engage a coal procurement expert to analyze PSNH’s coal procurement and transportation operations.  Consistent with the settlement agreement, the NHPUC deferred action on coal-related costs until that analysis has been completed.

·

On September 9, 2005 the DPUC issued a draft decision regarding Yankee Gas Services Company (Yankee Gas) Purchased Gas Adjustment (PGA) clause charges for the period of September 1, 2003 through August 31, 2004.  The draft decision disallowed approximately $9 million in previously recovered PGA revenues associated with two separate Yankee Gas unbilled sales and revenue adjustments.  At the request of Yankee Gas, the DPUC reopened the PGA hearings on September 20, 2005 and requested that Yankee Gas file supplemental information regarding the two adjustments.  Yankee Gas complied with this request.  The remaining schedule for the proceeding has not yet been established.

·

On December 1, 2005, NU filed at the FERC a request to include 50 percent of construction work in progress (CWIP) for its four major southwest Connecticut transmission projects in its formula rate for transmission service.  The FERC approved the filing with the new rates, including the CWIP, effective on February 1, 2006.  The new rates allow NU to collect 50 percent of the construction financing expenses while these projects are under construction.  

·

On December 1, 2005, WMECO made its 2006 annual rate change filing implementing the $3 million distribution revenue increase allowed under its rate case settlement agreement.  WMECO requested that this change become effective on January 1, 2006.  On December 29, 2005, the Massachusetts Department of Telecommunications and Energy (DTE) approved rates reflecting the $3 million distribution revenue increase as well as increases for new basic service supply.

·

On December 2, 2005, the NHPUC issued an order to rehear the order that lowered the return on equity (ROE) on PSNH’s generating facilities to 9.62 percent from 11 percent effective August 1, 2005.  On January 3, 2006, PSNH appealed the revised decision to the New Hampshire Supreme Court and simultaneously asked the NHPUC for reconsideration of its decision.  The appeal before the New Hampshire Supreme Court is pending.  On February 10, 2006, PSNH's most recent request for reconsideration by the NHPUC was denied.  

·

On December 23, 2005, the DPUC denied Yankee Gas' request for interim rate relief of $12.4 million on the grounds that the prerequisite circumstances of the settlement agreement had not been met.  Management expects to file a rate case in late 2006 that would be effective the earlier of July 1, 2007 or the date the Waterbury liquefied natural gas (LNG) facility enters service.  Management expects Yankee Gas to earn below its allowed ROE until the next rate case goes into effect.  Management has also begun to take steps to reduce Yankee Gas' nonfuel operation and maintenance costs by combining certain operations of Yankee Gas and CL&P.  

·

A final decision in the 2004 Competitive Transition Assessment (CTA) and System Benefits Charge (SBC) docket was issued on December 19, 2005 by the DPUC.  In a subsequent decision in CL&P’s docket to establish the 2006 transitional standard offer (TSO) rates dated December 28, 2005, the DPUC ordered CL&P to issue a revised CTA refund of $108 million over the twelve-month period beginning with January 2006 consumption and an additional CTA refund of $40 million for the months of January, February and March of 2006.

·

On March 6, 2006, the New England Independent System Operator (ISO-NE) and a broad cross-section of critical stakeholders from around the region, including CL&P, PSNH and Select Energy, filed a comprehensive settlement agreement at the FERC implementing a Forward Capacity Market in place of Locational Installed Capacity (LICAP).  The settlement agreement must be approved by the FERC, and the parties have asked for a decision by June 30, 2006.

Liquidity:

·

Exiting the competitive generation and retail marketing businesses is expected to benefit NU’s liquidity and reduce debt.  The net proceeds from NU Enterprises' competitive generation asset sales are expected to be an important factor in NU’s financing plans.  

·

On October 28, 2005, the SEC approved NU’s application to increase its authorized borrowing limit from $450 million to $700 million.  On December 9, 2005, NU parent also increased its revolving credit arrangement from $500 million to $700 million and extended its termination date by one year to November 6, 2010.  A separate $400 million Utility Group company revolving credit facility was also extended by one year to November 6, 2010.

·

On November 2, 2005, NU arranged a separate $600 million unsecured credit facility that supplements other sources of liquidity.  That facility was reduced to $310 million in December of 2005 after the issuance of $425 million of NU common shares and the increase in the NU parent and Utility Group revolving credit arrangements was completed.  

·

On December 12, 2005, NU received net proceeds of approximately $425 million from the sale of 23 million NU common shares.  These proceeds were used to reduce short-term debt and will be used in the future to continue to contribute common equity to the Utility Group companies.

·

In 2005, NU Enterprises paid approximately $186 million to exit all of its New England wholesale sales arrangements through cash on hand and cash provided by borrowings under the NU parent $500 million revolving credit arrangement.

·

In 2005, the Utility Group companies issued $350 million of first mortgage bonds and senior notes with maturities ranging from 10 years to 30 years, the proceeds from which were used to repay short-term borrowings used to finance capital expenditures.

·

In 2005, NU’s capital expenditures totaled $775.4 million compared with $671.5 million in 2004.  The increased level of capital expenditures was caused primarily by a need to continue to improve the capacity and reliability of NU’s regulated transmission system.  

·

Cash flows from operations decreased by $19.4 million to $441.2 million in 2005 from $460.6 million in 2004.

Overview

Consolidated:  NU lost $253.5 million, or $1.93 per share, in 2005, compared with earnings of $116.6 million, or $0.91 per share, in 2004, and $116.4 million, or $0.91 per share, in 2003.  Earnings per share in 2004 and 2003 are reported on a fully diluted basis and the weighted average common shares outstanding at December 31, 2005 include the impact of the issuance of 23 million NU common shares on December 12, 2005 which were outstanding for 20 days in 2005.  The 2005 loss reflects losses of $398.2 million, or $3.03 per share, at NU Enterprises, the holding company for NU’s competitive businesses, and earnings of $163.4 million, or $1.24 per share, at NU’s regulated Utility Group companies.  In 2005, NU also had $18.7 million, or $0.14 per share, of parent company and other expense, compared with $23.9 million, or $0.18 per share, in 2004 and $12.7 million, or $0.10 per share, in 2003.  NU's 2005 losses a lso include after-tax employee termination and benefit plan curtailment charges totaling $15 million.  

The losses at NU Enterprises reflect decisions announced in 2005 to exit all of its competitive business lines.  As a result of those decisions, NU Enterprises recorded $306.2 million of after-tax restructuring and impairment and mark-to-market charges, primarily on wholesale electric marketing sales contracts.  In 2005, NU Enterprises exited all of its wholesale sales obligations in New England.  NU Enterprises still has below-market wholesale obligations in the New York power pool through 2013 and Pennsylvania-New Jersey-Maryland (PJM) power pool through 2008, all of which were marked-to-market in 2005.  Those positions will continue to create volatility in NU’s quarterly earnings until the contracts expire or are exited.

NU’s 2004 results included an after-tax loss of $48.3 million associated with mark-to-market accounting for certain natural gas positions established to mitigate the risk of electricity purchased in anticipation of winning certain levels of wholesale electric load in New England.  NU's 2004 results also included after-tax investment write-downs of approximately $8.8 million, which is included in the $23.9 million.

A summary of NU’s (losses)/earnings by major business line for 2005, 2004 and 2003 is as follows:

	For the Years Ended December 31,
(Millions of Dollars)	2005	2004	2003
Utility Group	$  163.4	$155.6	$132.5
NU Enterprises (1)	(398.2)	(15.1)	(3.4)
Parent and Other	(18.7)	(23.9)	(12.7)
Net (Loss)/Income	$(253.5)	$116.6	$116.4

(1)

The NU Enterprises losses include losses totaling $23.3 million for the year ended December 31, 2005 and earnings totaling $3.6 million and $4.7 million for the years ended December 31, 2004 and 2003, respectively, which are classified as discontinued operations.

In 2005, NU announced decisions to exit all of its competitive businesses.  NU expects that exiting the NU Enterprises businesses will benefit shareholders by producing a company with a simpler, lower risk business model, and with more predictable financial results and cash flows.  In 2005, those businesses accounted for approximately $2 billion of NU's revenues of $7.4 billion.  At December 31, 2005, these businesses also accounted for $2.4 billion of NU's total assets.  NU Enterprises is comprised of two business segments:  the merchant energy business segment, which includes the

wholesale marketing, retail marketing and competitive generation businesses, and the energy services business segment.  In 2005, in addition to exiting all of its New England wholesale sales obligations, NU Enterprises sold two of its six energy services businesses for approximately $6.5 million and part of another energy services business in January of 2006 for approximately $2 million.  NU Enterprises expects to complete the sale of all its remaining competitive businesses in 2006.  The net proceeds from these sales will be used to reduce debt and make equity investments in the Utility Group companies.

For the Utility Group, NU segments its earnings between its transmission and distribution businesses with regulated generation included in the distribution business.  The electric transmission business earned $42.5 million, or $0.32 per share, in 2005, compared with earnings of $29.5 million, or $0.23 per share, in 2004, and $28.2 million, or $0.22 per share, in 2003.  The higher level of earnings was due primarily to a return on a higher level of transmission investment at CL&P.  In 2005, the electric distribution and regulated generation companies earned $103.6 million, or $0.79 per share, compared with earnings of $112 million, or $0.87 per share, in 2004 and $97 million, or $0.76 per share, in 2003.  Distribution company results in 2005 were primarily affected by rate increases implemented at CL&P, PSNH and WMECO in 2005.  Those increases were more than offset by higher operation, interest and depreciation costs at CL &P and PSNH.  Yankee Gas earned $17.3 million, or $0.13 per share, in 2005, compared with earnings of $14.1 million, or $0.11 per share, in 2004, and $7.3 million, or $0.06 per share, in 2003.  Improved 2005 Yankee Gas results were primarily due to a $14 million base rate increase implemented on January 1, 2005.

NU’s consolidated revenues increased to $7.4 billion in 2005 from $6.5 billion in 2004 and $5.9 billion in 2003.  Utility Group revenues totaled $5.5 billion in 2005, compared with $4.6 billion in 2004, and $4.3 billion in 2003.  Higher regulated revenues are primarily caused by higher fuel and energy costs which are passed through to customers.  NU Enterprises revenues totaled $2 billion before eliminations in 2005, compared with $2.7 billion in 2004 and $2.5 billion in 2003.  The lower 2005 NU Enterprises revenues reflect lower wholesale electric sales.

NU's revenues during 2004 increased due to increased revenues from NU Enterprises primarily as a result of higher merchant energy retail sales volumes and higher prices.  The remainder of the increase in 2004 revenues related to higher Utility Group transmission and distribution revenues as a result of higher rates and higher revenues to recover federally mandated congestion charges (FMCC).  

Utility Group:  The Utility Group is comprised of CL&P, PSNH, WMECO, and Yankee Gas, and is comprised of their transmission, distribution and generation businesses.  The Utility Group earned $163.4 million in 2005, or $1.24 per share, compared with $155.6 million, or $1.21 per share, in 2004 and $132.5 million, or $1.04 per share, in 2003.  A summary of Utility Group earnings by company and business segment for 2005, 2004 and 2003 is as follows:

	For the Years Ended December 31,
(Millions of Dollars)	2005	2004	2003
CL&P Distribution	$ 58.6	$  62.7	$ 46.3
CL&P Transmission	30.7	19.8	17.1
Total CL&P*	89.3	82.5	63.4
PSNH Distribution and Generation	33.9	39.9	38.3
PSNH Transmission	7.8	6.7	7.3
Total PSNH	41.7	46.6	45.6
WMECO Distribution	11.1	9.4	12.4
WMECO Transmission	4.0	3.0	3.8
Total WMECO	15.1	12.4	16.2
Yankee Gas	17.3	14.1	7.3
Total Utility Group Net Income	$163.4	$155.6	$132.5

*After preferred dividends of $5.6 million in all years.

CL&P earned $89.3 million in 2005, compared with $82.5 million in 2004 and $63.4 million in 2003.  CL&P’s transmission results benefited from higher revenues due to earning on a higher level of investment.  The 2005 decline in CL&P’s distribution earnings to $58.6 million in 2005 from $62.7 million in 2004 resulted from after-tax employee termination and benefit plan curtailment charges totaling $8.5 million, the positive $6.9 million after-tax impact of a regulatory decision in 2004 concerning a 2003 rate case, a negative $2.5 million after-tax impact of a regulatory decision in 2005 concerning streetlighting refunds, and higher operation, interest and depreciation expenses, partially offset by a $25 million distribution rate increase that took effect January 1, 2005 and a 3 percent increase in retail electric sales.  The increase in CL&P's transmission earnings resulted primarily from increased investment in its transmission system.

PSNH earned $41.7 million in 2005, compared with $46.6 million in 2004 and $45.6 million in 2003.  PSNH's distribution and generation earnings in 2005 were lower primarily due to a lower ROE on the generation facilities in 2005 and higher interest and operating expenses, partially offset by delivery rate increases of $3.5 million in October of 2004 and $10 million in June of 2005.

WMECO earned $15.1 million in 2005, compared with $12.4 million in 2004 and $16.2 million in 2003.  Improved 2005 distribution results were due to a $6 million distribution rate increase that took effect on January 1, 2005, a 1.4 percent increase in retail electric sales and higher rate base earnings as a result of WMECO refinancing its prior spent nuclear fuel obligation, partially offset by higher operating and interest costs.

Yankee Gas earned $17.3 million in 2005, compared with $14.1 million in 2004 and $7.3 million in 2003.  Yankee Gas results benefited from a $14 million base rate increase and a reduction in depreciation expense, both of which resulted from a 2004 rate settlement and were effective January 1, 2005.

The Utility Group's retail electric sales were positively impacted by weather in 2005, particularly by an unseasonably hotter than average third quarter of 2005, which increased electricity consumption.  Overall, retail kilowatt-hour electric sales increased 2.6 percent in 2005, but decreased by 0.1 percent on a weather adjusted basis.  Residential sales increased 4.4 percent, or 0.7 percent on a weather adjusted basis while commercial sales increased 3.6 percent, or 1.4 percent on a weather adjusted basis, and industrial sales decreased 4 percent, or 5.5 percent on a weather adjusted basis as a result of the increase in energy costs, business closings and the installation of cogeneration equipment.    

For the Utility Group, a summary of changes in retail electric sales for 2005 as compared to 2004 is as follows:

	Percentage Increase/(Decrease)	Weather Adjusted Percentage Increase/(Decrease)
CL&P	3.0%	0.1%
PSNH	1.9%	(0.2)%
WMECO	1.4%	(0.8)%

As noted above, when adjusted for the weather, retail kilowatt-hour electric sales were virtually unchanged from 2004 to 2005.  With commodity-driven rate increases taking effect early in 2006 and the weather being much milder to date in 2006, management is concerned that actual sales could be lower in 2006 than in 2005.  While sales volume does not affect transmission business earnings positively or negatively, lower electric and natural gas sales do negatively affect distribution company earnings.

NU Enterprises:   During 2005, NU Enterprises was the parent of Select Energy, Inc. (Select Energy), Select Energy Services, Inc. (SESI) and its subsidiaries, Northeast Generation Company (NGC), Northeast Generation Services Company (NGS) and its subsidiaries, E.S. Boulos Company (Boulos) and Woods Electrical Co., Inc. (Woods Electrical), Woods Network Services, Inc. (Woods Network), and Select Energy Contracting, Inc. (SECI), all of which are collectively referred to as "NU Enterprises."  The generation operations of Holyoke Water Power Company (HWP), which is a direct subsidiary of NU, are also included in the results of NU Enterprises.  The companies included in the NU Enterprises segment are grouped into two business segments: the merchant energy business segment and the energy services business segment.  The merchant energy business segment is currently comprised of Select Energy’s wholesale market ing business, the competitive generation businesses which includes 1,296 MW of pumped storage and hydroelectric generation assets owned by NGC and 146 MW of coal-fired generation assets owned by HWP, Select Energy’s retail marketing business, and NGS.  The energy services businesses consist of SESI, Boulos, Woods Electrical, Woods Network, and SECI.  SESI, Select Energy Contracting - New Hampshire (SECI-NH), a division of SECI, Woods Electrical, and Woods Network are classified as discontinued operations.

In March of 2005, NU announced the exit from NU Enterprises' wholesale marketing business and the energy services businesses, and in November of 2005, announced the exit from NU Enterprises' retail marketing and competitive generation businesses.  In the fourth quarter of 2005, Woods Network and SECI-NH (including Reeds Ferry Supply Co., Inc. (Reeds Ferry)) were sold for a total of approximately $6.5 million.  In January of 2006, the Massachusetts service location of Select Energy Contracting - Connecticut (SECI-CT), a division of SECI, was sold for approximately $2 million.

NU Enterprises also exited all of its New England wholesale sales obligations by either buying out those contracts or assigning its obligations to third parties.  Most of these contracts were with municipal electric companies.  In 2005, NU Enterprises paid approximately $186 million to exit those obligations and agreed to pay another approximately $56 million.

NU Enterprises recorded a loss of $398.2 million in 2005, or $3.03 per share, compared with a loss of $15.1 million, or $0.12 per share, in 2004, and a loss of $3.4 million, or $0.03 per share, in 2003.  The 2005 loss was primarily due to a net after-tax charge of $278.9 million as a result of the marking-to-market of various wholesale contracts, including the approximately $186 million contract payment and the $56 million obligation noted above.  In 2004, NU Enterprises results included an after-tax loss of $48.3 million associated with mark-to-market accounting for certain natural gas positions established to mitigate the risk of electricity purchased in anticipation of winning certain levels of wholesale electric load in New England.  These positions were balanced by entering into offsetting positions in the first quarter of 2005 and had no impact on earnings since then.  

NU Enterprises 2005 results also reflect $43.7 million of after-tax restructuring and impairment charges related to both the merchant energy and the energy services businesses.  Those charges include $16.4 million associated with discontinued operations.  There were no impairment charges in 2004.

A summary of NU Enterprises’ (losses)/earnings for 2005, 2004, and 2003 is as follows:

	For the Years Ended December 31,
(Millions of Dollars)	2005	2004	2003
Merchant Energy	$(360.6)	$(17.3)	$(6.7)
Energy Services,     Parent and Other (1)	(37.6)	2.2	3.3
Total NU Enterprises Net Loss	$(398.2)	$(15.1)	$(3.4)

(1)

The energy services, parent and other losses include losses totaling $23.3 million for the year ended December 31, 2005 and earnings totaling $3.6 million and $4.7 million for the years ended December 31, 2004 and 2003, respectively, which are classified as discontinued operations.

The merchant energy business lost $360.6 million in 2005, compared with $17.3 million in 2004 and $6.7 million in 2003.  A significant number of charges impacted NU Enterprises’ merchant energy business results in 2005.  Extreme increases in gas and oil prices in 2005 negatively affected sale obligations which had not yet been exited.  

NU recorded $278.9 million of after-tax ($440.9 million pre-tax) wholesale contract market changes for the year ended December 31, 2005, related to changes in the fair value of wholesale contracts that the company is in the process of exiting.  The changes are comprised of the following items:  

·

A charge of $257.4 million after-tax ($406.9 million pre-tax) related to the mark-to-market of certain long-dated wholesale electricity contracts in New England and New York with municipal and other customers.  The charge reflects negative mark-to-market movements on these contracts through December 31, 2005 as a result of rising energy prices, partially offset by positive effects of buying out certain obligations in 2005 at prices less than their marks at the time;

·

A charge of approximately $50.6 million after-tax (approximately $80 million pre-tax) related to purchases of additional electricity for an increase in the load forecasts related to a full requirements contract with a customer in the PJM power pool;

·

A benefit of approximately $24 million after-tax (approximately $38 million pre-tax) related to mark-to-market gains on certain generation related contracts which the company is in the process of exiting;

·

A benefit of $37.9 million after-tax ($59.9 million pre-tax) for mark-to-market gains primarily related to retail supply contracts that were previously held by the wholesale business to serve certain retail electric load, which the company has exited or settled.  Included in the $37.9 million of after-tax gains ($59.9 million pre-tax) is $19 million of after-tax ($30 million pre-tax) gains related to retail supply contracts marked-to-market as a result of the March 9, 2005 decision to exit the wholesale marketing business.

·

A charge of $9.8 million after-tax ($15.5 million pre-tax) in the fourth quarter of 2005 in connection with the decision to exit the competitive generation business related to marking-to-market two contracts to sell the output of its generation in 2007 and 2008.  NU Enterprises is in the process of exiting these contracts.  These two generation sales contracts were formerly accounted for under accrual accounting; however, accrual accounting was terminated in the fourth quarter of 2005 due to the high probability that these contracts would be net settled instead of physically delivered.  

·

A charge of $23 million after-tax ($36.4 million pre-tax) for mark-to-market contract asset write-offs related to long-term wholesale electricity contracts and a contract termination payment in March of 2005.

The termination of several municipal wholesale contracts in New England resulted in NU Enterprises having additional generation from HWP’s Mt. Tom coal-fired plant and NGC’s conventional hydroelectric plants available for sale in the wholesale market.  In 2005, NU Enterprises signed agreements to sell a total of approximately 1.4 million megawatt-hours (MWhs) from Mt. Tom to counterparties during the years 2006 through 2008.  Approximately 1 million MWhs are generated annually at Mt. Tom per year.  Those sales are at prices significantly in excess of Mt. Tom’s contracted coal cost.  

For further information regarding these derivative assets and liabilities that are being exited, see Note 2, "Wholesale Contract Market Changes," and Note 6, "Derivative Instruments," to the consolidated financial statements.

In addition to the mark-to-market, restructuring and impairment charges noted above, NU Enterprises results in 2005 reflect lower sales for the wholesale marketing business than in 2004 as a result of the announced exit from that business in March of 2005.  

In 2004, NU Enterprises recorded an after-tax charge of $48.3 million associated with marking-to-market certain wholesale natural gas contracts intended to hedge certain wholesale electricity purchase obligations.  

Exclusive of after-tax charges related to wholesale supply totaling $29.1 million and other after-tax restructuring and impairment charges totaling $5.8 million, NU Enterprises' retail marketing business earned $6.3 million in 2005, compared with earnings of $4.9 million in 2004 and a loss of $1.8 million in 2003.  The charges related to wholesale supply were the result of a requirement to account for the sourcing of its customers’ electric requirements at March 31, 2005 market prices for supply contracts signed in the past at lower prices.  This was necessitated by the fact that the source of those contracts, wholesale marketing, is being divested.  As a result, an after-tax gain on those contracts of $59.9 million was recorded in the first quarter of 2005 that represented estimated future margins on existing retail transactions.  As a result, future retail marketing business results will be negatively affected until the exit fr om that business is completed.

The energy services businesses and NU Enterprises parent lost $37.6 million in 2005, compared with earnings of $2.2 million in 2004 and earnings of $3.3 million in 2003.  The 2005 loss was due to after-tax restructuring and impairment charges of $26.7 million primarily associated with the impairment of goodwill and intangible assets and as a result of construction contract losses.  The portion of the charges directly relating to the energy services businesses totaling $16.4 million after-tax is included in the (loss)/income from discontinued operations on the accompanying consolidated statements of (loss)/income as the charges relate to the energy services companies that are presented as discontinued operations.

For information regarding the current status of the exit from the NU Enterprises businesses, see "NU Enterprises Divestitures," included in this management's discussion and analysis.

Parent and Other:  Parent company and other after-tax expenses totaled $18.7 million in 2005, or $0.14 per share, compared with $23.9 million in 2004, or $0.18 per share, and $12.7 million, or $0.10 per share, in 2003.  The losses in 2005 included after-tax investment write-downs totaling $4.3 million while the losses in 2004 included after-tax investment write-downs totaling $8.8 million.  

Future Outlook

NU projects that 2006 combined earnings for the Utility Group and parent company will be between $1.09 per share and $1.22 per share.  

Utility Group:  NU believes that the combination of the current mild winter to date in 2006, slowing non-weather related sales and the denial of interim rate relief for Yankee Gas in 2005 may cause the Utility Group's regulated distribution and generation businesses earnings to be below its previously estimated 2006 earnings range of between $0.89 and $0.96 per share.  Utility Group earnings will also be affected by the outcome of various retail distribution rate proceedings and by the outcome of a transmission ROE proceeding at the FERC.  NU continues to estimate 2006 transmission business earnings of between $0.32 and $0.35 per share.  

NU Enterprises:  NU is not providing 2006 earnings guidance for NU Enterprises due to the uncertainty of any potential financial impacts of exiting those businesses.  

Parent and Other:  NU believes that due to higher projected investment income and some other factors, 2006 parent company losses will be less than the previous estimate of between $0.09 and $0.12 per share.  

Liquidity

Consolidated:  NU continues to maintain an adequate level of liquidity.  At December 31, 2005, NU's total unused borrowing capacity through its revolving credit agreement, its separate liquidity facility, the Utility Group's revolving credit agreement, and CL&P's accounts receivable facility totaled $1.1 billion.  At December 31, 2005, NU also had $45.8 million of cash and cash equivalents on hand compared with $47 million at December 31, 2004.  

Cash flows from operations decreased by $19.4 million to $441.2 million in 2005 from $460.6 million in 2004.  The decrease in operating cash flows is primarily due to the 2005 payments made for the exit from long-term wholesale power contracts by NU Enterprises of approximately $186 million and an accounts receivable increase due to the retail distribution rate increases that took effect in 2005 offset by increases in working capital items including an accounts payable increase related to timing of payments to standard offer suppliers and a change in year over year accrued taxes.  

Cash flows from operations decreased by $228.4 million from $689 million in 2003 to $460.6 million in 2004.  Increases in cash flows related to deferred income taxes were offset by decreases related to regulatory (refunds)/overrecoveries.  The decrease in year over year cash flows from regulatory (refunds)/overrecoveries was primarily due to lower CTA and Generation Service Charge (GSC) collections in 2004 as CL&P refunded amounts to its ratepayers for past over collections or used those amounts to recover current costs.  These refunds were also the primary reason for the positive change in year over year deferred income taxes, which had increased operating cash flows as refunded amounts were currently deducted for tax purposes.  Lower taxes paid also benefited cash flows from operations in 2004 due to bonus tax depreciation on newly completed plant assets.  

On October 20, 2005, the SEC approved NU's application which sought the authority to issue up to $750 million of new securities, including common equity, preferred stock and long-term debt.  On December 12, 2005, under an S-3 registration statement that became effective on November 3, 2005, NU sold 23 million common shares at a price of $19.09 per share.  Proceeds from this issuance, which were approximately $425 million after underwriter commissions and expenses, were used to reduce short-term debt and will be used in the future to continue to contribute equity to the Utility Group companies.  In 2005, NU contributed $198 million of equity to CL&P, $53.6 million to PSNH and $6.9 million to WMECO.  No contributions were made to Yankee Gas.

On October 28, 2005, NU received approval from the SEC to increase its short-term borrowing limit from $450 million to $700 million.  On December 9, 2005, NU entered into an amended revolving credit agreement that increased NU’s credit line from $500 million to $700 million and extended the maturity date of the agreement by one year to November 6, 2010.  As of December 31, 2005, NU had $32 million of borrowings and $253 million of letters of credit (LOCs) outstanding under that agreement.  

On November 2, 2005, NU entered into a separate $600 million liquidity facility, which added to other sources of liquidity.  After NU amended its revolving credit agreement and closed on its equity issuance as described above, the commitment level under this supplemental credit facility was reduced to $310 million.  At December 31, 2005, there were no borrowings outstanding under this facility.

Exiting the NU Enterprises' wholesale marketing business had a negative impact on cash flows in 2005 and is expected to continue to have a negative impact in 2006.  During 2005, approximately $186 million was paid to exit contracts either directly with municipal electric companies in New England or with other counterparties.  During 2005, commitments were also made to pay another approximately $56 million to a counterparty to exit obligations with a New England municipality.  

The exit from NU Enterprises' competitive generation and retail marketing business is expected to benefit NU’s liquidity and reduce debt.  The net proceeds from NU Enterprises' competitive generation asset sales are expected to be an important factor in NU’s financing plans.  The NGC and HWP generation assets of 1,442 MW of pumped storage, conventional hydroelectric, coal-fired, and peaking generation assets are expected to have a book value of approximately $825 million.  The cash proceeds available to NU after the sale will be reduced by NGC's debt of $320 million and by any taxes that will have to be paid.

Negotiations are continuing with parties interested in acquiring NU Enterprises' remaining services businesses, which had an aggregate book value of approximately $45 million at December 31, 2005 and debt owed to third-party lenders of approximately $90 million.  In the fourth quarter of 2005,

NU Enterprises sold SECI-NH and Woods Network to separate third parties for a total of approximately $6.5 million.  In January of 2006, the Massachusetts service location of SECI-CT was sold for approximately $2 million.  

NU's senior unsecured debt is rated Baa2 and BBB- with a stable outlook by Moody's Investors Service (Moody's) and Standard & Poor's (S&P), respectively, and is rated BBB with a stable outlook by Fitch Ratings.  At December 31, 2005, Select Energy at NU's current credit ratings levels could have been requested to provide $12.7 million of collateral under certain contracts which counterparties have not required to date.  If NU were to be downgraded to a sub-investment grade level by either Moody's or S&P, a number of Select Energy's contracts would require the posting of additional collateral in the form of cash or LOCs.  Were NU's senior unsecured ratings to be reduced to sub-investment grade by either Moody’s or S&P, Select Energy could, under its present contracts, be asked to provide approximately $406.6 million of collateral or LOCs to various unaffiliated counterparties and approximately $95.7 million to several i ndependent system operators and unaffiliated local distribution companies (LDCs) at December 31, 2005.  If such a downgrade were to occur, management believes NU would currently be able to provide this collateral.  The company’s decision to exit its competitive generation business resulted in S&P downgrading NGC debt by three notches to B+, well below investment grade.  Moody’s and Fitch Ratings have both placed NGC under review for downgrade, but management does not believe that such a downgrade, in and of itself, would have a negative impact on the ratings of NU or any other subsidiary.

NU paid common dividends of $87.6 million in 2005, compared with $80.2 million in 2004 and $73.1 million in 2003.  The increase in common dividends reflects increases in quarterly dividends of $0.0125 per share in the third quarters of 2003, 2004, and 2005.  Management expects to continue its current policy of dividend increases, subject to the approval of the NU Board of Trustees and the company’s future earnings and cash requirements.  On February 14, 2006, the NU Board of Trustees approved a quarterly dividend of $0.175 per share, payable March 31, 2006, to shareholders of record as of March 1, 2006.  In general, the Utility Group companies pay approximately 60 percent of their cash earnings to NU in the form of common dividends.  In 2005, CL&P, PSNH, WMECO, and Yankee Gas paid $53.8 million, $42.4 million, $7.7 million, and $30.8 million, respectively, in common dividends to NU.

Capital expenditures described herein are cash capital expenditures and do not include cost of removal, allowance for funds used during construction (AFUDC), and the capitalized portion of pension expense or income.  NU’s capital expenditures totaled $775.4 million in 2005, compared with $671.5 million in 2004 and $558.1 million in 2003.  NU’s 2005 capital expenditures included $444.4 million by CL&P, $158.8 million by PSNH, $44.7 million by WMECO, $74.6 million by Yankee Gas, and $52.9 million by other NU subsidiaries, including $23.2 million by NU Enterprises.  The increase in NU's capital expenditures was primarily the result of higher transmission capital expenditures, particularly at CL&P and was also the result of higher capital expenditures at Yankee Gas, primarily due to construction of its liquefied natural gas storage and production facility.  Utility Group capital expenditures are expected to increase furt her approaching $900 million in 2006, including approximately $600 million, $150 million, $50 million, and $100 million for CL&P, PSNH, WMECO, and Yankee Gas, respectively.  On a consolidated basis, NU estimates capital expenditures of approximately $900 million in 2007, $950 million in 2008, $800 million in 2009 and $800 million in 2010.

NU expects to fund approximately half of its expected capital expenditures over the next several years through internally generated cash flows.  As a result, the company expects its Utility Group companies, particularly CL&P, to issue debt regularly.  In 2005, CL&P issued $200 million of first mortgage bonds, PSNH and Yankee Gas each issued $50 million of first mortgage bonds and WMECO issued $50 million of senior notes.

Management does not currently expect to issue additional common equity before 2008.  The actual timing of a common equity issuance will depend on a number of factors, including actual levels of capital expenditures, net proceeds from the exit from the NU Enterprises businesses and proposals now before the FERC to provide financial incentives for the construction of additional electric transmission facilities in the United States.  Some of the incentives under consideration by the FERC, such as accelerated depreciation and the inclusion of CWIP in rate base, could increase NU’s internally generated cash flows.

Utility Group:  The Utility Group companies entered into an amended revolving credit agreement that maintained their $400 million credit line and extended the maturity date of their agreement by one year to November 6, 2010.  There were no borrowings outstanding under that agreement at December 31, 2005.

In addition to its revolving credit line, CL&P has an arrangement with a financial institution under which CL&P can sell up to $100 million of accounts receivable and unbilled revenues.  At December 31, 2005, CL&P had sold $80 million to that financial institution.  For more information regarding the sale of receivables, see Note 1O, "Summary of Significant Accounting Policies - Sale of Receivables" to the consolidated financial statements.

On April 7, 2005, CL&P sold $100 million of 10-year first mortgage bonds carrying a coupon rate of 5.0 percent and $100 million of 30-year first mortgage bonds carrying a coupon rate of 5.625 percent.  Proceeds were used to repay short-term borrowings.

On July 21, 2005, Yankee Gas sold $50 million of 30-year first mortgage bonds.  The interest rate was 5.35 percent.  Proceeds were used to repay short-term borrowings used to finance capital expenditures.

On August 11, 2005, WMECO sold $50 million of 10-year senior notes with an interest rate of 5.24 percent.  On October 5, 2005, PSNH sold $50 million of 30-year first mortgage bonds with an interest rate of 5.6 percent.  Proceeds from both issuances were used to repay short-term borrowings used to finance capital expenditures.

NU Enterprises:  Currently, NU Enterprises' liquidity is impacted by both the amount of collateral it receives from other counterparties and the amount of collateral it is required to deposit with counterparties.  From December 31, 2004 to December 31, 2005, NU Enterprises' liquidity was negatively impacted by $76.5 million from counterparty collateral deposits being repaid and higher counterparty collateral deposits being made.  In

2005, NU Enterprises also made approximately $186 million of payments to exit municipal and certain other long-term wholesale power contracts in New England.  

Most of the working capital and LOCs required by NU Enterprises are currently used to support the wholesale marketing business.  As NU Enterprises' wholesale contracts expire or are exited, its liquidity requirements are expected to decline.  However, the sale or renegotiation of additional longer-term below market wholesale power contracts will likely require NU Enterprises to continue to make significant payments to the counterparties in such transactions.

Strategic Overview

In 2005, NU announced the decision to exit all of NU Enterprises' competitive businesses and increase its investment in its regulated businesses to a significantly higher level.  Exiting these businesses, which management expects to substantially complete by the end of 2006, will simplify NU’s business model, reduce business risk, improve financial flexibility, enhance earnings visibility and predictability, and capitalize on the value of generation assets in New England.  Exiting these businesses is also expected to help benefit the credit ratings of NU and its Utility Group companies.  Credit rating agencies generally require lower coverage ratios for regulated transmission and distribution companies than for competitive generating and marketing companies because the stability and predictability of regulated company cash flows is generally much higher.  As a result, management believes that once the competitive businesses are f ully exited, the company will be able to maintain its current investment grade ratings with higher levels of debt and interest expense than if the competitive businesses were retained.

NU expects the Utility Group to invest up to $4.3 billion in its electric transmission and distribution and natural gas distribution businesses from 2006 through 2010.  Those amounts include up to $2.3 billion for the high-voltage electric transmission system and $2 billion for the electric and natural gas distribution systems and regulated generation.  NU estimates that when it successfully meets this goal, it will achieve compounded annual regulated rate base growth through 2010 of approximately 14 percent, assuming appropriate regulatory actions.  That growth rate would include compounded annual growth of approximately 29 percent in its regulated electric transmission rate base and 8 percent in its regulated distribution and generation rate base.  Based on the issuance of 23 million common shares in December of 2005 and projected issuances of additional common shares beyond 2007, parent company expenses, and assuming appropriate re gulatory actions, NU estimates that it could achieve earnings per share growth of between 8 percent and 10 percent annually beginning with 2007.  

Enterprise Risk Management

In 2005, NU adopted Enterprise Risk Management (ERM) as a methodology for managing the principle risks of the company.  ERM involves the application of a well-defined, enterprise-wide methodology which will enable NU’s Risk and Capital Committee, comprised of senior NU officers, to oversee the identification, management and reporting of the principal risks of the business.

NU Enterprises Divestitures

On March 9, 2005, NU announced that NU Enterprises would exit its wholesale marketing business and its energy services businesses.  On November 7, 2005, NU announced its decision to exit the remainder of NU Enterprises' competitive businesses, which includes the retail marketing and competitive generation businesses.  NU intends to apply the net proceeds from the exiting of these businesses to debt reduction and the financing of the regulated businesses' capital spending programs.  An overview of this process is as follows:  

Wholesale Marketing Business: In 2005, NU Enterprises recorded a net negative after-tax mark-to-market charge of $278.9 million related to the wholesale energy contracts being exited.  Included in this negative mark-to-market charge, in 2005 NU Enterprises paid or agreed to pay approximately $242 million to complete the exit from its New England wholesale sales contracts.  In 2005, all but approximately $56 million of that sum was paid.  NU Enterprises' exposure related to its remaining wholesale power obligations in the PJM power pool, which expire in 2008, and in New York, which consists of a single contract that expires in 2013, continues to decline as these obligations roll off.

Retail Marketing Business:  NU has retained J. P. Morgan as a financial advisor in exiting the retail marketing business, which provides electricity and natural gas service to approximately 30,000 customer locations in New England, New York and PJM.  Sales documents were distributed to prospective buyers of the retail marketing business in January of 2006 and indicative bids, which were received in February of 2006, are under evaluation.  NU plans to close on the sale of the retail marketing business in mid-2006.

The decision to exit the retail marketing business also required that the retail sales contracts be evaluated to determine whether these contracts are derivatives, and if so, whether these contracts should be marked-to-market.  After a thorough review, the company concluded that these contracts should not be marked-to-market at December 31, 2005 because most of these contracts are not derivatives, but should continue to be accounted for on the accrual basis.  The sales revenue to be received from these contracts is below current market prices, and the retail marketing business will likely be sold without the benefit of either certain below market supply contracts or supply from NU Enterprises' generation resources.  As a result, a payment to the buyer may be required to exit the retail marketing business.  This payment will depend upon the results of the bidding process currently underway and market prices at the time of divestiture a nd could be significant.  NU is currently in the process of marketing the retail business.  

Competitive Generation Business: NU has also retained J. P. Morgan as a financial advisor in exiting the competitive generation business, which includes NGC's and HWP's competitive generation assets in Massachusetts and Connecticut.  Sales documents were distributed to prospective buyers of the generation assets in February of 2006 and NU expects to close on the sale of the generation assets by the end of 2006.

Energy Services Businesses:  In 2005, NU Enterprises sold two of its six energy services businesses, SECI-NH and Woods Network, for a total of approximately $6.5 million.  In January of 2006, the Massachusetts service location of SECI-CT was sold for approximately $2 million.  NU Enterprises expects to complete the sale of SESI during 2006.  NU Enterprises is in the process of marketing Woods Electrical to potential buyers and expects to complete the sale of Woods Electrical during 2006.  

NU Enterprises' two remaining energy services businesses, SECI-CT and Boulos will be actively marketed during 2006.  For further information regarding these companies, see Note 4, "Assets Held For Sale and Discontinued Operations," to the consolidated financial statements.  

Business Development and Capital Expenditures

Consolidated:  In 2005, NU’s capital expenditures totaled $775.4 million, compared with depreciation of $235.2 million.  In 2004 and 2003, capital expenditures totaled $671.5 million and $558.1 million, compared with depreciation of $224.9 million and $204.4 million, respectively.  In 2006, total capital expenditures are projected to approach $900 million.  The increasing level of capital expenditures was caused primarily by a need to continue to improve the capacity and reliability of NU’s regulated transmission system.  That increased level of capital expenditures, compared with depreciation levels, also is increasing the amount of plant in service and the regulated companies’ earnings base, provided that NU’s Utility Group companies achieve timely recovery of their investment.  Unless otherwise noted, the capital expenditure amounts below exclude AFUDC.  

NU currently forecasts transmission expenditures of up to $2.3 billion from 2006 through 2010.  Those expenditures include $1.3 billion on the four southwest Connecticut projects as more fully described below, $0.8 billion of additional transmission projects management expects to be built, and $0.2 billion on projects that remain in the conceptual phase.  Management forecasts approximately $450 million of transmission capital expenditures in 2006 and approximately $550 million of transmission capital expenditures in 2007 and 2008, including AFUDC.  In addition, approximately $2 billion of distribution and generation projects is currently forecasted from 2006 to 2010, totaling up to $4.3 billion in total Utility Group capital projects.  Capital expenditures for NU Enterprises are still expected to be modest.

Utility Group:

CL&P:  In December of 2003, the DPUC approved a total of $900 million of distribution capital expenditures for CL&P from 2004 through 2007.  Those expenditures are intended to improve the reliability of the distribution system and to meet growth requirements on the distribution system.  In 2005, CL&P’s distribution capital expenditures totaled $236.6 million, compared with $254.7 million in 2004 and $255.9 million in 2003.  In 2006, CL&P projects distribution capital expenditures of approximately $200 million.

CL&P’s transmission capital expenditures totaled $207.8 million in 2005, compared with $134.6 million in 2004 and $62.6 million in 2003.  The increase in CL&P's transmission capital expenditures in 2005 was primarily the result of increased spending on a new 21-mile 345 kilovolt (kV) transmission project between Bethel, Connecticut and Norwalk, Connecticut.  In 2006, CL&P's transmission capital expenditures are projected to total approximately $400 million.  

Transmission capital expenditures in Connecticut are focused primarily on four major transmission projects in southwest Connecticut.  These projects include 1) the Bethel to Norwalk project noted above, 2) a Middletown to Norwalk 345 kV transmission project, 3) a related 115 kV underground project (Glenbrook Cables), and 4) the replacement of the existing 138 kV cable between Connecticut and Long Island.  Each of these projects has received approval from the Connecticut Siting Council (CSC) and ISO-NE.  Capital expenditures for these projects in southwest Connecticut totaled $156 million (including AFUDC) in 2005 out of the $207.8 million ($257.3 million including AFUDC) in total transmission and other capital expenditures in 2005.  

Underground line construction activities began in April of 2005 on a 21-mile 115 kV/345 kV line project between Bethel and Norwalk, with overhead line work commencing in September of 2005.  The first substation (Plumtree) was successfully energized on September 23, 2005.  The first 6.2 mile section of 115 kV cable was energized in the fourth quarter of 2005.  This project is expected to cost approximately $350 million of which CL&P spent $130.7 million (including AFUDC) in 2005.  The project is approximately 70 percent complete and CL&P had capitalized $196 million associated with the project at December 31, 2005.  This project is expected to be completed by the end of 2006.

On April 7, 2005, the CSC unanimously approved a proposal by CL&P and United Illuminating to build a 69-mile 345 kV transmission line from Middletown to Norwalk, Connecticut.  Approximately 24 miles of the 345 kV line will be built underground with the balance being built overhead.  The project still requires CSC review of detailed construction plans, as well as United States Army Corps of Engineers approval to bury the line beneath certain navigable rivers and Department of Environmental Protection (DEP) approvals.  The CSC decision included provisions for low-magnetic field designs in certain areas and made variations to the proposed route.  CL&P's portion of the project is estimated to cost approximately $1.05 billion.  CL&P received final technical approval from ISO-NE on January 20, 2006 and expects to award the major construction-related contracts during the second quarter of 2006.  CL&P expects the pro ject to be completed by the end of 2009.  Legal review of three appeals related to this project is ongoing.  At this time, CL&P does not expect any of these three appeals to delay construction.  At December 31, 2005, CL&P has capitalized $41 million associated with this project.

CL&P’s construction of the Glenbrook Cables Project, two 115 kV underground transmission lines between Norwalk and Stamford, Connecticut, was approved by the CSC on July 20, 2005 and by ISO-NE on August 3, 2005.  There were no court appeals of the project, which is expected to cost approximately $120 million and help meet growing electric demands in the area.  Management expects to begin construction during 2007 and expects the lines to be in service during 2008.  At December 31, 2005, CL&P has capitalized $7 million associated with this project.

On October 1, 2004, CL&P and the Long Island Power Authority (LIPA) jointly filed plans with the Connecticut DEP to replace an undersea 13-mile electric transmission line between Norwalk, Connecticut and Northport - Long Island, New York, consistent with a comprehensive settlement agreement reached on June 24, 2004.  CL&P and LIPA each own approximately 50 percent of the line.  On June 20, 2005, the New York State Controller’s Officer and the New York State Attorney General approved the settlement agreement between CL&P and LIPA to replace the cable and the project had earlier received CSC approval.  State and federal permits are expected to be issued in the second quarter of 2006.  Assuming these permits are received by no later than the second quarter of 2006 and the necessary construction contracts are signed, construction activities will begin

when material lead times allow.  Management will provide the estimated removal and in service dates when these construction contracts are signed. At December 31, 2005, CL&P has capitalized $6 million associated with this project.

In the fourth quarter of 2005, CL&P began construction of a new substation in Killingly, Connecticut that will improve CL&P’s 345 kV and 115 kV transmission systems in northeast Connecticut.  The project is expected to be completed by the end of 2006 at a cost of approximately $32 million.  At December 31, 2005, CL&P has capitalized $2.5 million associated with this project.

During 2005, CL&P placed in service $175 million of electric transmission projects, including $70 million related to the Bethel to Norwalk project.

Yankee Gas:  In 2005, Yankee Gas' capital expenditures totaled $74.6 million.  Yankee Gas is constructing a LNG storage and production facility in Waterbury, Connecticut, which will be capable of storing the equivalent of 1.2 billion cubic feet of natural gas.  Construction of the facility began in March of 2005 and is expected to be completed in time for the 2007/2008 heating season.  The facility, which is expected to cost $108 million, is approximately 48 percent complete.  Yankee Gas has capitalized $46.4 million related to this project at December 31, 2005.

The LNG project represented approximately 45 percent of Yankee Gas’ capital expenditures in 2005.  In 2005, including AFUDC, Yankee Gas also spent $17.7 million on its reliability improvement program, $13.8 million on connecting new customers, and $10.1 million on other initiatives, including meters and information technology systems.  In 2006, Yankee Gas projects total capital expenditures of approximately $100 million.

PSNH:   In 2005, PSNH’s capital expenditures totaled $158.8 million, including $131.9 million on PSNH’s electric distribution system and generation.  This $158.8 million includes $45 million related to the conversion of a 50 MW coal-fired unit at Schiller Station in Portsmouth, New Hampshire to burn wood (Northern Wood Power Project).  The Northern Wood Power Project began in late 2004 and is expected to achieve commercial generation in the second half of 2006.  The NHPUC's 2004 approval of the project was appealed to the New Hampshire Supreme Court by some of New Hampshire's existing wood-fired generating plant owners.  The Supreme Court upheld the NHPUC's finding that the project is in the public interest and, as a result, the project was able to proceed in accordance with the original schedule.  This project is approximately 90 percent complete and PSNH has capitalized $64.7 million related to this p roject at December 31, 2005.

In 2005, PSNH also spent $26.9 million on upgrading and expanding its electric transmission system.  In 2006, PSNH projects total capital expenditures of approximately $150 million.  

WMECO:  In 2005, WMECO’s capital expenditures totaled $44.7 million, including $32.4 million in its electric distribution system and other capital expenditures and $12.3 million on its electric transmission system.  As part of WMECO’s rate settlement approved by the DTE on December 29, 2004, WMECO agreed to invest not less than $24 million in capital expenditures in 2005 and 2006 related to reliability improvements.  In 2006, WMECO projects total capital expenditures of approximately $50 million.

NU Enterprises:  In March of 2005, HWP notified Massachusetts environmental regulators that it planned to install a selective catalytic reduction system at the 146 MW Mt. Tom coal-fired station in Holyoke, Massachusetts.  The system will significantly reduce nitrogen oxide emissions from the unit and extend its operating life by meeting expected emission requirements through 2010.  The $14 million project commenced in July of 2005 and is expected to be complete by mid-2006.  At December 31, 2005, this project was approximately 75 percent complete and HWP has capitalized $9.9 million related to this project.

Transmission Access and FERC Regulatory Changes

In January of 2005, the New England transmission owners approved activation of the New England Regional Transmission Organization (RTO) which occurred on February 1, 2005.  CL&P, PSNH and WMECO are now members of the New England RTO and provide regional open access transmission service over their combined transmission system under the ISO-NE Transmission, Markets and Services Tariff, FERC Electric Tariff No. 3 and local open access transmission service under the ISO-NE Transmission, Markets and Services Tariff, FERC Electric No. 3, Schedule 21 - NU.

As a result of the RTO start-up on February 1, 2005, the ROE in the local network service (LNS) tariff was increased to 12.8 percent.  The ROE being utilized in the calculation of the current regional network service (RNS) rates is the sum of the 12.8 percent "base" ROE, plus a 50 basis point incentive adder for joining the RTO, or a total of 13.3 percent.  An initial decision by a FERC administrative law judge (ALJ) has set the base ROE at 10.72 percent as compared with the 12.8 percent requested by the New England RTO.  One of the adjustments made by the ALJ was to modify the underlying proxy group used to determine the ROE, resulting in a reduction in the base ROE of approximately 50 basis points.  The ALJ deferred to the FERC for final resolution on the 100 basis point incentive adder for new transmission investments but reaffirmed the 50 basis point incentive for joining the RTO.  The New England transmission owner s have challenged the ALJ’s findings and recommendations through written exceptions filed on June 27, 2005 and a final order from the FERC is expected in 2006.  The result of this order, if upheld by the FERC, would be an ROE for LNS of 10.72 percent and an ROE for RNS of 11.22 percent.  When blended, the resulting "all in" ROE would be approximately 11.15 percent for the NU transmission business.   Management cannot at this time predict what ROE will ultimately be established by the FERC in these proceedings but for purposes of current earnings accruals and estimates, the transmission business is assuming an ROE of 11.5 percent.

In November of 2005, the FERC announced that it was considering a number of proposals to provide financial incentives for the construction of high-voltage electric transmission in the United States.  Those proposals included reflecting in rate base 100 percent of the cost of CWIP; accelerated recovery of depreciation; imputing hypothetical capital structures in ratemaking; establishing ROEs for transmission owners that join RTOs; and other incentives that could improve the earnings and/or cash flows associated with NU's transmission capital expenditures.  Comments on the FERC proposals were submitted in January of 2006, and final rules are expected by the summer of 2006.  

Legislative Matters

Federal Energy Legislation:  On August 8, 2005, President Bush signed into law comprehensive energy legislation.  Among provisions potentially affecting NU are the repeal of PUHCA, FERC backstop siting authority for transmission, transmission pricing and rate reform, renewable production tax credits, and accelerated depreciation for certain new electric and gas facilities.  The renewable production tax credits provision is expected to save PSNH approximately $3 million annually in federal income taxes for the first 10 years after the Northern Wood Power Project becomes operational.  The accelerated depreciation provision, assuming timely rate recovery, is expected to increase Utility Group cash flows by more than $5 million annually.  As part of this legislation, some but not all of the SEC's responsibilities under PUHCA were transferred to the FERC.

Environmental Legislation:  The RGGI is a cooperative effort by certain northeastern states to develop a regional program for stabilizing and ultimately reducing CO2 emissions from fossil-fired electric generators.  This initiative proposed to stabilize CO2 emissions at current levels and require a ten percent reduction by 2020.  The RGGI agreement was signed on December 20, 2005 by the states of Connecticut, Delaware, Maine, New Jersey, New Hampshire, New York, and Vermont.  Each state commits to propose for approval legislative and regulatory mechanisms to implement the program.  RGGI may impact PSNH’s Merrimack, Newington and Schiller stations.  At this time, the impact of this agreement on NU cannot be determined.  

On January 1, 2006 a CO2 cap on emissions from fossil-fired electric generators took effect in Massachusetts, with a separate CO2 emissions rate limit effective in 2008.  Affected parties are currently awaiting the Massachusetts DEP's proposal concerning a trading or other form of offset program.  HWP’s Mt. Tom plant would be impacted by this regulation.  Given the uncertainty of the future compliance mechanism under these regulations, the impact of this regulation on NU and the potential sale of Mt. Tom cannot be determined.

Connecticut:

Transmission Tracking Mechanism:  On July 6, 2005, Connecticut adopted legislation creating a mechanism to allow the DPUC to true-up, at least annually, the retail transmission charge in local electric distribution company rates based on changes in FERC-approved charges.  This mechanism allows CL&P to include forward-looking transmission charges in its retail transmission rate and promptly recover its transmission expenditures.  On December 20, 2005, the DPUC approved CL&P’s August 1, 2005 proposal to implement the mechanism effective July 1, 2005, which includes two adjustments annually, in January and June.  On January 1, 2006, consistent with that approval, CL&P raised its retail transmission rate to collect $21 million of additional revenues over the first six months of 2006.  

Energy Legislation:  Public Act 05-01, an "Act Concerning Energy Independence," (Act) was signed by Governor Rell on July 22, 2005.  The new legislation provides incentives to encourage the construction of distributed generation, new large-scale generation, and conservation and load management initiatives to reduce FMCC charges.  FMCC charges represent the costs of power market rules approved by the FERC that are resulting in significantly higher costs for Connecticut.  The most significant cost item in 2005 is reliability must run (RMR) contracts.  The legislation requires regulators to a) implement near-term measures as soon as possible, and b) commence a new request for proposals to build customer side distributed resources and contracts for new or repowered larger generating facilities in the state.  Developers could receive contracts of up to 15 years from the distribution companies.  The legislati on provides utilities with the opportunity to earn one-time awards for generation that is installed in their service territories.  Those awards can be as high as $200 per kilowatt for distributed generation and $25 per kilowatt for more traditional generation.  It also allows distribution companies, such as CL&P, to bid as much as 250 MW of capacity into the request for proposals.  If such utility bid was accepted, then the unit after five years would have to be a) sold, b) have its capacity sold, or c) both, provided that the DPUC could waive these requirements.  The DPUC is conducting a number of new dockets to implement this legislation.  The legislation also requires the DPUC to investigate the financial impact on distribution companies of entering into long-term contracts and to allow distribution companies to recover through rates any increased costs.  The DPUC ruled that at this point the impact is hypothetical and instructed the utilities to raise the issue in subseq uent rate cases.  

New Hampshire:

Environmental Legislation:  The New Hampshire legislature is considering a bill in its 2006 legislative session that would place strict limitations on the level of mercury that PSNH’s existing generation plants can emit.  Legislation was first proposed in the 2005 session and passed by the New Hampshire senate in 2005 which would require PSNH to achieve fixed annual caps as early as 2009.  The bill was subsequently defeated by the New Hampshire House of Representatives early in 2006.  The legislature will now take up a new bill that requires PSNH to reduce power plant mercury emissions by at least 80 percent by 2013 while providing incentives for early reductions.  Management has been reviewing the proposed legislation.  PSNH's primary long-term alternative is to install wet scrubber equipment at its Merrimack Station at a cost of approximately $250 million.  PSNH’s other alternatives include the use of carbon injection pollution control equipment, reducing operating capacity of its plants and possible retirement or repowering of one or more of its generating units.  While state law and PSNH's restructuring agreement provide for the recovery of its generation costs, including the cost to comply with state environmental regulations, at this time management is unable to determine the impact of any potential new legislation on PSNH's net income or financial position.

Utility Group Regulatory Issues and Rate Matters

Transmission - Wholesale Rates:  Wholesale transmission revenues are based on rates and formulas that are approved by the FERC.  Most of NU’s wholesale transmission revenues are collected through a combination of the RNS tariff and NU’s LNS tariff.  NU’s LNS rate is reset on January 1 and June 1 of each year.  NU's RNS rate is reset on June 1 of each year.  On January 1, 2006, NU’s LNS rates increased NU wholesale revenues by approximately $18 million on an annualized basis.  The LNS and RNS rates to be effective on June 1, 2006 have not yet been determined.  Additionally, NU’s LNS tariff provides for a true-up to actual costs, which ensures that NU's transmission business recovers its total transmission revenue requirements, including the allowed ROE.  At December 31, 2005, this true-up resulted in the recognition of a $2.1 million regulatory liability, includi ng approximately $1.5 million due to NU’s electric distribution companies.  

On December 1, 2005, NU filed at the FERC a request to include 50 percent of construction work in progress for its four major southwest Connecticut transmission projects in its formula rate for transmission service (Schedule 21 – NU (LNS)).  The FERC approved the filing with new rates effective on February 1, 2006.  The new rates allow NU to collect 50 percent of the construction financing expenses while these projects are under construction.  

Transmission - Retail Rates:  A significant portion of the NU transmission business revenue comes from ISO-NE charges to the distribution businesses of CL&P, PSNH and WMECO.  The distribution businesses recover these costs through the retail rates that are charged to their retail customers.  In July of 2005, CL&P began tracking its retail transmission revenues and expenses and on January 1, 2006 raised its retail transmission rate to collect $21 million of additional revenues over the first six months of 2006.  CL&P adjusts its retail transmission rates on a regular basis, thereby recovering all of its retail transmission expenses on a timely basis.  This new tracking mechanism resulted from the enactment of the new legislation passed by the Connecticut legislature in 2005.  WMECO implemented its retail transmission tracker and rate adjustment mechanism in January of 2002 as part of its 2002 rate change fi ling.  PSNH does not currently have a retail transmission rate tracking mechanism.   

LICAP: In March of 2004, ISO-NE proposed at the FERC an administratively determined electric generation capacity pricing mechanism known as LICAP, intended to provide a revenue stream sufficient to maintain existing generation assets and encourage the construction of new generation assets at levels sufficient to serve peak load, plus fixed reserve and contingency margins.

After opposition from state regulators, utilities and various Congressional delegations, the FERC ordered settlement negotiations before an ALJ to determine whether there was an acceptable alternative to LICAP.  On March 6, 2006, ISO-NE and a broad cross-section of critical stakeholders from around the region, including CL&P, PSNH and Select Energy, filed a comprehensive settlement agreement at the FERC implementing a Forward Capacity Market (FCM) in place of LICAP.  The settlement agreement provides for a fixed level of compensation to generators from December 1, 2006 through May 31, 2010 without regard to location in New England, and annual forward capacity auctions, beginning in 2008, for the 1-year period ending on May 31, 2011, and annually thereafter.  The settlement agreement must be approved by the FERC, and the parties have asked for a decision by June 30, 2006.  According to preliminary estimates, FCM would require the o perating companies to pay approximately the following amounts during the 3½-year transition period:  CL&P - $470 million; PSNH - $80 million; and WMECO - $100 million.  CL&P would be able to recover these costs from its customers through the FMCC mechanism.  PSNH and WMECO also would be able to recover these costs from their customers.  

Connecticut - CL&P:     

Streetlighting Decision:  On June 30, 2005, the DPUC issued a final decision which required CL&P to recalculate all previously issued refunds (except the towns of Stamford and Middletown) utilizing applicable approved pre-tax cost of capital rates.  The final decision also provided for a five-year period for those towns that wish to phase in the purchase of their streetlights in which they can complete the asset purchase.  As a result of this decision, CL&P recorded an additional $7.4 million pre-tax reserve for streetlight billing in the second quarter of 2005 and subsequently reduced the reserve by $3.3 million after submitting its compliance calculations and receiving approval from the DPUC.  The net impact in 2005 was an additional $4.1 million of pre-tax reserve.  CL&P filed an appeal of this decision on August 11, 2005 in the Connecticut Superior Court.  The court has not yet set a schedule for the a ppeal.  

Procurement Fee Rate Proceedings:  CL&P is currently allowed to collect a fixed procurement fee of 0.50 mills per kilowatt-hour (kWh) from customers who purchase TSO service through 2006.  One mill is equal to one-tenth of a cent.  That fee can increase to 0.75 mills per kWh if CL&P outperforms certain regional benchmarks.  The fixed portion of the procurement fee amounted to approximately $12 million (approximately $7 million after-tax) for 2004.  CL&P submitted to the DPUC its proposed methodology to calculate the variable portion (incentive portion) of the procurement fee.  CL&P requested approval of $5.8 million for its 2004 incentive payment.  On December 8, 2005, a draft decision was issued in this docket, which accepted the methodology proposed by CL&P and authorized payment of the $5.8 million incentive fee.  The DPUC has not set a date for issuing a final decision.

Retail Transmission Rate Filing:  As a result of the legislation described above, CL&P filed for a transmission adjustment clause on August 1, 2005 with the rate tracking mechanism effective on July 1, 2005.   The DPUC approved the mechanism on December 20, 2005.  On January 1, 2006, consistent with that approval, CL&P raised its retail transmission rate to collect $21 million of additional revenues over the first six months of 2006.  

CTA and SBC Reconciliation: The CTA allows CL&P to recover stranded costs, such as securitization costs associated with the rate reduction bonds, amortization of regulatory assets, and IPP over market costs, while the SBC allows CL&P to recover certain regulatory and energy public policy costs, such as public education outreach costs, hardship protection costs, transition period property taxes, and displaced worker protection costs.

A final decision in the 2004 CTA and SBC docket was issued on December 19, 2005 by the DPUC.  That decision ordered a refund to customers of $100.8 million over the twelve-month period beginning with January 2006 consumption.  In a subsequent decision in CL&P’s docket to establish the 2006 TSO rates dated December 28, 2005, the DPUC ordered CL&P to issue a revised CTA refund of $108 million over the twelve-month period beginning with January 2006 consumption and an additional CTA refund of $40 million for the months of January, February and March of 2006.  

In the 2001 CTA and SBC reconciliation filing, and subsequently in a September 10, 2002 petition to reopen related proceedings, CL&P requested that a deferred intercompany tax liability associated with the intercompany sale of generation assets be excluded from the calculation of CTA revenue requirements.  This liability is currently included as a reduction in the calculation of CTA revenue requirements.  On September 10, 2003, the DPUC issued a final decision denying CL&P’s request, and on October 24, 2003, CL&P appealed the DPUC’s final decision to the Connecticut Superior Court.  The appeal has been fully briefed and argued.  If CL&P’s request is granted and upheld through these court proceedings, there would be additional amounts due to CL&P from its customers.  The amount due is contingent upon the findings of the court.  However, management believes that CL&P's pre-tax earnings wo uld increase by a minimum of $15 million in 2006 if CL&P's position is adopted by the court.  

CL&P TSO Rates:  Most of CL&P’s customers buy their energy at CL&P’s TSO rate, rather than buying energy directly from competitive suppliers.  CL&P secured half of its 2006 TSO requirements during bidding in 2003 and 2004.  Bids to supply CL&P with its remaining 50 percent 2006 TSO requirements were received on November 15, 2005.  On December 29, 2005, the DPUC approved CL&P’s TSO rates for 2006.  As a result of significantly higher supplier bids for 2006, CL&P increased TSO rates by 17.5 percent on January 1, 2006 and will increase rates another 4.9 percent on April 1, 2006, representing a total increase of $676.5 million on an annualized basis.

On December 22, 2004, the DPUC approved an increase of 16.2 percent in TSO rates effective January 1, 2005, although the impact was partially offset by a continuation of the CTA refund.  The DPUC also ordered that projected 2004 and 2005 CTA overrecoveries and half of projected 2004 distribution overrecoveries be used to moderate increases for customers that otherwise would occur when the current CTA refund expired on May 1, 2005.  Overall, the final decision approved an increase to the January 2004 TSO rates of approximately 10.4 percent, including the effects of existing and new refunds and overrecoveries.  The DPUC denied requests by the Connecticut Attorney General and Office of Consumer Counsel (OCC) to defer the recovery of higher supplier costs into future years.  On February 3, 2005, the OCC filed an appeal with the Connecticut Superior Court challenging this decision, which was dismissed by the court on October 20, 2005.

Also, pursuant to state law, on December 19, 2003, the DPUC set CL&P’s TSO rates for January 1, 2004 through December 31, 2004 and confirmed that state law exempted FMCC charges, Energy Adjustment Clause (EAC) charges and certain other charges from the statutorily imposed rate cap. The OCC filed appeals of this decision with the Connecticut Superior Court.  The OCC claimed that the decision improperly implements an EAC charge under Connecticut law, fails to properly define and identify the fees that CL&P will be allowed to collect from customers and improperly calculates base rates for purposes of determining the rate cap.

On May 16, 2005, the DPUC approved a 4.8 percent increase to customer rates related to $79.8 million of additional RMR contract costs, which have been approved by the FERC.  This additional amount was recovered over the period June through December of 2005 through an increase to the FMCC rates effective June 1, 2005.  On August 24, 2005, the DPUC issued a final decision supporting the interim rate increase approved in May of 2005.  On February 1, 2006, CL&P filed with the DPUC its annual FMCC reconciliation filing for the year ended 2005.  No change in the current rates was proposed.  The DPUC has not set a schedule for review of this filing.  

Application for Issuance of Long-Term Debt:  On January 26, 2005, the DPUC approved CL&P's request to issue $600 million in long-term debt through December 31, 2007.  Additionally, the final decision approved CL&P's request to enter into hedging transactions in connection with any prospective or outstanding long-term debt in order to reduce the interest rate risk associated with the debt or debt issuances.  On April 7, 2005, CL&P closed on the sale of $200 million of first mortgage bonds with maturities ranging from 10 years to 30 years.  Proceeds were used to repay short-term borrowings.

Distribution Rates:  In its December 2003 rate case decision, the DPUC allowed CL&P to increase distribution rates annually from 2004 through 2007.  A $25 million distribution rate increase effective January 1, 2005, combined with strong hot weather driven third quarter sales, offset by after-tax employee termination and benefit plan curtailment charges totaling $8.5 million, resulted in CL&P earning a cost of capital ROE of 7.51 percent on its average distribution equity in 2005, compared with an allowed ROE of 9.85 percent.  An additional $11.9 million distribution rate increase took effect on January 1, 2006 and another $7 million distribution rate increase is due to take effect on January 1, 2007.  While these increases will help CL&P's performance, they may be inadequate to offset a possible combination of lower retail sales, higher employee-related expenses and higher costs related to the distribution capital investment program.  

Connecticut - Yankee Gas:

Purchased Gas Adjustment:  On September 9, 2005 the DPUC issued a draft decision regarding Yankee Gas PGA clause charges for the period of September 1, 2003 through August 31, 2004.  The draft decision disallowed approximately $9 million in previously recovered PGA revenues associated with two separate Yankee Gas unbilled sales and revenue adjustments.  At the request of Yankee Gas, the DPUC reopened the PGA hearings on September 20, 2005 and requested that Yankee Gas file supplemental information regarding the two adjustments.  Yankee Gas complied with this request.  The remaining schedule for the proceeding has not yet been established.  If upheld, this disallowance would result in a $9 million pre-tax write-off.  Management believes the unbilled sales and revenue adjustments and resultant charges to customers through the PGA clause were appropriate.  Based on the facts of the case and the supplemental inf ormation provided to the DPUC, management believes the appropriateness of the PGA charges to customers for the time period under review will be approved.  

Yankee Gas Rate Relief:  As a result of a settlement agreement reached with various parties in 2004 and approved by the DPUC, Yankee Gas instituted a $14 million increase in base rates on January 1, 2005.  That rate increase improved Yankee Gas' cost of capital ROE from 7.8 percent in 2004 to 8.42 percent in 2005 compared with an allowed ROE of 9.9 percent.  On December 23, 2005, the DPUC denied Yankee Gas' request for interim rate relief on the grounds that the prerequisite circumstances of the settlement agreement had not been met.  As prescribed in the settlement agreement, management expects to file a rate case in late 2006 that would be effective the earlier of July 1, 2007 or the date the Waterbury LNG facility enters service.  Management expects Yankee Gas to earn below its allowed ROE until the next rate case goes into effect.  Management has also begun to take steps to reduce Yankee Gas’ nonfuel operatio n and maintenance costs by combining certain operations of Yankee Gas and CL&P.  

New Hampshire:

ES Rates:  In accordance with the "Agreement to Settle PSNH Restructuring" and state law, PSNH files for updated Transition Energy Service Rate and Default Energy Service Rate, collectively referred to as Energy Service Rate (ES), periodically to ensure timely recovery of its costs.  The ES rate recovers PSNH's generation and purchased power costs, including a return on PSNH's generation assets.  PSNH defers for future recovery or refund any difference between its ES revenues and the actual costs incurred.  

On January 28, 2005, the NHPUC issued an order approving an ES rate of $0.0649 per kWh for the period February 1, 2005 through January 31, 2006 which included an 11 percent ROE on PSNH's generation assets.  This generation ROE was the subject of a second set of proceedings.  On June 8, 2005, the NHPUC issued an order requiring PSNH to use a generation ROE of 9.63 percent, effective July 1, 2005.  On July 7, 2005, PSNH filed a motion for reconsideration in the ROE portion of the above docket.  On December 2, 2005 the NHPUC issued a revised decision, lowering PSNH’s allowed ROE to 9.62 percent that was retroactive to an effective date of August 1, 2005.  On January 3, 2006, PSNH appealed the revised decision to the New Hampshire Supreme Court and simultaneously asked the NHPUC for reconsideration of its decision.  The appeal before the New Hampshire Supreme Court is pending.  On February 10, 2006, PSNH's most recent request for reconsideration by the NHPUC was denied.  This decrease in allowed ROE will lower PSNH's net income by approximately $1.5 million annually based on the current level of generation asset investment.  

On July 1, 2005, PSNH filed a petition with the NHPUC requesting an increase in the ES rate from the then current $0.0649 per kWh to $0.0734 per kWh based on actual costs and underrecoveries incurred through June 30, 2005 and updated cost projections.  The updated cost projections included an increase in costs as a direct result of higher fuel and purchased power costs that PSNH expected to incur.  The generation ROE used in the updated cost projections was based upon the 9.63 percent ROE ordered on June 8, 2005.  An order changing the ES rate to $0.0724 per kWh, effective August 1, 2005, was issued by the NHPUC on August 1, 2005.

On September 30, 2005, PSNH filed a petition with the NHPUC requesting a change in ES rates for the period February 1, 2006 through January 31, 2007.  On December 14, 2005, PSNH and other parties, including the NHPUC staff and the OCA, filed a stipulation and settlement agreement related to the September 30, 2005 filing.  A provision of the settlement agreement included an allowance to implement deferred accounting treatment for asset retirement obligations (AROs) that PSNH will be required to recognize under generally accepted accounting principles, including the future amortization of these ARO deferrals.

On December 19, 2005, PSNH filed updated ES cost information and requested approval of an ES rate of $0.0913 per kWh for the 11-month period from February 1, 2006 through December 31, 2006.  Hearings regarding the settlement agreement and the updated ES rate were held on December 21, 2005 and the NHPUC issued an order on January 20, 2006 approving the settlement agreement, as filed, and the ES rate of $0.0913 per kWh for the 11-month period.

SCRC Reconciliation Filing:  The SCRC allows PSNH to recover its stranded costs.  On an annual basis, PSNH files with the NHPUC a SCRC reconciliation filing for the preceding calendar year.  This filing includes the reconciliation of stranded cost revenues and costs and ES revenues and costs.  The NHPUC reviews the filing, including a prudence review of the operations within PSNH's generation business segment.  The cumulative deferral of SCRC revenues in excess of costs was $303.3 million at December 31, 2005.  This cumulative deferral will decrease the amount of non-securitized stranded costs to be recovered from PSNH's customers in the future from $368 million to $64.7 million.

The 2004 SCRC reconciliation filing was filed with the NHPUC on May 2, 2005.  In October of 2005, PSNH, the NHPUC staff and the OCA reached a settlement agreement in this case.  The major provisions of  this settlement agreement include the following: 1) PSNH will be allowed to recover its 2004 ES costs and stranded costs without disallowances, 2) PSNH will be allowed to include its cumulative unbilled revenues in its ES and stranded cost reconciliations and 3) the NHPUC will defer any action regarding PSNH’s coal supply and transportation procedures until it completes a review using an outside expert.  The NHPUC issued its order on December 22, 2005, approving the settlement agreement as filed.  While management believes its coal procurement and transportation policies and procedures are prudent and consistent with industry practice, it is unable to determine the impact, if any, of the expected NHPUC review on PSNH's n et income or financial position.

Litigation with Independent Power Producers (IPPs):  Two wood-fired IPPs that sell their output to PSNH under long-term rate orders issued by the NHPUC brought suit against PSNH in state superior court.  The IPPs and PSNH dispute the end dates of the above-market long-term rates set forth in the respective rate orders.  Subsequent to the IPP's court filing, PSNH petitioned the NHPUC to decide this matter, and requested that the court stay its proceeding pending the NHPUC's decision.  By court order dated October 20, 2005, the court granted PSNH's motion to stay indicating that the NHPUC had primary jurisdiction over this matter.  

On November 11, 2005, the IPPs filed motions with the NHPUC seeking to disqualify two of the three NHPUC commissioners from participating in this proceeding.  As a result, the NHPUC chair excused himself from participating in this proceeding.  On December 7, 2005, the IPPs then filed an interlocutory appeal with the New Hampshire Supreme Court (Supreme Court) on the basis that the forum for resolving this dispute is in state superior court.  On December 27, 2005, PSNH and the New Hampshire Attorney General’s Office (representing the NHPUC) each filed motions for summary disposition with the Supreme Court.  On February 7, 2006, the Supreme Court declined to accept the IPP's interlocutory appeal.  As a result, the matter will return to the NHPUC for decision.  PSNH recovers the over market costs of IPP contracts through the SCRC.

Massachusetts:

Transition Cost Reconciliation:  On March 31, 2005, WMECO filed its 2004 transition cost reconciliation with the DTE.  The DTE has combined the 2003 transition cost reconciliation filing, standard offer service and default service reconciliation, the transmission cost adjustment filing, and the 2004 transition cost reconciliation filing into a single proceeding.  The timing of a decision in the combined proceeding is uncertain, but management does not expect the outcome to have a material adverse impact on WMECO's net income or financial position.  

Distribution Rate Case Settlement Agreement:  On December 29, 2004, the DTE approved a rate case settlement agreement submitted by WMECO, the Massachusetts Attorney General's Office, the Associated Industries of Massachusetts, and the Low-Income Energy Affordability Network.  The settlement agreement provides for a $6 million increase in WMECO’s distribution rate effective on January 1, 2005 and an additional $3 million increase in WMECO's distribution rate effective on January 1, 2006 and for a decrease in WMECO’s transition charge by approximately $13 million annually.  The lower transition charge will delay recovery of transition costs and will reduce WMECO’s cash flows but not its earnings as part of the rate case settlement agreement.  WMECO agreed not to file for a distribution rate increase to be effective prior to January 1, 2007.

Annual Rate Change Filing:  On December 1, 2005, WMECO made its 2006 annual rate change filing implementing the $3 million distribution revenue increase allowed under its rate case settlement agreement.  WMECO requested that this change become effective on January 1, 2006.  On December 29, 2005, the DTE approved rates reflecting the $3 million distribution revenue increase as well as increases for new basic service supply.

Basic Service:  WMECO owns no generation and seeks bids at regular intervals to provide full requirements service for its customers who do not contract directly with competitive retail suppliers for their energy.  As a result of higher energy prices, the prices for 2006 are significantly higher than 2005.  

Deferred Contractual Obligations

FERC Proceedings:  In 2003, the Connecticut Yankee Atomic Power Company (CYAPC) increased the estimated decommissioning and plant closure costs for the period 2000 through 2023 by approximately $395 million over the April 2000 estimate of $436 million approved by the FERC in a 2000 rate case settlement.  The revised estimate reflects the increases in the projected costs of spent fuel storage, increased security and liability and property insurance costs, and the fact that CYAPC is now self performing all work to complete the decommissioning of the plant due to the termination of the decommissioning contract with Bechtel Power Corporation (Bechtel) in July of 2003.  NU's share of CYAPC's increase in decommissioning and plant closure costs is approximately $194 million.  On July 1, 2004, CYAPC filed with the FERC for recovery seeking to increase its annual decommissioning collections from $16.7 million to $93 million for a six-ye ar period beginning on January 1, 2005.  On August 30, 2004, the FERC issued an order accepting the rates, with collection beginning on February 1, 2005, subject to refund.

Both the DPUC and Bechtel filed testimony in the FERC proceeding claiming that CYAPC was imprudent in its management of the decommissioning project.  In its testimony, the DPUC recommended a disallowance of $225 million to $234 million out of CYAPC's requested rate increase of approximately $395 million.  NU's share of the DPUC's recommended disallowance would be between $110 million to $115 million.  The FERC staff also filed testimony that recommended a $38 million decrease in the requested rate increase claiming that CYAPC should have used a different gross domestic product (GDP) escalator.  NU's share of this recommended decrease is $18.6 million.  

On November 22, 2005, a FERC administrative law judge issued an initial decision finding no imprudence on CYAPC's part.  However, the administrative law judge did agree with the FERC staff’s position that a lower GDP escalator should be used for calculating the rate increase and found that CYAPC should recalculate its decommissioning charges to reflect the lower escalator.  Briefs to the full FERC addressing these issues were filed in January and February of 2006, and a final order is expected later in 2006.  Management expects that if the FERC staff's position on the decommissioning GDP cost escalator is found by the FERC to be more appropriate than that used by CYAPC to develop its proposed rates, then CYAPC would review whether to reduce its estimated decommissioning obligation and reduce the customers' obligation, including CL&P, PSNH and WMECO.  

The company cannot at this time predict the timing or outcome of the FERC proceeding required for the collection of the increased CYAPC decommissioning costs.  The company believes that the costs have been prudently incurred and will ultimately be recovered from the customers of CL&P, PSNH and WMECO.  However, there is a risk that some portion of these increased costs may not be recovered, or will have to be refunded if recovered, as a result of the FERC proceedings.  

On June 10, 2004, the DPUC and the Connecticut OCC filed a petition seeking a declaratory order that CYAPC be allowed to recover all decommissioning costs from its wholesale purchasers, including CL&P, PSNH and WMECO, but that such purchasers may not be allowed to recover in their retail rates any costs that the FERC might determine to have been imprudently incurred.  On August 30, 2004, the FERC denied this petition.  On September 29, 2004, the DPUC and OCC asked the FERC to reconsider the petition and on October 20, 2005, the FERC denied the reconsideration, holding that the sponsor companies are only obligated to pay CYAPC for prudently incurred decommissioning costs and the FERC has no jurisdiction over the sponsors' rates to their retail customers.  On December 12, 2005, the DPUC sought review of these orders by the United States Court of Appeals for the D.C. Circuit.  The FERC and CYAPC have asked the court to dismiss the ca se and the DPUC has objected to a dismissal.  NU cannot predict the timing or the outcome of these proceedings.

Bechtel Litigation:  CYAPC and Bechtel commenced litigation in Connecticut Superior Court over CYAPC's termination of Bechtel's contract for the decommissioning of CYAPC's nuclear generating plant.  After CYAPC terminated the contract, responsibility for decommissioning was transitioned to CYAPC, which recommenced the decommissioning process.

On March 7, 2006, CYAPC and Bechtel executed a settlement agreement terminating this litigation.  Bechtel has agreed to pay CYAPC $15 million, and CYAPC will withdraw its termination of the contract for default and deem it terminated by agreement.

Spent Nuclear Fuel Litigation:  CYAPC, the Yankee Atomic Electric Company (YAEC) and Maine Yankee Atomic Power Company (MYAPC) (Yankee companies) also commenced litigation in 1998 charging that the federal government breached contracts it entered into with each company in 1983 under the Act.  Under the Act, the DOE was to begin removing spent nuclear fuel from the nuclear plants of the Yankee Companies no later than January 31, 1998 in return for payments by each company into the nuclear waste fund.  No fuel has been collected by the DOE, and spent nuclear fuel is stored on the sites of the Yankee Companies' plants.  The Yankee Companies collected the funds for payments into the nuclear waste fund from wholesale utility customers under FERC-approved contract rates.  The wholesale utility customers in turn collect these payments from their retail electric customers.  The Yankee Companies' individual damage claims attri buted to the government's breach ranging between $523 million and $543 million are specific to each plant and include incremental storage, security, construction and other costs through 2010.  The CYAPC damage claim ranges from $186 million to $198 million, the YAEC damage claim ranges from $177 million to $185 million and the MYAPC damage claim is $160 million.  The DOE trial ended on August 31, 2004 and a verdict has not been reached.  Post-trial findings of facts and final briefs were filed by the parties in January of 2005.  The Yankee Companies' current rates do not include an amount for recovery of damages in this matter.  Management can predict neither the outcome of this matter nor its ultimate impact on NU.

YAEC:   In November of 2005, YAEC established an updated estimate of the cost of completing the decommissioning of its plant resulting in an increase of approximately $85 million.   NU's share of the increase in estimated costs is $32.7 million.  This estimate reflects the cost of completing site closure activities from October of 2005 forward and storing spent nuclear fuel and other high level waste on site until 2020.  This estimate projects a total cost of $192.1 million for the completion of decommissioning and long-term fuel storage.  To fund these costs, on November 23, 2005, YAEC submitted an application to the FERC to increase YAEC’s wholesale decommissioning charges.  The DPUC and the Massachusetts attorney general protested these increases.  On January 31, 2006, the FERC issued an order accepting the rate increase, effective February 1, 2006, subject to refund after hearings and sett lement judge proceedings.  The hearings have been suspended pending settlement discussions between YAEC, the FERC and other intervenors in the case.  NU has a 38.5 percent ownership interest in YAEC and can predict neither the outcome of this matter nor its ultimate impact on NU.

NU Enterprises

NU Enterprises currently has two business segments:  the merchant energy business segment and the energy services and other business segment.  NU has decided to exit all aspects of both segments.

Merchant Energy Segment:  The merchant energy business segment includes Select Energy's retail marketing business, 1,442 MW of generation assets, including 1,296 MW of primarily pumped storage and hydroelectric generation assets at NGC and 146 MW of coal-fired generation assets at HWP, and NGS.

The merchant energy segment also continues to include the wholesale marketing business, which NU Enterprises is exiting.  Prior to the March 2005 decision to exit the wholesale marketing business, this business was comprised primarily of full requirements sales to LDCs and bilateral sales to other load-serving counterparties.  These sales were sourced by the generation assets and an inventory of energy contracts.   

Energy Services and Other Segment:  In March of 2005, NU Enterprises also announced that it would explore ways to exit the energy services businesses in a manner that maximizes their value.  These businesses include or have included the operations of SESI, Boulos, Woods Electrical and SECI.  SECI-NH, including Reeds Ferry, and Woods Network were sold in November of 2005.  In January of 2006, the Massachusetts service location of SECI-CT was sold for approximately $2 million.  

Outlook:  NU is not providing 2006 earnings guidance for NU Enterprises due to many factors, including:

·

The application of mark-to-market accounting to certain energy contracts until those contracts are settled or until the commodities are delivered.  The value of these contracts has fluctuated and will continue to fluctuate with changes in electricity and capacity values and with gas prices that are used to value the long-term portions of the contracts.  These changes in value have been reflected in earnings and have been significant.  These changes could continue to be significant.

·

Proceeds and the related gain or loss on the sale of competitive generation assets should the sale of NU Enterprises generation assets occur in 2006.  

·

The recognition of additional mark-to-market gains or losses on wholesale marketing contracts that have not been recorded yet.  Serving full requirements contracts could result in quantities of electricity to be delivered in amounts different from the notional amounts that were multiplied by current market prices to determine the mark-to-market gains or losses.  Differences have impacted and are reasonably likely to continue to impact NU Enterprises' earnings.  In addition, gains or losses may be recorded on the disposition of these wholesale contracts.  

·

Additional asset impairments or losses on disposals associated with the wholesale and retail marketing, competitive generation and energy service businesses.  As these businesses are exited, there could be additional impairments or gains or losses on the disposals to the extent sales are consummated.  

·

NU guarantees the performance of certain services companies.  The fair value of those guarantees may be recognized if they become guarantees to third parties.

·

The recognition of additional restructuring costs.  Costs associated with certain restructuring activities and employee costs are expected to be recognized in future periods as incurred.

Intercompany Transactions:  There were no CL&P TSO purchases from Select Energy in 2005, compared to $502 million of CL&P standard offer purchases in 2004.  Other energy purchases between CL&P and Select Energy totaled $53.4 million in 2005 compared to $109.3 million in 2004.  WMECO purchases from Select Energy totaled $36.3 million and $108.5 million for the year ended December 31, 2005 and 2004, respectively.  In February of 2005, WMECO entered into a contract with Select Energy under which Select Energy provided default service from April through June of 2005.

Risk Management: Until the exit from the merchant energy business is completed, NU Enterprises will continue to be exposed to various market risks which could negatively affect the value of its remaining assets.  These assets include its remaining portfolio of wholesale energy contracts, its retail energy marketing business and its generation assets.  Market risk at this point is comprised of the possibility of adverse energy commodity price movements and, in the case of the wholesale marketing business, unexpected load ingress or egress, affecting the unhedged portion of these contracts.

NU Enterprises manages these and associated operating risks through detailed operating procedures and an internal review committee.  A separate, parent-level committee, the Risk Oversight Council (ROC) meets monthly with NU Enterprises’ leadership and upon the occurrence of specific portfolio-triggered events to review conformity of NU Enterprises’ activities, commitments and exposures to NU’s risk parameters.  The ROC in turn is being integrated into NU’s ERM system, which was instituted in 2005.

Wholesale Marketing Activities:  As a result of NU's decision to exit the wholesale marketing business, certain wholesale energy contracts previously accounted for under accrual accounting were required to be marked-to-market beginning in the first quarter of 2005.  Existing energy trading contracts have been and will continue to be marked-to-market with changes in fair value reflected in earnings.  

At December 31, 2005, Select Energy had wholesale derivative assets and derivative liabilities as follows:

(Millions of Dollars)
Current wholesale derivative assets	$ 256.6
Long-term wholesale derivative assets	103.5
Current wholesale derivative liabilities	(369.3)
Long-term wholesale derivative liabilities	(220.9)
Portfolio position	$(230.1)

Numerous factors could either positively or negatively affect the realization of the net fair value amounts in cash.  These include the amounts paid or received to exit some or all of these contracts, the volatility of commodity prices until the contracts are exited, the outcome of future transactions, the performance of counterparties, and other factors.

Select Energy has policies and procedures requiring all wholesale positions to be marked-to-market at the end of each business day and segregating responsibilities between the individuals actually transacting (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 wholesale energy contracts are identified and segregated in the table of fair value of contracts at December 31, 2005.  A description of each method is as follows: 1) prices actively quoted primarily represent New York Mercantile Exchange (NYMEX) futures, swaps and options that are marked to closing exchange prices; and 2) prices provided by external sources primarily include over-the-counter forwards and options, including bilateral contracts for the purchase or sale of electricity or natural gas, and are marked to the mid-point of bid and ask market prices.  The mid-points of market prices are adjusted to include all applicable market information, such as prior contract settlements with third parties.  Currently, Select Energy has a contract for which a portion of the contract's fair value is determined based on a model or other valuation method.  The model utilizes natural gas prices and a conversion factor to electricity.  Broker quotes for electricity at locations for which Select Energy has entered into transactions are generally available through the year 2009.  For all natural gas positions, broker quotes extend through 2013.

Generally, valuations of short-term contracts derived from quotes or other external sources are more reliable should there be a need to liquidate the contracts, while valuations for longer-term contracts are less certain.  Accordingly, there is a risk that contracts will not be realized at the amounts recorded.  

As of and for the years ended December 31, 2005 and 2004, the sources of the fair value of wholesale contracts and the changes in fair value of these contracts are included in the following tables:

(Millions of Dollars)	Fair Value of Wholesale Contracts at December 31, 2005
Sources of Fair Value	Maturity Less than One Year	Maturity of One to Four Years	Maturity in Excess of Four Years	Total Fair Value
Prices actively quoted	$    31.3	$  19.1	$       -	$    50.4
Prices provided by external sources	(147.5)	(94.7)	(2.8)	(245.0)
Models based	0.7	(10.3)	(25.9)	(35.5)
Totals	$(115.5)	$(85.9)	$(28.7)	$(230.1)

(Millions of Dollars)	Fair Value of Wholesale Contracts at December 31, 2004
Sources of Fair Value	Maturity Less than One Year	Maturity of One to Four Years	Maturity in Excess of Four Years	Total Fair Value

Prices actively quoted	$(58.9)	$(7.3)	$      -	$(66.2)
Prices provided by external sources	(6.5)	11.3	12.5	17.3
Totals	$(65.4)	$ 4.0	$12.5	$(48.9)

	Years Ended December 31,
	2005	2004
(Millions of Dollars)	Total Portfolio Fair Value
Fair value of wholesale contracts outstanding at the beginning of the year	$ (48.9)	$ 33.4
Contracts realized or otherwise settled during the year	254.2	(3.5)
Changes in fair value recorded:
Wholesale contract market changes, net	(419.0)	-
Fuel, purchased and net interchange power	(43.7)	(86.3)
Operating revenues	13.1	2.0
Changes in model based assumption included in operating revenues	14.2	5.5
Fair value of wholesale contracts outstanding at the end of the year	$(230.1)	$(48.9)

Changes in the fair value of wholesale contracts that became marked-to-market as a result of the exit decisions totaling a negative $419 million in 2005 are recorded as wholesale contract market changes, net, changes in fair value of natural gas contracts totaling a negative $43.7 million in 2005 are recorded as fuel, purchased and net interchange power and changes in fair value of contracts formerly designated as trading totaling a positive $13.1 million in 2005 are recorded as revenue on the accompanying consolidated statements of (loss)/income.  

During the fourth quarter of 2005, Select Energy assigned a wholesale contract for $55.9 million with payments commencing in January of 2006 and ending in December of 2008.  This amount is included in the contracts realized or otherwise settled during the year amount of $254.2 million above.  

At December 31, 2005, this contractual assignment was reclassified from short and long-term derivative liabilities to other current liabilities ($18.5 million) and other long-term liabilities ($37.4 million) on the consolidated balance sheets.  This amount is included in the $419 million of wholesale contract market changes, net in the table above.  The payments under this assignment bear interest at 12.5 percent.  If certain conditions are met, these payments could be accelerated.  

In the first quarter of 2005, the mark-to-market of Select Energy's wholesale contracts increased by $14.2 million as a result of the removal of a modeling reserve for one of its trading contracts.  The change in fair value associated with this removal is included in the changes in model based assumption included in operating revenues category in the table above.  This contract was subsequently sold to a third-party wholesale marketer in the third quarter of 2005.

Retail Marketing Activities:   Select Energy manages its portfolio of retail marketing contracts to maximize value while operating within NU's corporate risk tolerance.  Select Energy generally acquires retail customers in small increments, which while requiring careful sourcing, allows energy purchases to be acquired in small increments.  However, fluctuations in prices, fuel costs, competitive conditions, regulations, weather, transmission costs, lack of market liquidity, plant outages and other factors can all impact the retail marketing business adversely from time to time.

In 2005, the retail marketing business was the successful bidder on more than 30 percent of its bids, from a revenue standpoint, compared with just under 25 percent in 2004.  

For the year ended December 31, 2005, approximately 11 million MWhs were delivered as compared to approximately 10 million MWhs in 2004.  For natural gas, approximately 46 billion cubic feet were delivered in 2005 as compared to approximately 39.5 billion cubic feet in 2004.  

Retail margins ranged from approximately $1.60 to $2.00 per MWh in 2005.  For natural gas, sales margins averaged between approximately $0.20 and $0.25 per thousand cubic feet in 2005.   

The retail marketing business periodically enters into supply contracts that do not immediately meet the criteria for the normal election and accrual accounting and therefore, changes in fair value are required to be marked-to-market and included in earnings.  At December 31, 2005, Select Energy had retail derivative assets and liabilities as follows:   

(Millions of Dollars)
Current retail derivative assets	$35.3
Long-term retail derivative assets	-
Current retail derivative liabilities	(18.3)
Long-term retail derivative liabilities	-
Portfolio position	$17.0

The methods used to determine the fair value of retail energy sourcing contracts are identified and segregated in the table of fair value of contracts at December 31, 2005.  A description of each method is as follows: 1) prices actively quoted primarily represent exchange traded futures and swaps that are marked to closing exchange prices; and 2) prices provided by external sources primarily include over-the-counter forwards, including bilateral contracts for the purchase or sale of electricity or natural gas, and are marked to the mid-point of bid and ask market prices.  

As of and for the year ended December 31, 2005, the sources of the fair value of retail energy sourcing contracts and the changes in fair value of these contracts are included in the following tables:  

(Millions of Dollars)	Fair Value of Retail Sourcing Contracts at December 31, 2005
Sources of Fair Value	Maturity Less Than One Year	Maturity of One to Four Years	Maturity in Excess of Four Years	Total Fair Value
Prices actively quoted	$(8.8)	$ -	$ -	$(8.8)
Prices provided by external sources	25.8	-	-	25.8
Totals	$17.0	$ -	$ -	$17.0

	Year Ended  December 31, 2005
	Total Portfolio Fair Value
Fair value of retail sourcing contracts outstanding at the beginning of the year	$        -
Contracts realized or otherwise settled during the year	(25.7)
Changes in fair value recorded:
Wholesale contract market changes, net	30.0
Fuel, purchased power and net interchange power	12.7
Fair value of retail sourcing contracts outstanding at the end of the year	$ 17.0

Upon the decision to exit the wholesale marketing business in March of 2005, Select Energy identified $30 million of previously designated wholesale contracts and redesignated them to help support its retail marketing business.  Subsequent changes in fair value are now recorded in fuel, purchased and net interchange power.  Fuel, purchased and net interchange power increased $12.7 million primarily due to power price increases in the PJM power pool in the second half of 2005.  

Competitive Generation Activities:  The competitive generation assets, owned by NU Enterprises are subject to certain operational risks, including but not limited to the length of scheduled and non-scheduled outages, bidding and scheduling with various ISOs, environmental issues and fuel costs.  Competitive generation activities are also subject to various federal, state and local regulations.  These risks may result in changes in the anticipated gross margins which the merchant energy business realizes from its competitive generation portfolio/activities.  

For the year ended December 31, 2005, NU Enterprises' competitive generation assets continued to run well while energy prices increased and reserve margins started to tighten.  NU Enterprises believes that generating unit availability will become increasingly important as the capacity market tightens in New England due to load growth and the absence of new plant construction.  For the year ended December 31, 2005, the 146 MW Mt. Tom plant at HWP had a capacity factor of just over 80 percent while the 1,080 MW Northfield Mountain facility had an availability factor of nearly 95 percent.  The approximately 200 MW of other hydroelectric units had an aggregate availability factor of 85 percent.

Total competitive generation was 2.6 million MWhs through December 31, 2005.  HWP's Mt. Tom station, a coal-fired unit located in Holyoke, Massachusetts, generated more than one million MWhs in 2005, while NGC's Northfield Mountain facility and other hydroelectric units generated approximately 0.9 million MWhs and approximately 0.7 million MWhs, respectively, in 2005.

For the Northfield Mountain facility, the ratio of on-peak to off-peak spreads averaged 1.5 for 2005.  As a result, NU Enterprises realized $17.5 million of energy-related gross margin in 2005.  

The value of NGC's generating assets could be affected by the adoption of FCM in place of the prior LICAP proposal.  For further information, see "Utility Group Regulatory Issues and Rate Matters - LICAP," included in this management's discussion and analysis.  

At December 31, 2005, Select Energy had generation derivative assets and liabilities as follows:   

(Millions of Dollars)
Current generation derivative assets	$    9.2
Long-term generation derivative assets	-
Current generation derivative liabilities	(5.1)
Long-term generation derivative liabilities	(15.5)
Portfolio position	$(11.4)

The methods used to determine the fair value of generation contracts are identified and segregated in the table of fair value of contracts at December 31, 2005.  A description of each method is as follows: 1) prices actively quoted primarily represent exchange traded futures and swaps that are marked to closing exchange prices; and 2) prices provided by external sources primarily include over-the-counter forwards, including bilateral contracts for the purchase or sale of electricity and are marked to the mid-point of bid and ask market prices.  

As of and for the year ended December 31, 2005, the sources of the fair value of generation contracts and the changes in fair value of these contracts are included in the following tables:  

(Millions of Dollars)	Fair Value of Generation Contracts at December 31, 2005
Sources of Fair Value	Maturity Less than One Year	Maturity of One to Four Years	Maturity in Excess of Four Years	Total Fair Value
Prices actively quoted	$(1.8)	$       -	$ -	$  (1.8)
Prices provided by external sources	5.9	(15.5)	-	(9.6)
Totals	$ 4.1	$(15.5)	$ -	$(11.4)

	Year Ended December 31, 2005
(Millions of Dollars)	Total Portfolio Fair Value
Fair value of competitive generation contracts outstanding at the beginning of the year	$         -
Contracts realized or otherwise settled during the year	(0.1)
Changes in fair value recorded:
Wholesale contract market changes, net	(15.5)
Operating revenues	4.2
Fair value of competitive generation contracts outstanding at the end of the year	$ (11.4)

As a result of NU's decision to exit the competitive generation business, certain competitive generation contracts to sell plant output in future periods previously accounted for under accrual accounting were required to be marked-to-market in the fourth quarter of 2005.  The contracts whose changes in fair value flow through operating revenues are primarily sales contracts used to hedge competitive generation.  The $4.2 million change in fair value is the result of high priced sales positions in the third quarter of 2005 combined with falling market prices during the fourth quarter of 2005.  

For further information regarding Select Energy's derivative contracts, see Note 6, "Derivative Instruments," to the consolidated financial statements.

Counterparty Credit:  Counterparty credit risk relates to the risk of loss that Select Energy would incur because of non-performance by counterparties pursuant to the terms of their contractual obligations.  Select Energy has established credit policies with regard to its counterparties to minimize overall credit risk.  These policies require an evaluation of potential counterparties' financial condition (including credit ratings), collateral requirements under certain circumstances (including cash advances, LOCs, and parent guarantees), and the use of standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty.  This evaluation results in establishing credit limits prior to Select Energy's entering into contracts.  The appropriateness of these limits is subject to continuing review.  Concentrations among these counterparties may affect Select Energy's ov erall 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, 2005, approximately 72 percent of Select Energy's counterparty credit exposure to wholesale and trading counterparties was collateralized or rated BBB- or better.  Select Energy was provided $28.9 million and $57.7 million of counterparty deposits at December 31, 2005 and 2004, respectively.  For further information, see Note 1Y, "Summary of Significant Accounting Policies - Counterparty Deposits," to the consolidated financial statements.

Consolidated Edison, Inc. Merger Litigation

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' 1999 merger agreement (Merger Agreement).  On March 12, 2001, NU filed suit against Con Edison seeking damages in excess of $1 billion.  

In an opinion dated October 12, 2005, a panel of three judges at the Second Circuit held that the shareholders of NU had no right to sue Con Edison for its alleged breach of the parties' Merger Agreement.  NU's request for rehearing was denied on January 3, 2006.  This ruling left intact the remaining claims between NU and Con Edison for breach of contract, which include NU’s claim for recovery of costs and expenses of approximately $32 million and Con Edison's claim for damages of "at least $314 million."  NU is currently considering whether to seek review by the United States Supreme Court.  At this stage, NU cannot predict the outcome of this matter or its ultimate effect on NU.  

Off-Balance Sheet Arrangements

Utility Group:  The CL&P Receivables Corporation (CRC) was incorporated on September 5, 1997 and is a wholly owned subsidiary of CL&P. CRC has an agreement with CL&P to purchase and has an arrangement with a highly-rated financial institution under which CRC can sell up to $100 million of an undivided interest in accounts receivable and unbilled revenues. At December 31, 2005 and 2004, CRC had sold an undivided interest in its accounts receivable and unbilled revenues of $80 million and $90 million, respectively, to that financial institution with limited recourse.

CRC was established for the sole purpose of selling CL&P’s accounts receivable and unbilled revenues and is included in the consolidated NU financial statements.On July 6, 2005, CRC renewed its Receivables Purchase and Sale Agreement with CL&P and the financial institution through July 5, 2006.  CL&P’s continuing involvement with the receivables that are sold to CRC and the financial institution is limited to the servicing of those receivables.

The transfer of receivables to the financial institution under this arrangement qualifies for sale treatment under Statement of Financial Accounting Standards (SFAS) No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities - A Replacement of SFAS No. 125."  Accordingly, the $80 million and $90 million outstanding under this facility are not reflected as debt or included in the consolidated financial statements at December 31, 2005 and 2004, respectively.

This off-balance sheet arrangement is not significant to NU’s liquidity or other benefits. There are no known events, demands, commitments, trends, or uncertainties that will, or are reasonably likely to, result in the termination, or material reduction in the amount available to the company under this off-balance sheet arrangement.

NU Enterprises:  During 2001, SESI created HEC/CJTS Energy Center LLC (HEC/CJTS) which is a special purpose entity (SPE). SESI created HEC/CJTS for the sole purpose of providing a bankruptcy remote entity for the financing of an energy center to serve the Connecticut Juvenile Training School (CJTS).  The owner of CJTS, the State of Connecticut, entered into a 20-year lease with a 10-year renewal option with HEC/CJTS for the energy center.  Simultaneously, HEC/CJTS transferred its interest in the lease with the State of Connecticut to investors who are unaffiliated with NU in exchange for the issuance of $19.2 million of Certificates of Participation.  The transfer of HEC/CJTS’ interest in the lease was accounted for as a sale under SFAS No. 140.  The debt of $19.2 million created in relation to the transfer of interest and issuance of the Certificates of Participation was derecognized and is not reflected as debt or i ncluded in the consolidated financial statements.  No gain or loss was recorded.  HEC/CJTS does not provide any guarantees or on-going services, and there are no contingencies related to this arrangement.  SESI has a separate contract with the State of Connecticut to operate and maintain the energy center.  The transaction was structured in this manner to obtain tax-exempt financing and therefore to reduce the State of Connecticut’s lease payments.  This off-balance sheet arrangement is not significant to NU’s liquidity, capital resources or other benefits.

SESI entered into a master purchase agreement with an unaffiliated third party on April 30, 2002 under which SESI may sell certain receivables that are due or become due under delivery orders issued pursuant to federal energy savings performance contracts.  At December 31, 2005, SESI had sold $38.6 million of receivables related to the installation of the energy efficiency projects under this arrangement.  The transfer of receivables to the unaffiliated third party under this arrangement qualified as a sale under SFAS No. 140.  Accordingly, the $38.6 million sold at December 31, 2005 is not included as debt in the consolidated financial statements.  Under the delivery order with the United States government, SESI is responsible for on-going maintenance and other services related to the energy efficiency project installation.  SESI receives payment for those services in addition to the amounts sold under the master purchase agreem ent.

SESI has entered into assignment agreements to sell an additional $17.9 million of receivables.  These sales will be complete upon customer acceptance of the project installations.  Until construction is completed, the advances under the purchase agreement are included in long-term debt in the consolidated financial statements and the receivables are recorded under the percentage of completion method.  

These off-balance sheet arrangements are not significant to NU’s liquidity or other benefits.

Since NU Enterprises is in the process of exiting SESI, NU's consolidated statements of (loss)/income for the years ended December 31, 2005, 2004 and 2003 present the operations for SESI, including HEC/CJTS, as discontinued operations as a result of meeting certain criteria requiring this presentation.  For further information regarding this classification, see Note 4, "Assets Held for Sale and Discontinued Operations," to the consolidated financial statements.  These off-balance sheet arrangements are expected to be assigned to the purchaser when SESI is exited.  

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates, assumptions and at times difficult, subjective or complex judgments.  Changes in these estimates, assumptions and judgments, in and of themselves, could materially impact the financial statements of NU.  Management communicates to and discusses with NU’s Audit Committee of the Board of Trustees all critical accounting policies and estimates.  The following are the accounting policies and estimates that management believes are the most critical in nature.

Discontinued Operations Presentation:  In order for discontinued operations treatment to be appropriate, management must conclude that there is a component of a business that is "held for sale" in accordance with the provisions of SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," and that it meets the criteria for discontinued operations.  Based on the status of exiting these businesses, discontinued operations presentation is only appropriate for SESI, SECI-NH, Woods Network and Woods Electrical, all of which relate to the energy services businesses.  In the fourth quarter of 2005, NU Enterprises sold SECI-NH and Woods Network to unaffiliated buyers for approximately $6.5 million.  In January of 2006, the Massachusetts service location of SECI-CT was sold for approximately $2 million.  

For further information regarding these companies, see Note 4, "Assets Held for Sale and Discontinued Operations," to the consolidated financial statements.  Management will continue to evaluate this classification in 2006 for the NU Enterprises' energy services businesses, as well as the wholesale and retail marketing businesses and the competitive generation business that are being exited.

Impairment of Long-Lived Assets:  The company evaluates long-lived assets such as property, plant and equipment to determine if these assets are impaired when events or changes in circumstances occur such as the 2005 announced decisions to exit all of the NU Enterprises businesses.  

When the company believes one of these events has occurred, the determination needs to be made if a long-lived asset should be classified as an asset to be held and used or if that asset should be classified as held for sale.  For assets classified as held and used, the company estimates the undiscounted future cash flows associated with the long-lived asset or asset group and an impairment loss is recognized if the carrying amount of an asset is not recoverable and exceeds its fair value.  The carrying amount is not recoverable if it exceeds the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset.  For assets held for sale, a long-lived asset or disposal group is measured at the lower of its carrying amount or fair value less cost to sell.  

In order to estimate an asset's future cash flows, the company considers historical cash flows, changes in the market and other factors that may affect future cash flows.  The company considers various relevant factors, including the method and timing of recovery, forward price curves for energy,

fuel costs, and operating costs.  Actual future market prices, costs and cash flows could vary significantly from those assumed in the estimates, and the impact of such variations could be material.

In 2005, management evaluated the wholesale and retail marketing businesses and competitive generation long-lived assets and determined that these assets should continue to be classified as assets to be held and used.  As assets to be held and used, they are required to be tested for impairment because of the expectation that the long-lived assets in these groups will be disposed of significantly before the end of their previously estimated useful lives.  As a result of impairment analyses performed, assets totaling $8 million were determined to be impaired and were written off.  At December 31, 2005, NU determined that no impairment existed for the competitive generation business generation assets based on NU's evaluation of their fair value using discounted cash flows and an analysis of reference transactions.

In 2005, management also evaluated the energy services businesses and determined that the assets of SESI, Woods Electrical, SECI-NH, and Woods Network should be classified as assets held for sale.  As a result of impairment analyses performed, the company impaired certain fixed assets by $0.8 million.

The assets and liabilities of the wholesale and retail marketing and competitive generation businesses, along with the remaining two energy services businesses, SECI-CT and Boulos, are being accounted for as assets to be held and used.  A change in classification from assets to be held and used to assets held for sale may result in additional asset impairments and write-offs.

For further information regarding these impairment charges and assets held for sale, see Note 3, "Restructuring and Impairment Charges," and Note 4, "Assets Held for Sale and Discontinued Operations," to the consolidated financial statements.

Goodwill and Intangible Assets:  SFAS No. 142, "Goodwill and Other Intangible Assets," requires that goodwill balances be reviewed for impairment at least annually by applying a fair value-based test.  NU selected October 1^st as the annual goodwill impairment testing date.  Goodwill impairment is deemed to exist if the net book value of a reporting unit exceeds its estimated fair value and if the implied fair value of goodwill based on the estimated fair value of the reporting unit is less than the carrying amount of the goodwill.  If goodwill is deemed to be impaired it is written-off to the extent it is impaired.  The impact of this goodwill impairment review would be limited to Yankee Gas.  During 2005, the goodwill and intangible asset balances previously recorded by NU Enterprises totaling $50.7 million were written off.  

NU has completed its impairment analysis as of October 1, 2005 for Yankee Gas and has determined that no impairment exists.  In performing the required impairment evaluation, NU estimated the fair value of the Yankee Gas reporting unit and compared it to the carrying amount of the reporting unit, including goodwill.  NU estimated the fair value of Yankee Gas using discounted cash flow methodologies and an analysis of comparable companies or transactions.  The discounted cash flow analysis requires the input of several critical assumptions, including future growth rates, operating cost escalation rates, allowed ROE, a risk-adjusted discount rate, and long-term earnings multiples of comparable companies.  These assumptions are critical to the estimate and can change from period to period.

Modifications to these assumptions in future periods, particularly changes in discount rates, could result in future impairments of goodwill. Actual financial performance and market conditions in upcoming periods could also impact future impairment analyses.

For further information, see Note 8, "Goodwill and Other Intangible Assets," to the consolidated financial statements.  

Revenue Recognition:  Utility Group retail revenues are based on rates approved by the state regulatory commissions. These regulated rates are applied to customers’ use of energy to calculate a bill. In general, rates can only be changed through formal proceedings with the state regulatory commissions.

The determination of the energy sales to individual customers is based on the reading of meters, which occurs on a systematic basis throughout the month.  Billed revenues are based on these meter readings.  At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and an estimated amount of unbilled revenues is recorded.

Certain Utility Group companies utilize regulatory commission-approved tracking mechanisms to track the recovery of certain incurred costs. The tracking mechanisms allow for rates to be changed periodically, with overcollections refunded to customers or undercollections collected from customers in future periods.

Wholesale transmission revenues are based on rates and formulas that are approved by the FERC.  Most of NU’s wholesale transmission revenues are collected through a combination of the RNS tariff and NU’s LNS tariff.  The RNS tariff, which is administered by ISO-NE, recovers the revenue requirements associated with transmission facilities that are deemed by the FERC to be Pool Transmission Facilities.  The LNS tariff, which was accepted by the FERC, provides for the recovery of NU’s total transmission revenue requirements, net of revenue credits received from various rate components, including revenues received under the RNS rates.  At December 31, 2005, this true-up has resulted in the recognition of a $2.1 million regulatory liability, including approximately $1.5 million due to NU's electric distribution companies.  

A significant portion of the NU transmission business revenue comes from ISO-NE charges to the distribution businesses of CL&P, PSNH and WMECO.  The distribution businesses recover these costs through the retail rates that are charged to their retail customers.  In July of 2005, CL&P began tracking its retail transmission revenues and expenses and will adjust its retail transmission rates on a regular basis, thereby recovering all of its retail transmission expenses on a timely basis.  This new tracking mechanism resulted from the enactment of the new legislation passed by the Connecticut legislature in 2005.  WMECO implemented its retail transmission tracker and rate adjustment mechanism in January of 2002 as part of its 2002 rate change filing.  PSNH does not currently have a retail transmission rate tracking mechanism.   

NU Enterprises' revenues are recognized at different times for its different business lines.  Wholesale marketing revenues were recognized when energy was delivered up to and including the first quarter of 2005.  Subsequent to March 31, 2005, as a result of going to mark-to-market accounting, these revenues were still recognized when delivered, however, they were reclassified to fuel, purchased and net interchange power.  Retail marketing revenues are recognized when energy is delivered.  Service revenues are recognized as services are provided, often on a percentage of completion basis.  

Revenues and expenses for derivative contracts that are entered into for trading purposes are recorded on a net basis in revenues when these transactions settle.  The settlement of wholesale non-trading derivative contracts for the sale of energy or gas by the Utility Group that are related to customers' needs are recorded net in operating expenses.   For further information regarding the accounting for these contracts, see Note 1F, "Summary of Significant Accounting Policies - Derivative Accounting," to the consolidated financial statements.

Utility Group Unbilled Revenues:  Unbilled revenues represent an estimate of electricity or gas delivered to customers that has not yet been billed. Unbilled revenues are included in revenue on the accompanying consolidated statements of (loss)/income and are assets on the accompanying consolidated balance sheets that are reclassified to accounts receivable in the following month as customers are billed.

The estimate of unbilled revenues is sensitive to numerous factors that can significantly impact the amount of revenues recorded.  Estimating the impact of these factors is complex and requires management’s judgment.  The estimate of unbilled revenues is important to NU’s consolidated financial statements as adjustments to that estimate could significantly impact operating revenues and earnings.

Through December 31, 2004, the Utility Group estimated unbilled revenues monthly using the requirements method.  The requirements method utilized the total monthly volume of electricity or gas delivered to the system and applied a delivery efficiency (DE) factor to reduce the total monthly volume by an estimate of delivery losses in order to calculate total estimated monthly sales to customers.  The total estimated monthly sales amount less the total monthly billed sales amount resulted in a monthly estimate of unbilled sales.  Unbilled revenues were estimated by first allocating sales to the respective rate classes, then applying an average rate to the estimate of unbilled sales.  The estimated DE factor had a significant impact on estimated unbilled revenue amounts.

In the first quarter of 2005, management adopted a new method to estimate unbilled revenues for CL&P, PSNH, WMECO, and Yankee Gas.  The new method allocates billed sales to the current calendar month based on the daily load for each billing cycle (DLC method).  The billed sales are subtracted from total calendar month sales to estimate unbilled sales.  The impact of adopting the new method was not material.  This new method replaces the requirements method described previously.  

Derivative Accounting:  Certain of the contracts comprising Select Energy’s wholesale marketing and competitive generation activities are derivatives, and certain Utility Group contracts for the purchase or sale of energy or energy-related products are derivatives.  Most retail marketing contracts with retail customers are not derivatives, while virtually all contracts entered into to supply these customers are derivatives.  The application of derivative accounting rules is complex and requires management judgment in the following respects: election and designation of the normal purchases and sales exception, identification of derivatives and embedded derivatives, identifying hedge relationships, assessing and measuring hedge ineffectiveness, and determining the fair value of derivatives.  All of these judgments, depending upon their timing and effect, can have a significant impact on NU’s consolidated net income.

The fair value of derivatives is based upon the notional amount of a contract and the underlying market price or fair value per unit.  When quantities are not specified in the contract, the company estimates notional amounts using amounts referenced in default provisions and other relevant sections of the contract.  The notional amount is updated during the term of the contract, and updates can have a material impact on mark-to-market amounts.  

The judgment applied in the election of the normal purchases and sales exception (and resulting accrual accounting) includes the conclusions that it is probable at the inception of the contract and throughout its term that it will result in physical delivery and that the quantities will be used or sold by the business over a reasonable period in the normal course of business.  If facts and circumstances change and management can no longer support this conclusion, then the normal exception and accrual accounting would be terminated and fair value accounting would be applied.  Cash flow hedge contracts that are designated as hedges for contracts for which the company has elected the normal purchases and sales exception can continue to be accounted for as cash flow hedges only if the normal exception for the hedged contract continues to be appropriate.  If the normal exception is terminated because delivery is no longer probable of occurring, then the hedge designation would be terminated at the same time.

For the period April 1, 2005 to December 31, 2005, Select Energy reported the settlement of derivative and non-derivative retail sales and certain other derivative contracts that physically deliver in revenues and the associated derivative and non-derivative contracts to supply these contracts in fuel, purchased and net interchange power.  In addition, Select Energy reported the settlement of all derivative wholesale contracts, including full requirements sales contracts, in fuel, purchased and net interchange power as a result of applying mark-to-market accounting to those contracts.  Certain generation-related derivative contracts that are marked-to-market were recorded in revenues.

Prior to April 1, 2005, Select Energy reported the settlement of long-term derivative contracts, including full requirements sales contracts that physically delivered and were not held for trading purposes on a gross basis, generally with sales in revenues and purchases in expenses.  Retail sales contracts are physically delivered and recorded in revenues.  Short-term sales and purchases represent power and natural gas that was purchased to serve contracts but was ultimately not needed based on the actual load of the customers.  This excess power and natural gas was sold to the independent system operator or to other counterparties.  For the years ended December 31, 2004 and 2003, settlements of these short-term derivative contracts that are not held for trading purposes, were reported on a net basis in fuel, purchased and net interchange power.

The Utility Group reports the settlement of all short-term sales contracts that are part of procurement activities on a net basis in expenses.

Regulatory Accounting:  The accounting policies of NU’s regulated utility companies historically reflect the effects of the rate-making process in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation."  The transmission and distribution businesses of CL&P, PSNH and WMECO, along with PSNH’s generation business and Yankee Gas’ distribution business, continue to be cost-of-service rate regulated, and management believes the application of SFAS No. 71 to those businesses continues to be appropriate.  Management must reaffirm this conclusion at each balance sheet date.  If, as a result of a change in circumstances, it is determined that any portion of these companies no longer meets the criteria of regulatory accounting under SFAS No. 71, that portion of the company will have to discontinue regulatory accounting and write-off the respective reg ulatory assets and liabilities.  Such a write-off could have a material impact on NU’s, CL&P's, PSNH's, WMECO's and Yankee Gas' financial statements.

The application of SFAS No. 71 results in recording regulatory assets and liabilities.  Regulatory assets represent the deferral of incurred costs that are probable of future recovery in customer rates.  In some cases, NU records regulatory assets before approval for recovery has been received from the applicable regulatory commission.  Management must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery.  Management bases its conclusion on certain factors, including changes in the regulatory environment, recent rate orders issued by the applicable regulatory agencies and the status of any potential new legislation.  Regulatory liabilities represent revenues received from customers to fund expected costs that have not yet been incurred or are probable future refunds to customers.

Management uses its best judgment when recording regulatory assets and liabilities; however, regulatory commissions can reach different conclusions about the recovery of costs, and those conclusions could have a material impact on NU’s consolidated financial statements.  Management believes it is probable that the Utility Group companies will recover the regulatory assets that have been recorded.

Presentation:  In accordance with current accounting pronouncements, NU’s consolidated financial statements include all subsidiaries upon which control is maintained and all variable interest entities (VIE).  Determining whether the company is the primary beneficiary of a VIE is subjective and requires management’s judgment.  There are certain variables taken into consideration to determine whether the company is considered the primary beneficiary of the VIE.  A change in any one of these variables could require the company to reconsider whether or not it is the primary beneficiary of the VIE.  All intercompany transactions between these subsidiaries are eliminated as part of the consolidation process.

NU has less than 50 percent ownership interests in CYAPC, YAEC, MYAPC, and two companies that transmit electricity imported from the Hydro-Quebec system.  NU does not control these companies and does not consolidate them in its financial statements.  NU accounts for the investments in these companies using the equity method.  Under the equity method, NU records its ownership share of the earnings or losses at these companies.  Determining whether or not NU should apply the equity method of accounting for an investment requires management judgment.

NU had a preferred stock investment in R. M. Services, Inc. (RMS). Upon adoption of Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46, "Consolidation of Variable Interest Entities," management determined that NU was the primary beneficiary of RMS and subsequently consolidated RMS into its financial statements.  The consolidation of RMS resulted in a negative $4.7 million after-tax cumulative effect of an accounting change in the third quarter of 2003.  On June 30, 2004, the assets and liabilities of RMS were sold.  For more information on RMS, see Note 1I, "Summary of Significant Accounting Policies - Accounting for R.M. Services, Inc." to the consolidated financial statements.

In December of 2003, the FASB issued a revised version of FIN 46 (FIN 46R).  FIN 46R was effective for NU for the first quarter of 2004 and did not have an impact on NU’s consolidated financial statements.

Pension and Postretirement Benefits Other Than Pensions (PBOP):  NU’s subsidiaries participate in a uniform noncontributory defined benefit retirement plan (Pension Plan) covering substantially all regular NU employees. NU also participates in a postretirement benefit plan (PBOP Plan) to provide certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired employees. For each of these plans, the development of the benefit obligation, fair value of plan assets, funded status and net periodic benefit credit or cost is based on several significant assumptions. If these assumptions were changed, the resulting change in benefit obligations, fair values of plan assets, funded status and net periodic benefit credits or costs could have a material impact on NU’s consolidated financial statements.

Pre-tax periodic pension expense/income for the Pension Plan totaled an expense of $42.5 million, an expense of $5.9 million and income of $31.8 million for the years ended December 31, 2005, 2004 and 2003, respectively.  The pension expense/income amounts exclude one-time items recorded under SFAS No. 88, "Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits."

The pre-tax net PBOP Plan cost, excluding curtailments and termination benefits, totaled $49.8 million, $41.7 million and $35.1 million for the years ended December 31, 2005, 2004 and 2003, respectively.

As a result of the decision to pursue a fundamentally different business strategy, and align the structure of the company to support this business strategy, NU recorded a $2.7 million pre-tax curtailment expense in 2005 for the Pension Plan.  NU also accrued certain related termination benefits and recorded a $2.8 million pre-tax charge in 2005 for the Pension Plan.  Additional termination benefits may be recorded in 2006.

On December 15, 2005, the NU Board of Trustees approved a benefit for new non-union employees hired on and after January 1, 2006 to receive retirement benefits under a new 401(k) benefit rather than under the Pension Plan.  Non-union employees actively employed on December 31, 2005 will be given the choice in 2006 to elect to continue participation in the Pension Plan or instead receive a new employer contribution under the 401(k) Savings Plan effective January 1, 2007.  If the new benefit is elected, their accrued pension liability in the Pension Plan will be frozen as of December 31, 2006.  Non-union employees will make this election in the second half of 2006.  This decision resulted in the recording of an estimated pre-tax curtailment expense of $6.2 million in 2005, as a certain number of employees are expected to elect the new 401(k) benefit, resulting in a reduction in aggregate estimated future years of service under the Pension Plan.  Management estimated the amount of the curtailment expense

associated with this change based upon actuarial calculations and certain assumptions, including the expected level of transfers to the new 401(k) benefit.  Any adjustments to this estimate resulting from actual employee elections will be recorded in 2006.

In April of 2004, as a result of litigation with nineteen former employees, NU was ordered by the court to modify its Pension Plan to include special retirement benefits for fifteen of these former employees retroactive to the dates of their retirement and provide increased future monthly benefit payments.  NU recorded $2.1 million in termination benefits related to this litigation in 2004 and made a lump sum benefit payment totaling $1.5 million to these former employees.

For the PBOP Plan, NU recorded an estimated $3.7 million pre-tax curtailment expense at December 31, 2005 relating to NU's change in business strategy.  NU also accrued a $0.5 million pre-tax termination benefit at December 31, 2005 relating to certain benefits provided under the terms of the PBOP Plan.  Additional termination benefits may be recorded in 2006.

There were no curtailments or termination benefits recorded for the Pension Plan or PBOP Plan in 2003.

Long-Term Rate of Return Assumptions:  In developing the expected long-term rate of return assumptions, NU evaluated input from actuaries and consultants, as well as long-term inflation assumptions and NU’s historical 20-year compounded return of approximately 11 percent. NU’s expected long-term rates of return on assets is based on certain target asset allocation assumptions and expected long-term rates of return. NU believes that 8.75 percent is a reasonable long-term rate of return on Pension Plan and PBOP Plan assets (life assets and non-taxable health assets) and 6.85 percent for PBOP health assets, net of tax for 2005. NU will continue to evaluate these actuarial  assumptions, including the expected rate of return, at least annually, and will adjust the appropriate assumptions as necessary. The Pension Plan’s and PBOP Plan’s target asset allocation assumptions and expected long-term rates of return assump tions by asset category are as follows:

	At December 31,
	Pension Benefits		Postretirement Benefits
	2005 and 2004		2005 and 2004
	Target Asset Allocation	Assumed Rate of Return	Target Asset Allocation	Assumed Rate of Return
Equity securities:
United States	45%	9.25%	55%	9.25%
Non-United States	14%	9.25%	11%	9.25%
Emerging markets	3%	10.25%	2%	10.25%
Private	8%	14.25%	-	-
Debt Securities:
Fixed income	20%	5.50%	27%	5.50%
High yield fixed income	5%	7.50%	5%	7.50%
Real estate	5%	7.50%	-	-

The actual asset allocations at December 31, 2005 and 2004 approximated these target asset allocations.  NU routinely reviews the actual asset allocations and periodically rebalances the investments to the targeted asset allocations when appropriate.  For information regarding actual asset allocations, see Note 7, "Employee Benefits - Pension Benefits and Postretirement Benefits Other Than Pensions," to the consolidated financial statements.

Actuarial Determination of Income and Expense:  NU bases the actuarial determination of Pension Plan and PBOP Plan income/expense on a market-related valuation of assets, which reduces year-to-year volatility.  This market-related valuation calculation recognizes investment gains or losses over a four-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the fair value of assets.  Since the market-related valuation calculation recognizes gains or losses over a four-year period, the future value of the market-related assets will be impacted as previously deferred gains or losses are recognized.  There will be no impact on the fair value of Pension Plan and PBOP Plan assets in the trust funds of these plans.

At December 31, 2005, the Pension Plan had cumulative unrecognized investment gains of $77.6 million, which will decrease pension expense over the next four years.  At December 31, 2005, the Pension Plan had cumulative unrecognized actuarial losses of $498.7 million, which will increase pension expense over the expected future working lifetime of active Pension Plan participants, or approximately 13 years.  The combined total of unrecognized investment gains and actuarial losses at December 31, 2005 is a net unrecognized loss of $421.1 million.  These gains and losses impact the determination of pension expense and the actuarially determined prepaid pension amount recorded on the consolidated balance sheets but have no impact on expected Pension Plan funding.

At December 31, 2005, the PBOP Plan had cumulative unrecognized investment gains of $47.5 million, which will decrease PBOP Plan expense over the next four years. At December 31, 2005, the PBOP Plan also had cumulative unrecognized actuarial losses of $227.4 million, which will increase PBOP Plan expense over the expected future working lifetime of active PBOP Plan participants, or approximately 13 years. The combined total of unrecognized investment gains and actuarial losses at December 31, 2005 is a net unrecognized loss of $179.9 million. These gains and losses impact the determination of PBOP Plan cost and the actuarially determined accrued PBOP Plan cost recorded on the consolidated balance sheets.

Discount Rate:  The discount rate that is utilized in determining future pension and PBOP obligations is based on a yield-curve approach where each cash flow related to the Pension Plan or PBOP Plan liability stream is discounted at an interest rate specifically applicable to the timing of the cash flow.  The yield curve is developed from the top quartile of AA rated Moody’s and S&P’s bonds without callable features outstanding at

December 31, 2005.  This process calculates the present values of these cash flows and calculates the equivalent single discount rate that produces the same present value for future cash flows.  The discount rates determined on this basis are 5.80 percent for the Pension Plan and 5.65 percent for the PBOP Plan at December 31, 2005.  Discount rates used at December 31, 2004 were 6.00 percent for the Pension Plan and 5.50 percent for the PBOP Plan.

Expected Contributions and Forecasted Expense:  Due to the effect of the unrecognized actuarial losses and based on an expected rate of return on Pension Plan assets of 8.75 percent, a discount rate of 6.00 percent and an expected rate of return on PBOP assets of 6.85 percent for health assets, net of tax and 8.75 percent for life assets and nontaxable health assets, a discount rate of 5.50 ­­­percent and various other assumptions, NU estimates that expected contributions to and forecasted expense for the Pension Plan and PBOP Plan will be as follows (in millions):

	Pension Plan		Postretirement Plan
Year	Expected Contributions	Forecasted Expense	Expected Contributions	Forecasted Expense
2006	$0	$51.6	$49.5	$49.5
2007	$0	$32.5	$41.7	$41.7
2008	$0	$28.1	$39.6	$39.6

Future actual pension and postretirement expense will depend on future investment performance, changes in future discount rates and various other factors related to the populations participating in the plans and amounts capitalized.

Sensitivity Analysis: The following represents the increase/(decrease) to the Pension Plan’s and PBOP Plan’s reported cost as a result of a change in the following assumptions by 50 basis points (in millions):

	At December 31,
	Pension Plan		Postretirement Plan
Assumption Change	2005	2004	2005	2004
Lower long-term  rate of return	$10.0	$10.0	$0.9	$0.7
Lower discount rate	$15.6	$13.4	$1.1	$1.0
Lower compensation   increase	$(7.3)	$(5.8)	N/A	N/A

Plan Assets:  The market-related value of the Pension Plan assets has increased by $47.1 million to $2.1 billion at December 31, 2005. The projected benefit obligation (PBO) for the Pension Plan has also increased by $153 million to $2.3 billion at December 31, 2005.  These changes have increased the underfunded status of the Pension Plan on a PBO basis from an underfunded position of $57.7 million at December 31, 2004 to an underfunded position of $163.6 million at December 31, 2005. The PBO includes expectations of future employee compensation increases. The accumulated benefit obligation (ABO) of the Pension Plan was approximately $62 million less than Pension Plan assets at December 31, 2005 and approximately $225 million less than Pension Plan assets at December 31, 2004.  The ABO is the obligation for employee service and compensation provided through December 31, 2005.  Under current accounting rules, if the ABO exceeds Pension Plan assets at a future plan measurement date, NU will record an additional minimum liability.  NU has not made employer contributions to the Pension Plan since 1991.

The value of PBOP Plan assets has increased from $199.8 million at December 31, 2004 to $222.9 million at December 31, 2005.  The benefit obligation for the PBOP Plan has also increased from $468.3 million at December 31, 2004 to $493.8 million at December 31, 2005.  These changes have increased the underfunded status of the PBOP Plan on an accumulated projected benefit obligation basis from $268.5 million at December 31, 2004 to $270.9 million at December 31, 2005.  NU has made a contribution each year equal to the PBOP Plan’s postretirement benefit cost, excluding curtailment and termination benefits.

Health Care Cost: The health care cost trend assumption used to project increases in medical costs was 7 percent for 2005 and 8 percent for 2004, decreasing one percentage point per year to an ultimate rate of 5 percent in 2007.  For December 31, 2005 disclosure purposes, the health care cost trend assumption was reset for 2006 at 10 percent, decreasing one percentage point per year to an ultimate rate of 5 percent in 2011.  The effect of increasing the health care cost trend by one percentage point would have increased service and interest cost components of the PBOP Plan cost by $0.9 million in 2005 and $1 million in 2004.

Income Taxes: Income tax expense is calculated each year in each of the jurisdictions in which NU operates.  This process involves estimating NU’s actual current tax exposures as well as assessing temporary differences resulting from differing treatment of items, such as timing of the deduction and expenses for tax and book accounting purposes.  These differences result in deferred tax assets and liabilities, which are included in NU’s consolidated balance sheets.  The income tax estimation process impacts all of NU’s segments and adjustments made to income taxes could significantly affect NU’s consolidated financial statements.  Management must also assess the likelihood that deferred tax assets will be recovered from future taxable income, and to the extent that recovery is not likely, a valuation allowance must be established.  Significant management judgment is required in determining income tax exp ense, deferred tax assets and liabilities and valuation allowances.

NU accounts for deferred taxes under SFAS No. 109, "Accounting for Income Taxes."  For temporary differences recorded as deferred tax liabilities that will be recovered in rates in the future, NU has established a regulatory asset.  The regulatory asset amounted to $332.5 million and $316.3 million at December 31, 2005 and 2004, respectively.  Regulatory agencies in certain jurisdictions in which NU’s Utility Group companies operate require the tax effect of specific temporary differences to be "flowed through" to utility customers.  Flow through treatment means that deferred tax expense is not recorded on the consolidated statements of (loss)/income.  Instead, the tax effect of the temporary difference impacts both amounts for income tax expense currently included in customers’ rates and the company’s net income.  Flow through treatment can result in effective income tax

rates that are significantly different than expected income tax rates.  Recording deferred taxes on flow through items is required by SFAS No. 109, and the offset to the deferred tax amounts is the regulatory asset referred to above.

A reconciliation from expected tax expense at the statutory federal income tax rate to actual tax expense recorded is included in the accompanying footnotes to the consolidated financial statements.  See Note 1H, "Summary of Significant Accounting Policies - Income Taxes," to the consolidated financial statements for further information.

The estimates that are made by management in order to record income tax expense, accrued taxes and deferred taxes are compared each year to the actual tax amounts filed on NU’s income tax returns. The income tax returns were filed in the fall of 2005 for the 2004 tax year, and NU recorded differences between income tax expense, accrued taxes and deferred taxes on its consolidated financial statements and the amounts that were on its income tax returns.

Depreciation:  Depreciation expense is calculated based on an asset’s useful life, and judgment is involved when estimating the useful lives of certain assets.  A change in the estimated useful lives of these assets could have a material impact on NU’s consolidated financial statements absent timely rate relief for Utility Group assets.

Accounting for Environmental Reserves:  Environmental reserves are accrued using a probabilistic model approach when assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated. Adjustments made to environmental liabilities could have a significant effect on earnings.  The probabilistic model approach estimates the liability based on the most likely action plan from a variety of available remediation options, ranging from no action to remedies ranging from establishing institutional controls to full site remediation and long-term monitoring.  The probabilistic model approach estimates the liabilities associated with each possible action plan based on findings through various phases of site assessments.

These estimates are based on currently available information from presently enacted state and federal environmental laws and regulations and several cost estimates from outside engineering and remediation contractors.  These amounts also take into consideration prior experience in remediating contaminated sites and data released by the United States Environmental Protection Agency and other organizations.  These estimates are subjective in nature partly because there are usually several different remediation options from which to choose when working on a specific site.  These estimates are subject to revisions in future periods based on actual costs or new information concerning either the level of contamination at the site or newly enacted laws and regulations.  The amounts recorded as environmental liabilities on the consolidated balance sheets represent management’s best estimate of the liability for environmental costs based on current site information from site assessments and remediation estimates.  These liabilities are estimated on an undiscounted basis.

PSNH and Yankee Gas have regulatory recovery mechanisms in place for environmental costs.  Accordingly, regulatory assets have been recorded for certain of PSNH’s and Yankee Gas’ environmental liabilities.  As of December 31, 2005 and 2004, $24.7 million and $28 million, respectively, have been recorded as regulatory assets on the accompanying consolidated balance sheets.  CL&P recovers a certain level of environmental costs currently in rates but does not have an environmental cost recovery tracking mechanism. Accordingly, changes in CL&P’s environmental reserves impact CL&P’s earnings. WMECO does not have a regulatory mechanism to recover environmental costs from its customers, and changes in WMECO’s environmental reserves impact WMECO’s earnings.

Asset Retirement Obligations:  On March 30, 2005, the FASB issued FIN 47, "Accounting for Conditional Asset Retirement Obligations - an Interpretation of FASB Statement No. 143."  FIN 47 requires an entity to recognize a liability for the fair value of an ARO that is conditional on a future event if the liability’s fair value can be reasonably estimated.  NU adopted FIN 47 on December 31, 2005.  Upon adoption, management identified several conditional removal obligations that have been accounted for as AROs.  A cumulative effect of an accounting change reflecting a $1 million after-tax loss related to the adoption of FIN 47 is included on the accompanying consolidated statements of (loss)/income.  For further information regarding the adoption of FIN 47, see Note 1P, "Summary of Significant Accounting Policies – Asset Retirement Obligations," to the consolidated financial statements.

Under SFAS No. 71, regulated utilities, including NU’s Utility Group companies, currently recover amounts in rates for future costs of removal of plant assets.  At December 31, 2005 and 2004, these amounts totaling $305.5 million and $328.8 million, respectively, are classified as regulatory liabilities on the accompanying consolidated balance sheets.

Special Purpose Entities:  In addition to SPEs that are described in the "Off-Balance Sheet Arrangements" section of this management’s discussion and analysis, during 2001 and 2002, to facilitate the issuance of rate reduction bonds and certificates intended to finance certain stranded costs, NU established four SPEs: CL&P Funding LLC, PSNH Funding LLC, PSNH Funding LLC 2, and WMECO Funding LLC (the funding companies).  The funding companies were created as part of state-sponsored securitization programs.  The funding companies are restricted from engaging in non- related activities and are required to operate in a manner intended to reduce the likelihood that they would be included in their respective parent company’s bankruptcy estate if they ever become involved in a bankruptcy proceeding.  The funding companies and the securitization amounts are consolidated in the accompanying consolidated financial statements.

During 1999, SESI established an SPE, HEC/Tobyhanna Energy Project, Inc. (HEC/Tobyhanna), in connection with a federal energy savings performance project located at the United States Army Depot in Tobyhanna, Pennsylvania.  HEC/Tobyhanna sold $26.5 million of Certificates related to the project and used the funds to repay SESI for the costs of the project.  HEC/Tobyhanna’s activities and Certificates are included in NU’s consolidated financial statements.  NU Enterprises is in the process of exiting SESI.  

Other Matters

Commitments and Contingencies:  For further information regarding other commitments and contingencies, see Note 9, "Commitments and Contingencies," to the consolidated financial statements.

Accounting Standards Issued But Not Yet Adopted:

Share-Based Payments:  On December 16, 2004, the FASB issued SFAS No. 123 (Revised 2004), "Share-Based Payments," (SFAS No. 123R), which amended SFAS No. 123, "Accounting for Stock-Based Compensation."  Under the provisions of SFAS No. 123R, NU will recognize compensation expense for the unvested portion of previously granted awards outstanding beginning on January 1, 2006, the effective date of SFAS No. 123R, and any new awards after that date.  The adoption of SFAS No. 123R is not expected to have a material impact on NU’s consolidated financial statements.  For information regarding current accounting for equity-based compensation, see Note 1N, "Summary of Significant Accounting Policies - Equity-Based Compensation," to the consolidated financial statements.

Accounting Changes and Error Corrections: In May of 2005, the FASB issued SFAS No. 154, "Accounting Changes and Error Corrections."  SFAS No. 154 is effective beginning on January 1, 2006 for NU and requires retrospective application to prior periods’ financial statements of voluntary changes in accounting principles.  It also applies to accounting changes required by a new accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions.  SFAS No. 154 does not change previous guidance for reporting the correction of an error in previously issued financial statements or a change in accounting estimate.  Implementation of SFAS No. 154 on January 1, 2006 is not expected to affect NU’s consolidated financial statements until such time that its provisions are required to be applied as described above.

Contractual Obligations and Commercial Commitments:  Information regarding NU’s contractual obligations and commercial commitments at December 31, 2005 is summarized through 2010 and thereafter as follows:

(Millions of Dollars)	2006	2007	2008	2009	2010	Thereafter
Notes payable to banks (a)	$   32.0	$     -	$     -	$      -	$      -	$           -
Long-term debt (a) (b)	22.7	4.1	155.3	56.5	8.0	2,544.5
Estimated interest payments on existing debt	162.7	160.7	157.9	153.4	151.2	1,759.3
Capital leases (c)(d)	2.7	2.6	2.3	2.0	1.5	16.6
Operating leases  (d)(e)	33.4	29.9	26.8	18.8	15.5	42.3
Required funding of other postretirement   benefit obligations (e)	49.5	41.7	39.6	37.5	35.9	N/A
Estimated future annual   Utility Group costs (d)(e)	947.2	508.9	392.7	361.0	330.0	1,273.4
Estimated future annual   NU Enterprises costs  (d)(e)	2,255.0	698.2	323.1	22.6	18.2	5.0
Totals	$3,505.2	$1,446.1	$1,097.7	$651.8	$560.3	$5,641.1

(a)

Included in NU’s debt agreements are usual and customary positive, negative and financial covenants. Non-compliance with certain covenants, for example the timely payment of principal and interest, may constitute an event of default, which could cause an acceleration of principal in the absence of receipt by the company of a waiver or amendment.  Such acceleration would change the obligations outlined in the table of contractual obligations and commercial commitments.

(b)

Long-term debt excludes $268 million of fees and interest due for spent nuclear fuel disposal costs, $5.2 million of net changes in fair value and $3.9 million of net unamortized discounts.

(c)

The capital lease obligations include imputed interest of $13.7 million.

(d)

NU has no provisions in its capital or operating lease agreements or agreements related to the estimated future annual Utility Group or NU Enterprises costs that could trigger a change in terms and conditions, such as acceleration of payment obligations.

(e)

Amounts are not included on NU’s consolidated balance sheets.

Rate reduction bond amounts are non-recourse to NU, have no required payments over the next five years and are not included in this table. The Utility Group’s standard offer service contracts and default service contracts also are not included in this table. The estimated payments under interest rate swap agreements are not included in this table as the estimated payment amounts are not determinable. For further information regarding NU’s contractual obligations and commercial commitments, see the consolidated statements of capitalization and Note 5, "Short-Term Debt," Note 9D, "Commitments and Contingencies - Long-Term Contractual Arrangements," Note 12, "Leases," and Note 13, "Long-Term Debt," to the consolidated financial statements.

Forward Looking Statements:  This discussion and analysis includes statements concerning NU's expectations, plans, objectives, future financial performance and other statements that are not historical facts.  These statements are "forward looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995.  In some cases the reader can identify these forward looking statements by words such as "estimate," "expect," "anticipate," "intend," "plan," "believe," "forecast," "should," "could," and similar expressions.  Forward looking statements involve risks and uncertainties that may cause actual results or outcomes to differ materially from those included in the forward looking statements.  Factors that may cause actual results to differ materially from those included in the forward looking statements include, but are not limited to, actions by state and federal regulatory bodies, competition and industry restructuring, changes in economic conditions, changes in weather patterns, changes in laws, regulations or regulatory policy, expiration or initiation of significant energy supply contracts, changes in levels of capital expenditures, developments in legal or public policy doctrines, technological developments, volatility in electric and natural gas commodity markets, effectiveness

of our risk management policies and procedures, changes in accounting standards and financial reporting regulations, fluctuations in the value of electricity positions, the methods, timing and results of disposition of competitive businesses, actions of rating agencies, terrorist attacks on domestic energy facilities and other presently unknown or unforeseen factors. Other risk factors are detailed from time to time in our reports to the SEC. Management undertakes no obligation to update the information contained in any forward looking statements to reflect developments or circumstances occurring after the statement is made.

Web Site:  Additional financial information is available through NU’s web site at www.nu.com.

RESULTS OF OPERATIONS

The components of significant income statement variances for the past two years are provided in the table below (millions of dollars).  

Income Statement Variances	2005 over/(under) 2004			2004 over/(under) 2003
	Amount	Percent		Amount	Percent
Operating Revenues	$  855	13	%	$599	10	%
Operating Expenses:
Fuel, purchased and net interchange power	702	17		496	13
Other operation	109	11		104	12
Wholesale contract market changes, net	441	100		-	-
Restructuring and impairment charges	44	100		-	-
Maintenance	12	6		13	8
Depreciation	11	5		21	10
Amortization	65	47		(54)	(28)
Amortization of rate reduction bonds	11	7		12	8
Taxes other than income taxes	16	7		11	4
Total operating expenses	1,411	23		603	11
Operating (loss)/income	(556)	(a)		(4)	(1)
Interest expense, net	22	9		7	3
Other income, net	22	(a)		10	(a)
(Loss)/income before income tax (benefit)/expense	(556)	(a)		(1)	-
Income tax (benefit)/expense	(214)	(a)		3	7
Preferred dividends of subsidiary	-	-		-	-
(Loss)/income from continuing operations	(342)	(a)		(4)	(3)
(Loss)/income from discontinued operations	(27)	(a)		(1)	(24)
Cumulative effects of accounting changes, net of tax benefits	(1)	(100)		5	100
Net (loss)/income	$(370)	(a)	%	$    -	-	%

(a) Percent greater than 100.

2005 Compared to 2004

Operating Revenues

Operating revenues increased $855 million in 2005 primarily due to higher electric distribution revenues ($796 million), higher gas distribution revenues ($95 million), and higher regulated transmission business revenues ($24 million), partially offset by lower revenues from NU Enterprises ($59 million).  

The electric distribution revenue increase of $796 million is primarily due to the components of CL&P, PSNH and WMECO retail revenues which are included in regulatory commission approved tracking mechanisms that track the recovery of certain incurred costs ($732 million).  The tracking mechanisms allow for rates to be changed periodically with over collections refunded to customers or under collections collected from customers in future periods.  The distribution revenue tracking components increase of $732 million is primarily due to the pass through of higher energy supply costs ($447 million), CL&P FMCC charges ($235 million) and higher wholesale revenues ($69 million).  The distribution component of these companies and the retail transmission component of PSNH which flow through to earnings increased $65 million primarily due to an increase in retail rates and an increase in retail sales.  Regulated retail sales increased 2.6 percent in 2005 compared with 2004, primarily due to an unseasonably hot third quarter.  On a weather adjusted basis, retail sales were relatively flat.

The higher gas distribution revenue of $95 million is primarily due to the recovery of increased gas costs ($80 million) and the effect of the January 1, 2005 base rate increase ($14 million).

Transmission business revenues increased $24 million primarily due to the recovery of higher operating expenses in 2005 as allowed under FERC Tariff Schedule 21, a higher transmission investment base and the incremental recovery of 2004 expenses.  

The NU Enterprises’ revenue decrease of $59 million is primarily due to lower revenues from the mark-to-market accounting for certain wholesale contracts related to the business to be exited.  As a result of mark-to-market accounting, receipts under those contracts are netted with expenses to serve those contracts and recorded in fuel, purchased and net interchange power, resulting in reduced revenues by approximately $693 million.  Additionally, revenues decreased primarily due to the wholesale marketing business ($385 million) and the services business ($26 million) as a result of lower sales volumes.  These decreases are partially offset by the NU consolidating impact of eliminating lower intercompany revenues from CL&P and WMECO ($687 million) and higher revenues from the retail marketing business as a result of higher rates and volumes ($355 million).

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expense increased $702 million in 2005, primarily due to higher purchased power costs for the Utility Group ($1.34 billion), partially offset by lower costs at NU Enterprises ($642 million).  The $1.34 billion increase for the Utility Group is due to the NU consolidating impact of eliminating lower intercompany TSO purchases from NU Enterprises ($687 million) and higher CL&P and WMECO standard offer supply costs and increased retail sales ($479 million).  The increase is also due to higher PSNH expenses primarily due to higher energy costs and higher retail sales ($98 million) and higher Yankee Gas expenses primarily due to increased gas prices ($80 million).

NU Enterprises’ lower fuel costs of $642 million are primarily due to the mark-to-market accounting for certain wholesale contracts related to the business to be exited ($693 million) as a result of netting revenues with expenses.  Additionally, fuel costs are lower due to the wholesale marketing business ($304 million) primarily due to lower sales volumes.  These decreases are partially offset by higher fuel costs and volumes in the retail marketing business ($355 million).

Other Operation

Other operation expense increased $109 million in 2005, primarily due to higher RMR and other power pool related expenses ($78 million).  In addition, administrative and general expenses increased primarily due to higher pension costs and other benefits ($33 million), employee termination and benefit plan curtailment costs ($27 million) of which $21 million relates to regulated distribution that impact earnings, and higher uncollectible expenses ($7 million).  These increases are partially offset by lower expenses for NU Enterprises as a result of decreased cost of services primarily in the services business ($29 million).  

Wholesale Contract Market Changes, Net

See Note 2, "Wholesale Contract Market Changes," to the consolidated financial statements for a description and explanation of these charges.

Restructuring and Impairment Charges

See Note 3, "Restructuring and Impairment Charges," to the consolidated financial statements for a description and explanation of these charges.

Maintenance

Maintenance expense increased $12 million in 2005, primarily due to increased electric distribution expenses, including higher overhead and underground line, substation and transformer maintenance expenses ($14 million) in part due to heat related and storm activity.  This increase is partially offset by lower maintenance expenses at the generating plants of NU Enterprises and PSNH ($4 million).

Depreciation

Depreciation increased $11 million in 2005 primarily due to higher Utility Group depreciation expense resulting from higher plant balances ($16 million), partially offset by lower Yankee Gas depreciation expense as allowed in the January 1, 2005 rate decision, due to adequate reserve levels for cost of removal ($6 million).

Amortization

Amortization increased $65 million in 2005 primarily due to acceleration in the recovery of PSNH’s non-securitized stranded costs as a result of the positive reconciliation of stranded cost revenues and expenses ($47 million).  Amortization also increased due to higher amortization related to the CL&P’s recovery of transition charges as a result of higher wholesale revenues ($34 million).  These increases are partially offset by lower WMECO recovery of stranded costs ($18 million) primarily due to the decrease in WMECO’s transition component of retail rates.

Amortization of Rate Reduction Bonds

Amortization of rate reduction bonds increased $11 million in 2005 due to the repayment of a higher principal amount as compared to 2004.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $16 million in 2005 primarily due to higher Connecticut gross earnings tax related to higher CL&P and Yankee Gas revenues.

Interest Expense, Net

Interest expense, net increased $22 million in 2005, primarily due to higher interest on long-term debt ($23 million) as a result of Utility Group issuance of new long-term debt in 2005.  New long-term debt of $350 million includes the issuance of $200 million related to CL&P in April and the issuance of $50 million per company related to Yankee Gas, WMECO, and PSNH in July, August and October, respectively.  See the liquidity section for a further description and explanation of the debt issued.  Interest expense, net is also higher due to higher short-term debt levels primarily at NU Parent ($6 million).  In addition, interest expense, net increased at CL&P due to higher other interest as a result of the final streetlight refund docket ($3 million).  These increases are partially offset by lower rate reduction bond interest resulting from lower principal balances outstanding at CL&P, PSNH and WMECO ($11 million). &nb sp;

Other Income, Net

Other income, net increased $22 million in 2005 primarily due to higher allowance for funds used in construction ($8 million), higher investment income ($8 million), a net decrease in investment write-downs ($7 million), and a higher CL&P procurement fee ($6 million), partially offset by a 2005 environmental reserve for a manufactured gas plant site at HWP ($5 million).  

Income Tax (Benefit)/Expense

Included in the notes to the consolidated financial statements is 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 $214 million to a benefit of $163 million in 2005 from an expense of $51 million in 2004 primarily due to a loss before income tax expense and greater favorable flow through adjustments, offset by increases to the deferred state income tax valuation allowance.  The increase in the state income tax valuation allowance was required due to the magnitude of the tax losses limiting the ability to utilize the state tax benefits within the applicable state tax carryforward period.

(Loss)/Income from Discontinued Operations

Beginning with the

quarter ended September 30, 2005, the operations of SESI, SECI-NH, Woods Network and Woods Electrical were presented as discounted operations as a result of meeting certain criteria requiring this presentation.  Under this presentation, revenues and expenses of these businesses are included in the (loss)/income from discontinued operations on the consolidated statements of income.  See Note 4, "Assets Held for Sale and Discontinued Operations," to the consolidated financial statements for a description and explanation of the discontinued operations.

Cumulative Effects of Accounting Changes, Net of Tax Benefits

A cumulative effect of accounting change, net of tax benefit ($1 million) was recorded in the fourth quarter of 2005 in connection with the adoption of FIN 47, which required NU to recognize a liability for the fair value of an ARO.  

2004 Compared to 2003

Operating Revenues

Operating revenues increased $599 million in 2004 due to higher revenues from NU Enterprises ($369 million), higher electric distribution revenues ($172 million), higher gas distribution revenues ($46 million) and higher regulated transmission revenues ($13 million).

The NU Enterprises’ revenue increase of $369 million is primarily due to higher revenues for the retail marketing business ($197 million), the 2003 revenue reduction recorded for the settlement of a wholesale power dispute associated with CL&P standard offer supply ($56 million), and an increased level of competitive energy services business ($24 million).  Higher revenues for the retail marketing business resulted from higher electric volumes ($119 million), higher gas prices ($48 million), higher electric prices ($28 million), and higher gas volumes ($2 million).  The competitive energy services business revenue increase resulted from higher revenues from a cogeneration project and higher volumes in the mechanical contracting group.

The electric distribution revenue increase of $172 million is primarily due to non-earnings components of CL&P, PSNH and WMECO retail rates ($141 million).  The distribution component of these companies and the retail transmission component of CL&P and PSNH that flow through to earnings increased $33 million, primarily due to the CL&P retail transmission rate increase effective in January of 2004.  The non-earnings components increase of $141 million is primarily due to the pass through of energy supply costs ($269 million) and CL&P FMCC ($151 million), partially offset by the resolution of SMD cost recovery which was being collected from CL&P customers in 2003 and early 2004 and subsequently refunded beginning in late 2004 ($71 million), lower CL&P EAC revenue as a result of the end of EAC billings in 2003 ($44 million), lower transition cost recoveries for CL&P and WMECO ($44 million) and lower CL&P system bene fit cost recoveries ($31 million).  Regulated retail sales increased 0.9 percent in 2004 compared with 2003.  On a weather adjusted basis, retail sales increased 1.9 percent as a result of improved economic conditions and increasing use per customer.  In addition, electric wholesale revenues decreased $72 million, primarily due to lower Utility Group sales related to IPP contracts and the expiration of long-term contracts.  

The higher gas distribution revenue of $46 million is primarily due to the recovery of increased gas costs ($17 million) and the absence of the 2003 unbilled revenue adjustment ($28 million).  

Transmission revenues were higher primarily due to the October 2003 implementation of the transmission rate case approved at the FERC.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expense increased $496 million in 2004, primarily due to higher wholesale costs at NU Enterprises ($224 million) and higher purchased power costs for the Utility Group ($272 million).  The increase for the Utility Group is primarily due to an increase in the standard offer supply costs for CL&P ($152 million) and WMECO ($16 million), higher Yankee Gas expenses ($33 million) primarily due to increased gas prices, higher expenses for PSNH ($10 million) primarily due to higher energy and capacity purchases, partially offset by the 2003 CL&P recovery of certain fuel costs ($44 million).   

Other Operation

Other operation expenses increased $104 million in 2004, primarily due to higher expenses for NU Enterprises resulting from the increased volume in the contracting business ($44 million), higher CL&P RMR costs and other power pool related expenses ($71 million), higher PSNH fossil production expense ($6 million), and higher distribution expenses ($4 million), partially offset by lower Conservation and Load Management (C&LM) expense ($20 million).  

Maintenance

Maintenance expense increased $13 million in 2004, primarily due to higher expenses for NU Enterprises at its generating plants ($5 million), the absence of the 2003 positive resolution of the Millstone use of proceeds docket ($5 million) and higher electric distribution expenses ($5 million).

Depreciation

Depreciation increased $21 million in 2004 due to higher Utility Group plant balances and higher depreciation rates at CL&P resulting from the distribution rate case decision effective in January of 2004.

Amortization

Amortization decreased $54 million in 2004 primarily due to lower Utility Group recovery of stranded costs and a decrease in amortization expense resulting from the amortization of GSC over-recoveries allowed in the CL&P distribution rate case effective in January of 2004 ($29 million).

Amortization of Rate Reduction Bonds

Amortization of rate reduction bonds increased $12 million in 2004 due to the repayment of a higher principal amount as compared to 2003.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $11 million in 2004 primarily due to higher payroll taxes ($4 million), higher sales tax ($3 million) and higher local property taxes ($2 million).

Interest Expense, Net

Interest expense, net increased $7 million in 2004 primarily due to the issuance of $75 million of ten-year notes at Yankee Gas in January of 2004, the issuance of $50 million of thirty-year senior notes at WMECO in September of 2004, and the issuance of $150 million of five-year notes at NU Parent in June of 2003.

Other Income, Net

Other income, net increased $10 million in 2004 primarily due to the recognition, beginning in 2004, of a CL&P procurement fee approved in the TSO docket decision ($12 million).

Income Tax (Benefit)/Expense

Income tax expense increased by $3 million in 2004 due to higher reversal of prior flow-through depreciation and lower favorable adjustments to tax expense, partially offset by lower state income tax expense, due to increased state tax credits and favorable unitary apportionment.

(Loss)/Income from Discontinued Operations

Beginning with the quarter ended September 30, 2005, the operations of SESI, SECI-NH, Woods Network and Woods Electrical were presented as discontinued operations as a result of meeting certain criteria requiring this presentation.  Under this presentation, revenues and expenses of these businesses are included in the (loss)/income from discontinued operations on the consolidated statements of income.  See Note 4, "Assets Held for Sale and Discontinued Operations," to the consolidated financial statements for a description and explanation of the discontinued operations.

Cumulative Effects of Accounting Changes, Net of Tax Benefits

A cumulative effect of accounting change, net of tax benefit ($5 million) was recorded in the third quarter of 2003 in connection with the adoption of FIN 46, which required NU to consolidate RMS into NU’s financial statements and adjust its equity interest as a cumulative effect of an accounting change.

Company Report on Internal Controls Over Financial Reporting    

Management is responsible for the preparation, integrity, and fair presentation of the accompanying consolidated financial statements of Northeast Utilities and subsidiaries (NU) and of other sections of this annual report.  These financial statements, which were audited by Deloitte & Touche LLP, have been prepared in conformity with accounting principles generally accepted in the United States of America using estimates and judgments, where required, and giving consideration to materiality.

Additionally, management is responsible for establishing and maintaining adequate internal controls over financial reporting.  Under the supervision and with the participation of management, including our principal executive officer and principal financial officer, NU conducted an evaluation of the effectiveness of internal controls over financial reporting based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  Based on this evaluation under the framework in COSO, management concluded that our internal controls over financial reporting were effective as of December 31, 2005.

Deloitte & Touche LLP has issued an attestation report on management’s assessment of internal controls over financial reporting.

March 7, 2006

Reports of Independent Registered Public Accounting Firm

To the Board of Trustees and Shareholders of Northeast Utilities:

We have audited management's assessment, included in the accompanying Company’s Report on Internal Controls Over Financial Reporting, that Northeast Utilities and subsidiaries (the "Company") maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.  The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting.  Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.  Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances.  We believe that our audit provides a reasonable basis for our opinions.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of trustees, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis.  Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management's assessment that the Company maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.  Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedules as of and for the year ended December 31, 2005, of the Company and our report dated March 7, 2006 expressed an unqualified opinion on those financial statements and includes an explanatory paragraph regarding the Company’s recording of significant charges in connection with its decision to exit certain business lines and the reporting of certain components of the Company’s energy services businesses as discontinued operations.

/s/	DELOITTE & TOUCHE LLP
	DELOITTE & TOUCHE LLP

Hartford, Connecticut

March 7, 2006

Report of Independent Registered Public Accounting Firm

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, 2005 and 2004, and the related consolidated statements of (loss)/income, comprehensive (loss)/income, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2005.  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 the standards of the Public Company Accounting Oversight Board (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, such consolidated financial statements present fairly, in all material respects, the financial position of Northeast Utilities and subsidiaries as of December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Notes 2 and 3, the Company recorded significant charges in the year ended December 31, 2005 in connection with its decision to exit certain business lines and, as discussed in Note 4, certain components of the Company’s energy services businesses are reported as discontinued operations.  

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company's internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 7, 2006 expressed an unqualified opinion on management's assessment of the effectiveness of the Company's internal control over financial reporting and an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.

/s/	DELOITTE & TOUCHE LLP
	DELOITTE & TOUCHE LLP

Hartford, Connecticut

March 7, 2006

NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF (LOSS)/INCOME
For the Years Ended December 31,	2005	2004	2003
	(Thousands of Dollars, except share information)
Operating Revenues	$        7,397,390	$           6,542,120	$         5,943,514
Operating Expenses:
Operation -
Fuel, purchased and net interchange power	4,933,080	4,231,192	3,735,154
Other	1,061,159	951,877	848,163
Wholesale contract market changes, net	440,946	-	-
Restructuring and impairment charges	44,143	-	-
Maintenance	200,263	188,092	174,594
Depreciation	234,652	224,132	203,469
Amortization	202,949	138,271	191,805
Amortization of rate reduction bonds	176,356	164,915	153,172
Taxes other than income taxes	257,707	241,424	231,062
Total operating expenses	7,551,255	6,139,903	5,537,419
Operating (Loss)/Income	(153,865)	402,217	406,095
Interest Expense:
Interest on long-term debt	163,012	139,988	121,887
Interest on rate reduction bonds	87,439	98,899	108,359
Other interest	19,350	8,610	10,333
Interest expense, net	269,801	247,497	240,579
Other Income, Net	37,237	14,562	4,105
(Loss)/Income from Continuing Operations Before
Income Tax (Benefit)/Expense	(386,429)	169,282	169,621
Income Tax (Benefit)/Expense	(162,765)	50,728	47,628
(Loss)/Income from Continuing Operations Before
Preferred Dividends of Subsidiary	(223,664)	118,554	121,993
Preferred Dividends of Subsidiary	5,559	5,559	5,559
(Loss)/Income from Continuing Operations	(229,223)	112,995	116,434
Discontinued Operations (Note 4):
(Loss)/Income from Discontinued Operations Before Income Taxes	(38,057)	4,621	7,822
Loss from Sale of Discontinued Operations	(1,123)	-	-
Income Tax (Benefit)/Expense	(15,920)	1,028	3,104
(Loss)/Income from Discontinued Operations	(23,260)	3,593	4,718
(Loss)/Income Before Cumulative Effects of Accounting Changes,   Net of Tax Benefits	(252,483)	116,588	121,152
Cumulative effects of accounting changes,
net of tax benefits of $689 in 2005 and $2,553 in 2003	(1,005)	-	(4,741)
Net (Loss)/Income	$         (253,488)	$              116,588	$            116,411
Basic and Fully Diluted (Loss)/Earnings Per Common Share:
(Loss)/Income from Continuing Operations	$               (1.74)	$                    0.88	$                  0.91
(Loss)/Income from Discontinued Operations	(0.18)	0.03	0.04
Cumulative Effects of Accounting Changes,
Net of Tax Benefits	(0.01)	-	(0.04)
Basic and Fully Diluted (Loss)/Earnings Per Common Share	$              (1.93)	$                    0.91	$                  0.91
Basic Common Shares Outstanding (weighted average)	131,638,953	128,245,860	127,114,743
Fully Diluted Common Shares Outstanding (weighted average)	131,638,953	128,396,076	127,240,724
The accompanying notes are an integral part of these consolidated financial statements.

NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS)/INCOME
For the Years Ended December 31,	2005	2004	2003
	(Thousands of Dollars)
Net (Loss)/Income	$            (253,488)	$            116,588	$              116,411
Other comprehensive income/(loss), net of tax:
Qualified cash flow hedging instruments	21,688	(28,246)	9,274
Unrealized (losses)/gains on securities	(899)	1,191	2,093
Minimum supplemental executive retirement
pension liability adjustments	418	(156)	(303)
Other comprehensive income/(loss), net of tax	21,207	(27,211)	11,064
Comprehensive (Loss)/Income	$           (232,281)	$              89,377	$             127,475
The accompanying notes are an integral part of these consolidated financial statements.

NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
At December 31,	2005	2004
	(Thousands of Dollars)
ASSETS
Current Assets:
Cash and cash equivalents	$                 45,782	$                 46,989
Special deposits	103,789	82,584
Investments in securitizable assets	252,801	139,391
Receivables, less provision for uncollectible accounts
of $24,444 in 2005 and $25,325 in 2004	901,516	771,257
Unbilled revenues	175,853	144,438
Taxes receivable	-	61,420
Fuel, materials and supplies	206,557	185,180
Marketable securities	56,012	52,498
Derivative assets - current	403,507	81,567
Prepayments and other	129,242	154,395
Assets held for sale	101,784	-
	2,376,843	1,719,719
Property, Plant and Equipment:
Electric utility	6,378,838	5,918,539
Gas utility	825,872	786,545
Competitive energy	908,776	918,183
Other	254,659	241,190
	8,368,145	7,864,457
Less: Accumulated depreciation	2,551,322	2,382,927
	5,816,823	5,481,530
Construction work in progress	600,407	382,631
	6,417,230	5,864,161
Deferred Debits and Other Assets:
Regulatory assets	2,483,851	2,746,219
Goodwill	287,591	319,986
Prepaid pension	298,545	352,750
Marketable securities	56,527	51,924
Derivative assets - long-term	425,049	198,769
Other	223,439	384,868
	3,775,002	4,054,516
Total Assets	$          12,569,075	$          11,638,396
The accompanying notes are an integral part of these consolidated financial statements.

NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
At December 31,	2005	2004
	(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION
Current Liabilities:
Notes payable to banks	$                 32,000	$                 180,000
Long-term debt - current portion	22,673	90,759
Accounts payable	972,368	825,247
Accrued taxes	95,210	-
Accrued interest	47,742	49,449
Derivative liabilities - current	402,530	130,275
Counterparty deposits	28,944	57,650
Other	272,252	212,239
Liabilities of assets held for sale	101,511	-
	1,975,230	1,545,619
Rate Reduction Bonds	1,350,502	1,546,490
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	1,306,340	1,434,403
Accumulated deferred investment tax credits	95,444	99,124
Deferred contractual obligations	358,174	413,056
Regulatory liabilities	1,273,501	1,070,187
Derivative liabilities - long-term	272,995	58,737
Other	364,157	267,895
	3,670,611	3,343,402
Capitalization:
Long-Term Debt	3,027,288	2,789,974
Preferred Stock of Subsidiary - Non-Redeemable	116,200	116,200
Common Shareholders' Equity:
Common shares, $5 par value - authorized 225,000,000
shares; 174,897,704 shares issued and 153,225,892
shares outstanding in 2005 and 151,230,981 shares
issued and 129,034,442 shares outstanding in 2004	874,489	756,155
Capital surplus, paid in	1,437,561	1,116,106
Deferred contribution plan - employee stock
ownership plan	(46,884)	(60,547)
Retained earnings	504,301	845,343
Accumulated other comprehensive income/(loss)	19,987	(1,220)
Treasury stock, 19,645,511 shares in 2005
and 19,580,065 shares in 2004	(360,210)	(359,126)
Common Shareholders' Equity	2,429,244	2,296,711
Total Capitalization	5,572,732	5,202,885
Commitments and Contingencies (Note 9)
Total Liabilities and Capitalization	$          12,569,075	$            11,638,396
The accompanying notes are an integral part of these consolidated financial statements.

NORTHEAST UTILITIES AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
	Common Shares		Capital Surplus,	Deferred Contribution Plan -	Retained	Accumulated Other Comprehensive Income/	Treasury
	Shares	Amount	Paid In	ESOP	Earnings	(Loss)	Stock	Total
	(Thousands of Dollars, except share information)
Balance as of  January 1, 2003	127,562,031	$  746,879	$1,108,338	$     (87,746)	$     765,611	$    14,927	$(337,488)	$  2,210,521
Net income for 2003					116,411			116,411
Cash dividends on common
shares - $0.575 per share					(73,090)			(73,090)
Issuance of common shares, $5 par value	1,022,556	5,113	8,541					13,654
Allocation of benefits - ESOP	607,020		(4,030)	14,052				10,022
Restricted shares, net	(7,508)		(4,110)				(99)	(4,209)
Repurchase of common shares	(1,638,100)						(23,210)	(23,210)
Issuance of treasury shares	150,000						2,772	2,772
Capital stock expenses, net			185					185
Other comprehensive income						11,064		11,064
Balance as of
December 31, 2003	127,695,999	751,992	1,108,924	(73,694)	808,932	25,991	(358,025)	2,264,120
Net income for 2004					116,588			116,588
Cash dividends on common
shares - $0.625 per share					(80,177)			(80,177)
Issuance of common shares, $5 par value	832,578	4,163	6,774					10,937
Allocation of benefits - ESOP	567,907		(2,384)	13,147				10,763
Restricted shares, net	(62,042)		1,250				(1,101)	149
Tax deduction for stock options exercised and Employee
Stock Purchase Plan disqualifying dispositions			1,356					1,356
Capital stock expenses, net			186					186
Other comprehensive loss						(27,211)		(27,211)
Balance as of
December 31, 2004	129,034,442	756,155	1,116,106	(60,547)	845,343	(1,220)	(359,126)	2,296,711
Net loss for 2005					(253,488)			(253,488)
Cash dividends on common
shares - $0.675 per share					(87,554)			(87,554)
Issuance of common shares, $5 par value	23,666,723	118,334	332,493					450,827
Allocation of benefits – ESOP	590,173		(2,161)	13,663				11,502
Restricted shares, net	(65,446)		5,295				(1,084)	4,211
Tax deduction for stock options exercised and Employee
Stock Purchase Plan disqualifying dispositions			368					368
Capital stock expenses, net			(14,540)					(14,540)
Other comprehensive income						21,207		21,207
Balance as of
December 31, 2005	153,225,892	$  874,489	$1,437,561	$     (46,884)	$     504,301	$   19,987	$(360,210)	$  2,429,244
The accompanying notes are an integral part of these consolidated financial statements.

NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31,	2005	2004	2003
Operating Activities:	(Thousands of Dollars)
Net (loss)/income	$            (253,488)	$              116,588	$               116,411
Adjustments to reconcile to net cash flows
provided by operating activities:
Wholesale contract market changes, net	440,946	-	-
Restructuring and impairment charges	67,181	-	-
Bad debt expense	27,528	19,062	23,229
Depreciation	235,221	224,855	204,388
Deferred income taxes	(202,789)	111,710	(129,733)
Amortization	202,949	138,271	191,805
Amortization of rate reduction bonds	176,356	164,915	153,172
Amortization/(deferral) of recoverable energy costs	39,914	(22,751)	20,486
Pension expense/(income)	42,662	10,636	(16,416)
Wholesale contract buyout payments	(186,531)	-	-
Regulatory (refunds)/overrecoveries	(65,236)	(150,119)	287,974
Derivative assets and liabilities - changes in fair value	2,405	85,592	(12,175)
Deferred contractual obligations	(89,464)	(56,161)	(52,961)
Other non-cash adjustments	48,477	(30,053)	(60,719)
Other sources of cash	5,528	26,596	5,950
Other uses of cash	-	(10,189)	(51,386)
Changes in current assets and liabilities:
Receivables and unbilled revenues, net	(208,519)	(103,983)	39,322
Fuel, materials and supplies	(17,848)	(31,104)	(34,223)
Investments in securitizable assets	(113,410)	27,074	12,443
Other current assets	(11,061)	(38,648)	121,249
Accounts payable	131,043	124,437	(36,380)
Counterparty deposits	(28,706)	11,154	46,496
Accrued taxes	156,630	(112,300)	(83,625)
Other current liabilities	41,416	(44,935)	(56,357)
Net cash flows provided by operating activities	441,204	460,647	688,950
Investing Activities:
Investments in property and plant:
Electric, gas and other utility plant	(752,124)	(653,948)	(539,424)
Competitive energy assets	(23,231)	(17,527)	(18,686)
Cash flows used for investments in property and plant	(775,355)	(671,475)	(558,110)
Net proceeds from sale of property	31,456	-	-
Proceeds from sales of investment securities	137,099	106,217	34,147
Purchases of investment securities	(142,260)	(171,511)	(49,729)
Restricted cash - LMP costs	-	93,630	(93,630)
CVEC acquisition special deposit	-	-	(30,104)
Other investing activities	49,515	7,721	3,864
Net cash flows used in investing activities	(699,545)	(635,418)	(693,562)
Financing Activities:
Issuance of common shares	450,827	10,937	13,654
Repurchase of common shares	-	-	(20,537)
Issuance of long-term debt	350,355	512,762	268,368
Retirement of rate reduction bonds	(195,988)	(183,470)	(169,352)
(Decrease)/increase in short-term debt	(148,000)	75,000	49,000
Reacquisitions and retirements of long-term debt	(98,056)	(155,532)	(65,600)
Cash dividends on common shares	(87,554)	(80,177)	(73,090)
Other financing activities	(14,450)	(1,132)	(4,792)
Net cash flows provided by/(used in) financing activities	257,134	178,388	(2,349)
Net (decrease)/increase in cash and cash equivalents	(1,207)	3,617	(6,961)
Cash and cash equivalents - beginning of year	46,989	43,372	50,333
Cash and cash equivalents - end of year	$               45,782	$               46,989	$                43,372
The accompanying notes are an integral part of these consolidated financial statements.

NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CAPITALIZATION
		At December 31,
(Thousands of Dollars)		2005	2004
Common Shareholders’ Equity		$2,429,244	$2,296,711
Preferred Stock:
CL&P Preferred Stock Not Subject to Mandatory Redemption -     $50 par value – authorized 9,000,000 shares in 2005 and 2004;     2,324,000 shares outstanding in 2005 and 2004;     Dividend rates of $1.90 to $3.28;       Current redemption prices of $50.50 to $54.00		116,200	116,200
Long-Term Debt:   First Mortgage Bonds:
Final Maturity	Interest Rates
2005	5.00% to 6.75%	-	57,500
2009-2012	6.20% to 7.19%	80,000	80,000
2014-2015	4.80% to 5.25%	375,000	275,000
2019-2024	5.26% to 8.48%	209,845	209,845
2026-2035	5.35% to 8.81%	650,000	450,000
Total First Mortgage Bonds		1,314,845	1,072,345
Other Long-Term Debt:    Pollution Control Notes:
2016-2018	5.90%	25,400	25,400
2021-2022	Variable Rate and 5.45% to 6.00%	428,285	428,285
2028	5.85% to 5.95%	369,300	369,300
2031	3.35% until 2008	62,000	62,000
Other:
2005-2008	3.30% to 8.81%	173,263	200,795
2012-2015	5.00% to 9.24%	368,000	328,694
2018-2026	6.00% to 7.69%	-	88,262
2034	5.90%	50,000	50,000
Total Pollution Control Notes and Other		1,476,248	1,552,736
Total First Mortgage Bonds, Pollution Control Notes and Other		2,791,093	2,625,081
Fees and interest due for spent nuclear fuel disposal costs		268,008	259,707
Change in Fair Value		(5,211)	91
Unamortized premium and discount, net		(3,929)	(4,146)
Total Long-Term Debt		3,049,961	2,880,733
Less:  Amounts due within one year		22,673	90,759
Long-Term Debt, Net		3,027,288	2,789,974
Total Capitalization		$5,572,732	$5,202,885

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

Consolidated:  Northeast Utilities (NU or the company) is the parent company of the companies comprising the Utility Group and NU Enterprises.  Until February 8, 2006, NU was registered with the Securities and Exchange Commission (SEC) as a holding company under the Public Utility Holding Company Act of 1935 (PUHCA).  On February 8, 2006, PUHCA was repealed.  Arrangements among the Utility Group, NU Enterprises and other NU companies, outside agencies and other utilities covering interconnections, interchange of electric power and sales of utility property are subject to regulation by the Federal Energy Regulatory Commission (FERC) and/or the SEC.  The Utility Group is subject to further regulation for rates, accounting and other matters by the FERC and/or applicable state regulatory commissions.

Several wholly owned subsidiaries of NU provide support services for NU’s companies.  Northeast Utilities Service Company (NUSCO) provides centralized accounting, administrative, engineering, financial, information technology, legal, operational, planning, purchasing, and other services to NU’s companies.  Three other subsidiaries construct, acquire or lease some of the property and facilities used by NU’s companies.

Utility Group:  The Utility Group furnishes franchised retail electric service in Connecticut, New Hampshire and Massachusetts through three companies: The Connecticut Light and Power Company (CL&P), Public Service Company of New Hampshire (PSNH) and Western Massachusetts Electric Company (WMECO).  Another Utility Group company is Yankee Gas Services Company (Yankee Gas), which owns and operates Connecticut’s largest natural gas distribution system.  The Utility Group includes three reportable business segments: the regulated electric utility distribution segment, the regulated gas utility distribution segment and the regulated electric utility transmission segment.

Effective January 1, 2004, PSNH completed the purchase of the electric system and retail franchise of Connecticut Valley Electric Company (CVEC), a subsidiary of Central Vermont Public Service Corporation (CVPS), for $30.1 million.  CVEC’s 11,000 customers in western New Hampshire have been added to PSNH’s customer base.  The purchase price included the book value of CVEC’s plant assets of approximately $9 million and an additional $21 million to terminate an above-market wholesale power purchase agreement CVEC had with CVPS.  The $21 million payment is being recovered from PSNH’s customers.  

NU Enterprises:  NU Enterprises, Inc. is the parent company of Select Energy, Inc. (Select Energy), Select Energy Services, Inc. (SESI) and their respective subsidiaries, Northeast Generation Company (NGC), Northeast Generation Services Company (NGS) and its subsidiaries E. S. Boulos Company (Boulos) and Woods Electrical Co., Inc. (Woods Electrical), Select Energy Contracting, Inc. (SECI), Reeds Ferry Supply Co., Inc. (Reeds Ferry) and Woods Network Services, Inc. (Woods Network), all of which are collectively referred to as NU Enterprises.  The generation operations of Holyoke Water Power Company (HWP), a direct subsidiary of NU, are also included in the results of NU Enterprises.  The companies included in the NU Enterprises segment are grouped into two business segments: the merchant energy business segment and the energy services business segment.  The merchant energy business segment is currently comprised of Select Energy ’s wholesale marketing business, which includes 1,296 megawatts (MW) of pumped storage and hydroelectric generation assets owned by NGC, 146 MW of coal-fired generation assets owned by HWP, Select Energy’s retail marketing business and NGS.  On March 9, 2005, NU announced its decision to exit the wholesale marketing portion of the merchant energy business segment as well as the energy services businesses.  On November 7, 2005, NU announced it would exit the remainder of the merchant energy business segment, which includes the retail marketing business and the competitive generation business.  For information regarding the decisions to exit these businesses, see Note 2, "Wholesale Contract Market Changes," and Note 3, "Restructuring and Impairment Charges," to the consolidated financial statements.

The energy services business segment includes the operations of SESI, Boulos, Woods Electrical, SECI, Reeds Ferry, and Woods Network.  SESI performs energy management services for large commercial customers, institutional facilities and the United States government and energy-related construction services.  Boulos and Woods Electrical provide third-party electrical services.  SECI provides mechanical and electrical contracting services for new construction and service contracts.  Reeds Ferry purchases equipment on behalf of SECI.  Woods Network is a network design, products and services company.  

On November 8, 2005, certain assets of SECI-New Hampshire (SECI-NH), a division of SECI, and 100 percent of the common stock of Reeds Ferry were sold to an unrelated third party.  On November 22, 2005, 100 percent of the common stock of Woods Network was sold to an unrelated third party.  The proceeds from these two sales totaled $6.5 million.  In January of 2006, the Massachusetts service location of Select Energy Contracting - Connecticut (SECI-CT) was sold for approximately $2 million.  See Note 4, "Assets Held for Sale and Discontinued Operations," to the consolidated financial statements for further information regarding the status of the sale of the energy services businesses.  For information regarding NU’s business segments, see Note 17, "Segment Information," to the consolidated financial statements.

B.

Presentation

The consolidated financial statements of NU and of its subsidiaries, as applicable, include the accounts of all their respective subsidiaries. Intercompany transactions have been eliminated in consolidation.

The preparation of consolidated 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 consolidated 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 period data included in the accompanying consolidated financial statements have been made to conform with the current years' presentation.  

In the company's consolidated balance sheet at December 31, 2004, the company changed the classification of certain deposit amounts totaling $17.8 million related to its rate reduction bonds.  The company previously presented these amounts on a gross basis in deferred debits and other assets - other with an equal and offsetting amount in other current liabilities.  For the current year presentation, these amounts are presented on a net basis in the company's accompanying consolidated balance sheet.

In the company’s consolidated statements of (loss)/income for the years ended December 31, 2004 and 2003, the company changed the classification of certain costs that were not recoverable from regulated customers totaling $5.7 million and $10.5 million, respectively.  The company previously presented these amounts in other income, net.  For the current year presentation, these amounts are presented in other operation expenses in the consolidated statements of (loss)/income for the years ended December 31, 2004 and 2003.

In the company's consolidated statements of cash flows for the years ended December 31, 2004 and 2003, the company changed the classification of the change in restricted cash – locational marginal pricing (LMP) costs balances to present that change as an investing activity.  The company previously presented that change as an operating activity which resulted in a $93.6 million decrease in net cash flows used in investing activities and a corresponding decrease in operating cash flows from the amounts previously reported for the year ended December 31, 2004 and a $93.6 million increase in net cash flows used in investing activities and a corresponding increase in operating cash flows from amounts previously reported for the year ended December 31, 2003.  

The consolidated statements of cash flows for the years ended December 31, 2004 and 2003 have also been reclassified to exclude from cash flows from operations the change in accounts payable related to capital projects as well as excluding these amounts from investments in property and plant in investing activities.  These amounts totaled uses of cash of $27.7 million and $5.5 million for the years ended December 31, 2004 and 2003, respectively.  

NU's consolidated statements of (loss)/income for the years ended December 31, 2005, 2004 and 2003 present the operations for the following companies as discontinued operations as a result of meeting certain criteria requiring this presentation:

·

SESI and its wholly owned subsidiaries HEC/Tobyhanna Energy Project, Inc. (HEC/Tobyhanna) and HEC/CJTS Energy Center LLC (HEC/CJTS);

·

SECI-NH (including Reeds Ferry), a division of SECI;

·

Woods Network; and

·

Woods Electrical.  

At December 31, 2005, the assets and liabilities of SESI and Woods Electrical have been reclassified to assets held for sale and liabilities of assets held for sale on the accompanying consolidated balance sheet.  SECI-NH and Woods Network were sold in November of 2005.  For further information regarding these companies, see Note 4, "Assets held for Sale and Discontinued Operations" to the consolidated financial statements.  

In the company's consolidated statements of (loss)/income for the year ended December 31, 2004, the company has reclassified a $5.8 million loss associated with a construction contract from income/(loss) from discontinued operations to (loss)/income from continuing operations.  The company had previously included this loss in (loss)/income from discontinued operations in its Form 8-K dated November 22, 2005.

C.

Accounting Standards Issued But Not Yet Adopted

Share-Based Payments:  On December 16, 2004, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 123 (Revised 2004), "Share-Based Payments," (SFAS No. 123R), which amended SFAS No. 123, "Accounting for Stock-Based Compensation."  Under the provisions of SFAS No. 123R, NU will recognize compensation expense for the unvested portion of previously granted awards outstanding beginning on January 1, 2006, the effective date of SFAS No. 123R, and any new awards after that date.  The adoption of SFAS No. 123R is not expected to have a material impact on NU’s consolidated financial statements.  For information regarding current accounting for equity-based compensation, see Note 1N, "Summary of Significant Accounting Policies - Equity-Based Compensation," to the consolidated financial statements.

Accounting Changes and Error Corrections: In May of 2005, the FASB issued SFAS No. 154, "Accounting Changes and Error Corrections."  SFAS No. 154 is effective beginning on January 1, 2006 for NU and requires retrospective application to prior periods’ financial statements of voluntary changes in accounting principles.  It also applies to accounting changes required by a new accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions.  SFAS No. 154 does not change previous guidance for reporting the correction of an error in previously issued financial statements or a change in accounting estimate.  Implementation of SFAS No. 154 on January 1, 2006 is not expected to affect NU’s consolidated financial statements until such time that its provisions are required to be applied as described above.  

D.

Guarantees

NU provides credit assurances on behalf of subsidiaries in the form of guarantees and letters of credit (LOCs) in the normal course of business.  NU would be required to perform under these guarantees in the event of non-performance by NU Enterprises, primarily Select Energy.  At December 31, 2005, the maximum level of exposure in accordance with FASB Interpretation No. (FIN) 45, "Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others," under guarantees by NU, primarily on behalf of NU Enterprises, totaled $989.7 million.  A majority of these guarantees do not have established expiration dates, and some guarantees have unlimited exposure to commodity

price movements.  Additionally, NU had $253 million of LOCs issued, the majority of which were issued for the benefit of NU Enterprises at December 31, 2005.  NU has no guarantees of the performance of third parties.  

At December 31, 2005, NU had outstanding guarantees on behalf of the Utility Group and Rocky River Realty (RRR) of $11 million and $10.7 million, respectively.  These amounts are included in the total outstanding NU guarantee exposure amount of $989.7 million.  The guarantee amount of $968 million for NU Enterprises includes $670 million for Select Energy and $298 million for the energy services businesses.  The $298 million in guarantees related to the energy services businesses is comprised of $97 million and $14.1 million for SESI's and NGC's obligations, respectively, under certain financing arrangements and $186.9 million for performance obligations of the energy services businesses.

Several underlying contracts that NU guarantees, as well as certain surety bonds, contain credit ratings triggers that would require NU to post collateral in the event that NU’s credit ratings are downgraded below investment grade.

Until the repeal of PUHCA on February 8, 2006, NU was authorized by the SEC to provide up to $750 million of guarantees for its non-utility subsidiaries through June 30, 2007.  The $11 million in outstanding guarantees on behalf of the Utility Group was subject to a separate PUHCA limitation of $50 million.  The amount of guarantees outstanding for compliance with this limit for NU Enterprises at December 31, 2005 is $567.5 million.  The amount of guarantees outstanding for compliance with the limit for the Utility Group at December 31, 2005 is $0.2 million.  These amounts are calculated using different, more probabilistic and fair-value based criteria than the maximum level of exposure required to be disclosed under FIN 45.  FIN 45 includes all exposures even though they are not reasonably likely to result in exposure to NU.

NU was also authorized by the SEC under PUHCA to issue guarantees of up to an aggregate $100 million through June 30, 2007 of the debt or other obligations of two of its other subsidiaries, NUSCO and RRR.  These companies provide certain specialized support and real estate services and occasionally enter into transactions that require financial backing from NU.  The amount of guarantees outstanding for compliance with the limit under this category at December 31, 2005 is $0.2 million.

With the repeal of PUHCA, there are no regulatory limits on NU's ability to guarantee the obligation of its subsidiaries.  

E.

Revenues

Utility Group:  Utility Group retail revenues are based on rates approved by the state regulatory commissions.  These regulated rates are applied to customers’ use of energy to calculate a bill.  In general, rates can only be changed through formal proceedings with the state regulatory commissions.  However, certain Utility Group companies utilize regulatory commission-approved tracking mechanisms to track the recovery of certain incurred costs.  The tracking mechanisms allow for rates to be changed periodically, with overcollections refunded to customers or undercollections collected from customers in future periods.

Utility Group Unbilled Revenues:  Unbilled revenues represent an estimate of electricity or gas delivered to customers that has not yet been billed.  Unbilled revenues are included in revenue on the statement of (loss)/income and are assets on the balance sheet that are reclassified to accounts receivable in the following month as customers are billed.  Such estimates are subject to adjustment when actual meter readings become available, when changes in estimating methodology occur and under other circumstances.

Through December 31, 2004, the Utility Group estimated unbilled revenues monthly using the requirements method.  The requirements method utilized the total monthly volume of electricity or gas delivered to the system and applied a delivery efficiency (DE) factor to reduce the total monthly volume by an estimate of delivery losses in order to calculate total estimated monthly sales to customers.  The total estimated monthly sales amount less the total monthly billed sales amount resulted in a monthly estimate of unbilled sales.  Unbilled revenues were estimated by first allocating sales to the respective rate classes, then applying an average rate to the estimate of unbilled sales.  The estimated DE factor had a significant impact on estimated unbilled revenue amounts.

In the first quarter of 2005, management adopted a new method to estimate unbilled revenues for CL&P, PSNH, WMECO, and Yankee Gas.  The new method allocates billed sales to the current calendar month based on the daily load for each billing cycle (DLC method).  The billed sales are subtracted from total calendar month sales to estimate unbilled sales.  The impact of adopting the new method was not material.  This new method replaces the requirements method described above.    

Utility Group Transmission Revenues - Wholesale Rates:  Wholesale transmission revenues are based on rates and formulas that are approved by the FERC.  Most of NU’s wholesale transmission revenues are collected through a combination of the New England Regional Network Service (RNS) tariff and NU’s Local Network Service (LNS) tariff.  The RNS tariff, which is administered by the New England Independent System Operator (ISO-NE), recovers the revenue requirements associated with transmission facilities that are deemed by the FERC to be regional facilities.  This regional rate is reset on June 1 of each year.  The LNS tariff provides for the recovery of NU’s total transmission revenue requirements, net of revenues received from other sources, including those revenues received under RNS rates.  NU’s LNS tariff is reset on January 1 and June 1 of each year.  Additionally, NU’s LNS tariff provid es for a true-up to actual costs, which ensures that NU recovers its total transmission revenue requirements, including an allowed return on equity (ROE).  At December 31, 2005, this true-up has resulted in the recognition of a $2.1 million regulatory liability, including approximately $1.5 million due to NU’s electric distribution companies.  

Utility Group Transmission Revenues - Retail Rates:  A significant portion of the NU transmission business revenue comes from ISO-NE charges to the distribution businesses of CL&P, PSNH and WMECO.  The distribution businesses recover these costs through the retail rates that are charged to their retail customers.  For CL&P, any difference between the revenues received from retail customers and the retail transmission expenses charged to the distribution business has historically impacted the distribution business earnings.  In July of 2005, CL&P began a process of tracking its retail transmission revenues and expenses and adjusting its retail transmission rates on a regular basis, thereby recovering all of its retail transmission expenses on a timely basis.  This ratemaking change resulted from the enactment of the legislation passed by the Connecticut legislature in 2005.

WMECO implemented its retail transmission tracker and rate adjustment mechanism in January of 2002 as part of its 2002 rate change filing.  PSNH does not currently have a retail transmission rate tracking mechanism.   

NU Enterprises:  NU Enterprises' revenues are recognized at different times for its different business lines.  Wholesale marketing revenues were recognized when energy was delivered up to and including the first quarter of 2005.  Subsequent to March 31, 2005, as a result of going to mark-to-market accounting, these revenues were still recognized when delivered, however, they were reclassified to fuel, purchased and net interchange power.  Retail marketing revenues are recognized when energy is delivered.  Service revenues are recognized as services are provided, often on a percentage of completion basis.  

For further information regarding the recognition of revenue, see Note 1F "Derivative Accounting" to the consolidated financial statements.

F.

Derivative Accounting

SFAS Nos. 133 and 149:  In April of 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities," which amended SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities."  SFAS No. 149 incorporated interpretations that were included in previous Derivative Implementation Group guidance, clarified certain conditions, and amended other existing pronouncements.  It was effective for contracts entered into or modified after June 30, 2003.  Management determined that the adoption of SFAS No. 149 did not change NU’s accounting for wholesale and retail marketing contracts, or the ability of NU Enterprises to elect the normal purchases and sales exception.  Certain Utility Group derivative contracts are recorded at fair value as derivative assets and liabilities with offsetting amounts recorded as regulatory liabilities and assets becau se the contracts are part of providing regulated electric or gas service and because management believes that these amounts will be recovered or refunded in rates.

EITF Issue No. 03-11:  In 2003, the FASB ratified the consensus reached by its Emerging Issues Task Force (EITF) in EITF Issue No. 03-11, "Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ as Defined in Issue No. 02-3."  The consensus stated that determining whether realized gains and losses on contracts that physically deliver and are not held for trading purposes should be reported on a net or gross basis was a matter of judgment that depended on the relevant facts and circumstances.  NU Enterprises and the Utility Group have derivative sales contracts, and though these contracts may result in physical delivery, management has determined, based on the relevant facts and circumstances, that because these transactions are part of the respective companies’ procurement activities, inclusion in operating expenses better d epicts these sales activities.  For the years ended December 31, 2005, 2004 and 2003, the settlement of these derivative contracts that are not held for trading purposes are reported on a net basis in operating expenses.

For the period April 1, 2005 to December 31, 2005, Select Energy reported the settlement of derivative and non-derivative retail sales and certain other derivative contracts that physically deliver in revenues and the associated derivative and non-derivative contracts to supply these contracts in fuel, purchased and net interchange power.  In addition, Select Energy reported the settlement of all derivative wholesale contracts, including full requirements sales contracts in fuel, purchased and net interchange power as a result of applying mark-to-market accounting to those contracts.  Certain competitive generation related derivative contracts that are marked-to-market beginning in the fourth quarter of 2005 continue to be recorded in revenues.

Prior to April 1, 2005, Select Energy reported the settlement of long-term derivative contracts, including full requirements sales contracts that physically delivered and were not held for trading purposes on a gross basis, generally with sales in revenues and purchases in expenses.  Retail sales contracts were physically delivered and recorded in revenues.  Short-term sales and purchases represented power and natural gas that was purchased to serve full requirements contracts but was ultimately not needed based on the actual load of the customers.  This excess power and natural gas was sold to the independent system operator or to other counterparties.  For the three months ended March 31, 2005 and for the years ended December 31, 2004 and 2003, settlements of these short-term derivative contracts that were not held for trading purposes, were reported on a net basis in fuel, purchased and net interchange power.

Accounting for Energy Contracts:  The accounting treatment for energy contracts entered into varies and depends on the intended use of the particular contract and on whether or not the contract is a derivative.  Non-derivative contracts such as certain retail sales contracts are recorded at the time of delivery or settlement.  Most of the contracts comprising Select Energy’s wholesale marketing and competitive generation activities are derivatives, and certain Utility Group contracts for the purchase or sale of energy or energy-related products are derivatives.  Certain retail marketing contracts with retail customers are not derivatives, while virtually all contracts entered into to supply these customers are derivatives.  The application of derivative accounting under SFAS No. 133, as amended, is complex and requires management judgment in the following respects: election and designation of the normal purchases and sales exception, identification of derivatives and embedded derivatives, identifying hedge relationships, assessing and measuring hedge ineffectiveness, and determining the fair value of derivatives. All of these judgments, depending upon their timing and effect, can have a significant impact on NU’s consolidated net income.

The fair value of derivatives is based upon the notional amount of a contract and the underlying market price or fair value per unit.  When quantities are not specified in the contract, the company estimates notional amounts using amounts referenced in default provisions and other relevant sections of the contract.  The notional amount is updated during the term of the contract, and updates can have a material impact on mark-to-market amounts.  

The judgment applied in the election of the normal purchases and sales exception (and resulting accrual accounting) includes the conclusions that it is probable at the inception of the contract and throughout its term that it will result in physical delivery and that the quantities will be used or sold by the business over a reasonable period in the normal course of business. If facts and circumstances change and management can no longer support this conclusion, then the normal exception and accrual accounting is terminated and fair value accounting is applied.  Cash flow hedge contracts that are designated as hedges for contracts for which the company has elected the normal purchases and sales exception can continue to be accounted for as cash flow hedges only if the normal exception for the hedged contract continues to be appropriate.  If the normal exception is terminated, then the hedge designation would be terminated at the same time.

Derivative contracts that are entered into for trading purposes are recorded on the consolidated balance sheets at fair value, and changes in fair value are recorded in earnings.  Revenues and expenses for these contracts are recorded on a net basis in revenues.

Contracts that are hedging an underlying transaction and that qualify as derivatives that hedge exposure to the variable cash flows of a forecasted transaction (cash flow hedges) are recorded on the consolidated balance sheets at fair value with changes in fair value generally reflected in accumulated other comprehensive income.  Cash flow 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.   The settlements of cash flow hedges are recorded in the same income statement line item as the forecasted transaction, typically fuel, purchased and net interchange power.  

For further information regarding these contracts and their accounting, see Note 6, "Derivative Instruments," to the consolidated financial statements.

G.

Utility Group Regulatory Accounting

The accounting policies of the Utility Group conform to accounting principles generally accepted in the United States of America applicable to rate-regulated enterprises and historically reflect the effects of the rate-making process in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation."

The transmission and distribution businesses of CL&P, PSNH and WMECO, along with PSNH’s generation business and Yankee Gas’ distribution business, continue to be cost-of-service rate regulated, and management believes that the application of SFAS No. 71 to those businesses continues to be appropriate.  Management also believes it is probable that NU’s Utility Group companies will recover their investments in long-lived assets, including regulatory assets.  In addition, all material net regulatory assets are earning an equity return, except for securitized regulatory assets, which are not supported by equity and substantial portions of the unrecovered contractual obligations regulatory assets.  New Hampshire’s electric utility industry restructuring laws have been modified to delay the sale of PSNH’s fossil and hydroelectric generation assets until at least April of 2006.  There has been no regulatory actio n to the contrary, and management currently has no plans to divest these generation assets.  As the New Hampshire Public Utilities Commission (NHPUC) has allowed and is expected to continue to allow rate recovery of a return on and recovery of these assets, as well as all operating expenses, PSNH meets the criteria for the application of SFAS No. 71.  Generation costs that are not currently recovered in rates are deferred for future recovery.  Stranded costs related to generation assets are deferred for recovery as stranded costs under the "Agreement to Settle PSNH Restructuring" (Restructuring Settlement).  Part 3 stranded costs are non-securitized regulatory assets that must be recovered by a recovery end date determined in accordance with the Restructuring Settlement or be written off.  Based on current projections, PSNH expects to fully recover its Part 3 costs by the middle of 2006.  

Regulatory Assets:  The components of regulatory assets are as follows:

	At December 31,
(Millions of Dollars)	2005	2004
Recoverable nuclear costs	$     44.1	$     52.0
Securitized assets	1,340.9	1,537.4
Income taxes, net	332.5	316.3
Unrecovered contractual obligations	327.5	354.7
Recoverable energy costs	193.0	255.0
Other	245.9	230.8
Totals	$2,483.9	$2,746.2

Included in other regulatory assets above of $245.9 million at December 31, 2005 are the regulatory assets recorded associated with the implementation of FIN 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143," totaling $47.3 million.  A portion of these regulatory assets totaling $17.3 million has been approved for deferred accounting treatment.  At this time, management believes that the remaining regulatory assets are probable of recovery.  

Additionally, the Utility Group had $11.2 million and $11.6 million of regulatory costs at December 31, 2005 and 2004, respectively, that are included in deferred debits and other assets - other on the accompanying consolidated balance sheets.  These amounts represent regulatory costs that have not yet been approved by the applicable regulatory agency.  Management believes these costs are recoverable in future regulated rates.

Recoverable Nuclear Costs:  PSNH recorded a regulatory asset in conjunction with the sale of its share of Millstone 3 in March of 2001 with an unamortized balance of $26.1 million and $29.7 million at December 31, 2005 and 2004, respectively, which is included in recoverable nuclear costs.  Also included in recoverable nuclear costs at December 31, 2005 and 2004 are $18 million and $22.3 million, respectively, primarily related to WMECO's share of  Millstone 1 recoverable nuclear costs associated with the undepreciated plant and related assets at the time Millstone 1 was shutdown.

Securitized Assets:  In March of 2001, CL&P issued $1.4 billion in rate reduction certificates.  CL&P used $1.1 billion of the proceeds from that issuance to buyout or buydown certain contracts with independent power producers (IPP).  The unamortized CL&P securitized asset balance is $731.4 million and $850 million at December 31, 2005 and 2004, respectively.  CL&P used the remaining proceeds from the issuance of the rate reduction certificates to securitize a portion of its SFAS No. 109, "Accounting for Income Taxes," regulatory asset.  The securitized SFAS No. 109 regulatory asset had an unamortized balance of $124.2 million and $144.3 million at December 31, 2005 and 2004, respectively.

In April of 2001, PSNH issued rate reduction bonds in the amount of $525 million.  PSNH used the majority of the proceeds from that issuance to buydown its affiliated power contracts with North Atlantic Energy Corporation (NAEC).  The unamortized PSNH securitized asset balance is $354.5 million and $392.2 million at December 31, 2005 and 2004, respectively.  In January of 2002, PSNH issued an additional $50 million in rate reduction bonds and used the proceeds from that issuance to repay short-term debt that was incurred to buyout a purchased-power contract in December of 2001.  The unamortized PSNH securitized asset balance for the January of 2002 issuance is $20.5 million and $29.4 million at December 31, 2005 and 2004, respectively.

In May of 2001, WMECO issued $155 million in rate reduction certificates and used the majority of the proceeds from that issuance to buyout an IPP contract.  The unamortized WMECO securitized asset balance is $110.3 million and $121.5 million at December 31, 2005 and 2004, respectively.

Securitized assets are being recovered over the amortization period of their associated rate reduction certificates and bonds. All outstanding CL&P rate reduction certificates are scheduled to fully amortize by December 30, 2010, while PSNH rate reduction bonds are scheduled to fully amortize by May 1, 2013, and WMECO rate reduction certificates are scheduled to fully amortize by June 1, 2013.

Income Taxes, Net:  The tax effect of temporary differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of taxable income) is accounted for in accordance with the rate-making treatment of the applicable regulatory commissions and SFAS No. 109.  Differences in income taxes between SFAS No. 109 and the rate-making treatment of the applicable regulatory commissions are recorded as regulatory assets which totaled $332.5 million and $316.3 million at December 31, 2005 and 2004, respectively.  For further information regarding income taxes, see Note 1H, "Summary of Significant Accounting Policies - Income Taxes," to the consolidated financial statements.

Unrecovered Contractual Obligations:  Under the terms of contracts with the Yankee Companies, CL&P, PSNH, and WMECO are responsible for their proportionate share of the remaining costs of the units, including decommissioning.  These amounts which totaled $327.5 million and $354.7 million at December 31, 2005 and 2004, respectively, are recorded as unrecovered contractual obligations.  A portion of these obligations for CL&P was securitized in 2001 and is included in securitized regulatory assets.  Amounts for PSNH and WMECO are being recovered along with other stranded costs.  As discussed in Note 9E, "Commitments and Contingencies - Deferred Contractual Obligations," substantial portions of the unrecovered contractual obligations regulatory assets have not yet been approved for recovery.  At this time management believes that these regulatory assets are probable of recovery.

Recoverable Energy Costs:  Under the Energy Policy Act of 1992 (Energy Act), CL&P, PSNH, WMECO, and NAEC were assessed for their proportionate shares of the costs of decontaminating and decommissioning uranium enrichment plants owned by the United States Department of Energy (DOE) (D&D Assessment).  The Energy Act requires that regulators treat D&D Assessments as a reasonable and necessary current cost of fuel, to be fully recovered in rates like any other fuel cost.  CL&P, PSNH and WMECO no longer own nuclear generation assets but continue to recover these costs through rates.  At December 31, 2005 and 2004, NU’s total D&D Assessment deferrals were $9.8 million and $13.9 million, respectively, and have been recorded as recoverable energy costs.  Also included in recoverable energy costs at December 31, 2004 is $32.5 million related to federally mandated congestion charges (FMCC).  

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, 2005 and 2004, PSNH had $127.5 million and $144.8 million, respectively, of recoverable energy costs deferred under the FPPAC.  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 deferred costs associated with certain contractual purchases from IPPs.  These costs are also treated as Part 3 stranded costs and amounted to $44 million and $50.1 million at December 31, 2005 and 2004, respectively.

The regulated rates of Yankee Gas include a purchased gas adjustment clause under which gas costs above or below base rate levels are charged to or credited to customers.  Differences between the actual purchased gas costs and the current rate recovery are deferred and recovered or refunded in future periods.  These amounts are recorded as recoverable energy costs of $11.7 million and $13.7 million at December 31, 2005 and 2004, respectively.

The majority of the recoverable energy costs are currently recovered in rates from the customers of CL&P, PSNH, WMECO, and Yankee Gas.  PSNH’s recoverable energy costs are Part 3 stranded costs.   

Regulatory Liabilities:  The Utility Group had $1.3 billion and $1.1 billion of regulatory liabilities at December 31, 2005 and 2004, respectively, including revenues subject to refund.  These amounts are comprised of the following:

	At December 31,
(Millions of Dollars)	2005	2004
Cost of removal	$    305.5	$   328.8
CL&P CTA, GSC and SBC overcollections	154.0	200.0
PSNH cumulative deferrals - SCRC	303.3	208.6
Regulatory liabilities offsetting
Utility Group derivative assets	391.2	191.4
Other regulatory liabilities	119.5	141.4
Totals	$1,273.5	$1,070.2

Cost of Removal:  Under SFAS No. 71, regulated utilities, including NU’s Utility Group companies, currently recover amounts in rates for future costs of removal of plant assets.  These amounts which totaled $305.5 million and $328.8 million at December 31, 2005 and 2004, respectively, are classified as regulatory liabilities on the accompanying consolidated balance sheets.

CL&P CTA, GSC and SBC Overcollections and PSNH Cumulative Deferrals - SCRC:  The Competitive Transition Assessment (CTA) allows CL&P to recover stranded costs, such as securitization costs associated with the rate reduction bonds, amortization of regulatory assets, and IPP over market costs.  The Generation Service Charge (GSC) allows CL&P to recover the costs of the procurement of energy for standard offer service.  The System Benefits Charge (SBC) allows CL&P to recover certain regulatory and energy public policy costs, such as public education outreach costs, hardship protection costs, transition period property taxes, and displaced workers protection costs.   CL&P CTA, GSC and SBC overcollections totaled $154 million and $200 million at December 31, 2005 and 2004, respectively.  The cumulative deferrals accrued under the Stranded Cost Recovery Charge (SCRC) totaled $303.3 million and $208.6 mil lion at December 31, 2005 and 2004, respectively, and will decrease the amount of non-securitized stranded costs to be recovered from PSNH's customers in the future.

Regulatory Liabilities Offsetting Utility Group Derivative Assets:  The regulatory liabilities offsetting derivative assets relate to the fair value of CL&P IPP contracts used to purchase power that will benefit ratepayers in the future.  These amounts totaled $391.2 million and $191.4 million at December 31, 2005 and 2004, 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.

Details of income tax (benefit)/expense are as follows:

	For the Years Ended December 31,
(Millions of Dollars)	2005	2004	2003
The components of the federal and state income tax provisions are:
Current income taxes:
Federal	$  15.0	$ (53.5)	$ 143.3
State	9.1	(6.5)	37.1
Total current	24.1	(60.0)	180.4
Deferred income taxes, net
Federal	(152.6)	120.3	(90.0)
State	(46.5)	(4.8)	(35.9)
Total deferred	(199.1)	115.5	(125.9)
Investment tax credits, net	(3.7)	(3.8)	(3.8)
Income tax benefit/(expense) related to discontinued operations	15.9	(1.0)	(3.1)
Income tax (benefit)/expense	$(162.8)	$    50.7	$   47.6
A reconciliation between income tax (benefit)/expense and the   expected tax (benefit)/expense at the statutory rate is as follows:
Expected federal income tax (benefit)/expense	$(149.0)	$    60.9	$   62.1
Tax effect of differences:
Depreciation	(3.5)	5.8	4.0
Amortization of regulatory assets	1.8	1.8	1.8
Investment tax credit amortization	(3.7)	(3.8)	(3.8)
State income taxes, net of federal benefit	(43.4)	(5.4)	0.8
Medicare subsidy	(6.0)	(1.0)	-
Dividends received deduction	(0.3)	(1.2)	(1.4)
Tax asset valuation allowance/reserve adjustments	18.5	1.9	(5.4)
Other, net	6.9	(7.3)	(7.4)
	(178.7)	51.7	50.7
Income tax benefit/(expense) from discontinued operations	15.9	(1.0)	(3.1)
Income tax (benefit)/expense	$(162.8)	$    50.7	$    47.6

NU and its subsidiaries file a consolidated federal income tax return.  NU and its subsidiaries file state income tax returns, with some filing in more than one state.  NU and its subsidiaries are parties to a tax allocation agreement under which taxable subsidiaries pay no more taxes than they would have otherwise paid had they filed a standalone tax return and subsidiaries generating tax losses are paid for their losses when utilized.

The tax effects of temporary differences that give rise to the current and long-term net accumulated deferred tax obligations are as follows:

	At December 31,
(Millions of Dollars)	2005	2004
Deferred tax liabilities - current:
Change in fair value of energy contracts	$    7.3	$    74.7
Other	35.6	33.0
Total deferred tax liabilities - current	42.9	107.7
Deferred tax assets - current:
Change in fair value of energy contracts	50.7	76.3
Other	15.9	14.7
Total deferred tax assets - current	66.6	91.0
Net deferred tax (assets)/liabilities - current	(23.7)	16.7
Deferred tax liabilities – long-term:
Accelerated depreciation and     other plant-related differences	1,120.7	1,105.5
Employee benefits	165.0	169.2
Regulatory amounts:
Securitized contract termination costs and other	223.6	252.1
Income tax gross-up	215.1	215.1
Other	239.3	227.2
Total deferred tax liabilities - long-term	1,963.7	1,969.1
Deferred tax assets – long-term:
Regulatory deferrals	365.8	365.0
Employee benefits	112.0	86.7
Income tax gross-up	34.0	32.6
Other	175.4	63.0
Total deferred tax assets - long-term	687.2	547.3
Less: valuation allowance	29.8	12.6
Net deferred tax assets - long-term	657.4	534.7
Net deferred tax liabilities - long-term	1,306.3	1,434.4
Net deferred tax liabilities	$1,282.6	$1,451.1

At December 31, 2005, NU had state net operating loss carry forwards of $371.6 million that expire between December 31, 2007 and December 31, 2025.  At December 31, 2005, NU also had state credit carry forwards of $21.2 million that expire on December 31, 2010.  

At December 31, 2004, NU had state net operating loss carry forwards of $206.2 million that expire between December 31, 2006 and December 31, 2024.  At December 31, 2004, NU also had state credit carry forwards of $9.3 million that expire on December 31, 2009.

In 2000, NU requested from the Internal Revenue Service (IRS) a Private Letter Ruling (PLR) regarding the treatment of unamortized investment tax credits (ITC) and excess deferred income taxes (EDIT) related to generation assets that have been sold.  EDIT are temporary differences between book and taxable income that were recorded when the federal statutory tax rate was higher than it is now or when those differences were expected to be resolved.  The PLR addresses whether or not EDIT and ITC can be returned to customers, which without a PLR management believes would represent a violation of current tax law.  The IRS declared a moratorium on issuing PLRs until final regulations on the return of EDIT and ITC to regulated customers are issued by the Treasury Department.  Proposed regulations were issued in December of 2005 withdrawing proposed regulations issued in March of 2003.  The new proposed regulations would generally allow EDIT and ITC generated by property that is no longer regulated to be returned to regulated customers without violating the tax law.  The new proposed regulations would only apply to property that ceases to be regulated public utility property after December of 2005.  As such, the EDIT and ITC cannot be used to reduce customer rates.  The ultimate results of this contingency could have a positive impact on CL&P’s earnings.

I.

Accounting for R.M. Services, Inc.

NU had an investment in R.M. Services, Inc. (RMS), a provider of consumer collection services. In January of 2003, the FASB issued FIN 46, "Consolidation of Variable Interest Entities," which was effective for NU on July 1, 2003.  RMS is a variable interest entity (VIE), as defined.  FIN 46, as revised, required that the party to a VIE that absorbs the majority of the VIE’s losses, defined as the "primary beneficiary," consolidate the VIE.  Upon adoption of FIN 46 on July 1, 2003, management determined that NU was the "primary beneficiary" of RMS under FIN 46 and that NU was now required to consolidate RMS into its financial statements.  To consolidate RMS, NU eliminated the carrying value of its preferred stock investment in RMS and recorded the assets and liabilities of RMS.  This adjustment resulted in a negative $4.7 million after-tax cumulative effect of an accounting change in the third qu arter of 2003, and the assets and liabilities recorded are summarized as follows (millions of dollars):

Current assets	$ 0.6
Net property, plant and equipment	1.7
Other noncurrent assets	1.5
Current liabilities	(0.6)
	3.2
Elimination of investment at July 1, 2003	(10.5)
Pre-tax cumulative effect of accounting change	(7.3)
Income tax benefit	2.6
Cumulative effect of accounting change	$(4.7)

Prior to the consolidation of RMS on July 1, 2003, NU recorded $1.4 million of pre-tax investment write-downs in 2003.  After RMS was consolidated on July 1, 2003, $1.9 million of after-tax operating losses were included in earnings.

On June 30, 2004, NU sold virtually all of the assets and liabilities of RMS for $3 million and recorded a gain on the sale totaling $0.8 million.  Prior to the sale, RMS had after-tax operating losses totaling $1 million in 2004.  These charges and gains are included in Note 1V, "Summary of Significant Accounting Policies - Other Income, Net," and in the other segment in Note 17, "Segment Information," to the consolidated financial statements.

NU has no other VIE’s for which it is defined as the "primary beneficiary."

J.

Other Investments

NU maintains certain other investments.  These investments include Acumentrics Corporation (Acumentrics), a developer of fuel cell and power quality equipment, and BMC Energy LLC (BMC), an operator of renewable energy projects.

Acumentrics:  Management determined that the value of NU’s investment in Acumentrics declined in 2004 and that the decline was other than temporary.  Total pre-tax investment write-downs of $9.1 million were recorded in 2004 to reduce the carrying value of the investment.  During 2004, NU also invested an additional $0.2 million in Acumentrics debt securities.  NU’s investment in Acumentrics, which is included in receivables on the accompanying consolidated balance sheets, totaled $0.6 million in debt securities at both December 31, 2005 and 2004.

BMC:  In the first quarter of 2004, based on revised information that negatively impacted undiscounted cash flow projections and fair value estimates, management determined that the fair value of the note receivable from BMC had declined and that the note was impaired. As a result, management recorded a pre-tax investment write-down of $2.5 million in the first quarter of 2004.  In the second quarter of 2005, based on additional revised information that negatively impacted the fair value of the BMC note receivable, management recorded an additional pre-tax investment write-down of $0.8 million.  The remaining note receivable from BMC, which is included in deferred debits and other assets – other on the accompanying consolidated balance sheets, totaled $0.5 million and $1.3 million at December 31, 2005 and 2004, respectively.  

The Acumentrics and BMC investment write-downs are included in other income, net on the accompanying consolidated statements of (loss)/income.  For further information, see Note 1V, "Summary of Significant Accounting Policies - Other Income, Net," to the consolidated financial statements.

K.

Depreciation

The provision for depreciation on utility assets is calculated using the straight-line method based on the estimated remaining useful lives of depreciable plant-in-service, which range primarily from 3 years to 75 years, adjusted for salvage value and removal costs, as approved by the appropriate regulatory agency where applicable.  Depreciation rates are applied to plant-in-service from the time it is placed in service.  When plant is retired from service, the original cost of the plant, including costs of removal less salvage, is charged to the accumulated provision for depreciation.  Cost of removal is classified as a regulatory liability.  The depreciation rates for the several classes of electric utility plant-in-service are equivalent to a composite rate of 3.2 percent in 2005, 3.3 percent in 2004, and 3.4 percent in 2003.

NU also maintains other non-utility plant which is being depreciated using the straight-line method based on their estimated remaining useful lives, which range primarily from 15 years to 120 years.

L.

Jointly Owned Electric Utility Plant

Regional Nuclear Companies:  At December 31, 2005, CL&P, PSNH and WMECO own common stock in three regional nuclear companies (Yankee Companies).  Each of the Yankee Companies owns a single nuclear generating plant which is being decommissioned.  NU’s ownership interests in the Yankee Companies at December 31, 2005, 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), and 20 percent of the Maine Yankee Atomic Power Company (MYAPC).  The total carrying value of CYAPC, MYAPC and YAEC, which is included in deferred debits and other assets - other on the accompanying consolidated balance sheets and the Utility Group - electric distribution reportable segment, totaled $28.6 million at both December 31, 2005 and 2004.  Earnings related to these equity investments are included in other income, ne t on the accompanying consolidated statements of (loss)/income.  For further information, see Note 1V, "Summary of Significant Accounting Policies - Other Income, Net," to the consolidated financial statements.  

CYAPC filed with the FERC to recover the increased estimate of decommissioning and plant closure costs.  The FERC proceeding is ongoing.  Management believes that the FERC proceeding has not impaired the value of its investment in CYAPC totaling $22.7 million at December 31, 2005 but will continue to evaluate the impacts that the FERC proceeding has on NU's investment.  For further information, see Note 9E, "Commitments and Contingencies - Deferred Contractual Obligations," to the consolidated financial statements.  

Hydro-Quebec:  NU parent has a 22.7 percent equity ownership interest in two companies that transmit electricity imported from the Hydro-Quebec system in Canada.  NU’s investment, which is included in deferred debits and other assets - other on the accompanying consolidated balance sheets, totaled $8.5 million and $9.5 million at December 31, 2005 and 2004, respectively.

M.

Allowance for Funds Used During Construction

The allowance for funds used during construction (AFUDC) is a non-cash item that is included in the cost of Utility Group utility plant and represents the cost of borrowed and equity funds used to finance construction.  The portion of AFUDC attributable to borrowed funds is recorded as a reduction of other interest expense and the cost of equity funds is recorded as other income on the accompanying consolidated statements of (loss)/income as follows:

	For the Years Ended December 31,
(Millions of Dollars, except percentages)	2005		2004		2003
Borrowed funds	$10.1		$3.9		$  3.9
Equity funds	12.3		3.8		6.5
Totals	$22.4		$7.7		$10.4
Average AFUDC rate	5.8	%	3.9	%	4.0	%

The average Utility Group AFUDC rate is based on a FERC-prescribed formula that develops an average rate using the cost of the company’s short-term financings as well as the company’s capitalization (preferred stock, long-term debt and common equity). The average rate is applied to eligible construction work in progress amounts to calculate AFUDC.  The increase in the average AFUDC rate during 2005 is primarily due to increases in short-term and long-term debt interest rates.

N.

Equity-Based Compensation

NU maintains an Employee Stock Purchase Plan and other long-term, equity-based incentive plans under the Northeast Utilities Incentive Plan (Incentive Plan).  NU accounts for these plans under the recognition and measurement principles of Accounting Principles Board Opinion (APB) No. 25, "Accounting for Stock Issued to Employees," and related interpretations.  Equity-based employee compensation cost for stock options is not 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.  During the years ended December 31, 2005, 2004 and 2003, no stock options were awarded.  The following table illustrates the effect on net income and earnings per share (EPS) if NU had applied the fair value recognition provisions of SFAS No. 123 to equity-based employee compensation:

	For the Years Ended December 31,
(Millions of Dollars,  except per share amounts)	2005	2004	2003
Net (loss)/income as reported	$(253.5)	$116.6	$116.4
Add:  Equity-based employee compensation   expense included in the reported net   (loss)/income, net of related tax effects	2.6	2.3	1.2
Net (loss)/income before equity-based   compensation	(250.9)	118.9	117.6
Deduct:  Total equity-based employee   compensation expense determined under the  fair value-based method for all awards, net of  related tax effects	(1.2)	(2.7)	(2.5)
Pro forma net (loss)/income	$(252.1)	$116.2	$115.1
EPS:
Basic and diluted - as reported	$  (1.93)	$  0.91	$  0.91
Basic and diluted - pro forma	$  (1.92)	$  0.91	$  0.90

In 2005, NU disclosed the final pro forma expense for stock options granted in 2002 as all stock options were fully vested.  The total equity-based employee compensation expense of $1.2 million, $2.7 million, and $2.5 million above includes offsetting amounts of $2.2 million, $0.7 million, and $0.6 million, related to forfeitures of stock options made for the years ended December 31, 2005, 2004, and 2003, respectively.  

NU assumes an income tax rate of 40 percent to estimate the tax effect on total equity-based employee compensation expense determined under the fair value-based method for all awards.

NU accounts for restricted stock and restricted stock units in accordance with APB No. 25 and amortizes the intrinsic value of the stock at the award date over the related service period.

For information regarding new accounting standards issued but not yet adopted associated with equity-based compensation, see Note 1C, "Summary of Significant Accounting Policies – Accounting Standards Issued But Not Yet Adopted," to the consolidated financial statements.

O.

Sale of Receivables

Utility Group:  At December 31, 2005 and 2004, CL&P had sold an undivided interest in its accounts receivable of $80 million and $90 million, respectively, to a financial institution with limited recourse through CL&P Receivables Corporation (CRC), a wholly owned subsidiary of CL&P. CRC can sell up to $100 million of an undivided interest in its accounts receivable and unbilled revenues.  At December 31, 2005 and 2004, the reserve requirements calculated in accordance with the Receivables Purchase and Sale Agreement were $21 million and $18.8 million, respectively. These reserve amounts are deducted from the amount of receivables eligible for sale.  At their present levels, these reserve amounts do not limit CL&P’s ability to access the full amount of the facility.  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.

At December 31, 2005 and 2004, amounts sold to CRC by CL&P but not sold to the financial institution totaling $252.8 million and $139.4 million, respectively, are included as investments in securitizable assets on the accompanying consolidated balance sheets.  These amounts would be excluded from CL&P’s assets in the event of CL&P’s bankruptcy.  On July 6, 2005, CRC renewed its Receivables Purchase and Sale Agreement with CL&P and the financial institution through July 5, 2006.  CL&P’s continuing involvement with the receivables that are sold to CRC and the financial institution is limited to the servicing of those receivables.

The transfer of receivables to the financial institution under this arrangement qualifies for sale treatment under SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities - A Replacement of SFAS No. 125."

NU Enterprises:  SESI has a master purchase agreement with an unaffiliated third party under which SESI may sell certain monies due or which will become due under delivery orders issued pursuant to United States federal government energy savings performance contracts (energy savings contracts).  The sale of a portion of the future cash flows from the energy savings contracts is used to reimburse the costs to construct the energy savings projects.  SESI continues to provide performance period services under its contract with the government for the remaining term.  The portion of future government payments for performance period services is not sold to the unaffiliated third party or recorded as a receivable until such services are rendered.

At December 31, 2005 and 2004, SESI had sold $38.6 million and $30 million, respectively, of accounts receivable related to the installation of the energy savings projects, with limited recourse, under this master purchase agreement.  Under its delivery orders with the government, SESI is responsible for ongoing maintenance and other services related to the energy savings project installation and receives payment for those services in addition to the amounts sold under the master purchase agreement.  NU has provided a guarantee that SESI will perform its obligations under the master purchase agreement and subsequent individual assignment agreements.  The sale of the receivables to the unaffiliated third party qualifies for sales treatment under SFAS No. 140, and therefore these receivables are not included in NU's consolidated financial statements.

SESI has entered into assignment agreements to sell an additional $17.9 million of receivables upon completion of the installation of certain savings projects.  Until the projects are completed, the receivables are recorded under the percentage of completion method and included in the consolidated financial statements and the advances under the master purchase agreement are recorded as debt.  

P.

Asset Retirement Obligations

On January 1, 2003, NU implemented SFAS No. 143, "Accounting for Asset Retirement Obligations," requiring legal obligations associated with the retirement of property, plant and equipment to 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.  Management concluded that there were no asset retirement obligations (AROs) to be recorded upon implementation of SFAS No. 143.  

In March of 2005, the FASB issued FIN 47, required to be implemented by December 31, 2005.  FIN 47 requires an entity to recognize a liability for the fair value of an ARO even if it is conditional on a future event and the liability’s fair value can be reasonably estimated.  FIN 47 provides that settlement dates and future costs should be reasonably estimated when sufficient information becomes available, and provides guidance on the definition and timing of sufficient information in determining expected cash flows and fair values.  Management has completed its identification of conditional AROs and has identified various categories of AROs, primarily certain assets containing asbestos and hazardous contamination.  A fair value calculation, reflecting expected probabilities for settlement scenarios, and a data consistency review across operating companies have been performed.  

The earnings impact of this implementation has been reported as a cumulative effect of accounting change, net of tax benefit, of $1 million related to NU Enterprises.  The Utility Group companies utilized regulatory accounting in accordance with SFAS No. 71 and the amounts are included in other regulatory assets at December 31, 2005.  The fair value of the AROs is included in property, plant and equipment and related accretion is recorded as a regulatory asset, with corresponding credits reflecting the ARO liabilities in deferred credits and other liabilities - other, on the accompanying consolidated balance sheet at December 31, 2005.  Depreciation of the ARO asset is also included as a regulatory asset with an offsetting amount in accumulated depreciation.  The following table presents the fair value of the ARO, the related accumulated depreciation, the regulatory asset, and the ARO liabilities.  

	At December 31, 2005
(Millions of Dollars)	Fair Value of ARO Asset	Accumulated Depreciation of ARO Asset	Regulatory Asset	ARO Liabilities
Asbestos	$  3.9	$(2.1)	$21.0	$(22.8)
Hazardous contamination	7.1	(1.7)	17.4	(22.8)
Other AROs	9.6	(3.9)	8.9	(14.6)
Total Utility Group AROs	$20.6	$(7.7)	$47.3	$(60.2)

A summary of the Utility Group AROs by company is as follows:
	At December 31, 2005
(Millions of Dollars)	Fair Value	Accumulated Depreciation of ARO Asset	Regulatory Asset	ARO Liability
CL&P	$16.8	$(6.0)	$25.1	$(35.9)
PSNH	2.3	(1.2)	17.3	(18.4)
WMECO	1.1	(0.3)	2.4	(3.2)
Yankee Gas	0.4	(0.2)	2.5	(2.7)
Total Utility Group AROs	$20.6	$(7.7)	$47.3	$(60.2)

The following table presents the ARO liabilities as of the dates indicated, as if FIN 47 has been applied for all periods affected (millions of dollars):  

	At December 31, 2005	At December 31, 2004	At  January 1, 2004
Utility Group	$(60.2)	$(53.5)	$(52.7)
NU Enterprises	(1.7)	(1.7)	(1.6)

The net negative effect on earnings, as if FIN 47 had been applied for all periods affected, is as follows for the years ended December 31, 2005, 2004 and 2003 (millions of dollars):

	2005	2004	2003
Net (loss)/income as reported before cumulative effect   of accounting change related to FIN 47	$(252.5)	$116.6	$116.4
Effect of application of FIN 47	(0.1)	(0.1)	(0.1)
Pro forma net (loss)/income before cumulative effect   of accounting change related to FIN 47	$(252.6)	$116.5	$116.3
EPS:
Basic and diluted – as reported	$(1.92)	$0.91	$0.91
Basic and diluted – pro forma	$(1.92)	$0.91	$0.91

Q.

Materials and Supplies

Materials and supplies include materials purchased primarily for construction, operation and maintenance (O&M) purposes.  Materials and supplies are valued at the lower of average cost or market.

R.

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand and short-term cash investments that are highly liquid in nature and have original maturities of three months or less.  At the end of each reporting period, overdraft amounts are reclassified from cash and cash equivalents to accounts payable.

S.

Special Deposits

Special deposits represent amounts Select Energy has on deposit with unaffiliated counterparties and brokerage firms in the amounts of $103.8 million and $46.3 million at December 31, 2005 and 2004, respectively.  SESI special deposits totaling $10.2 million are included in assets held for sale on the accompanying consolidated balance sheet at December 31, 2005.  Special deposits at December 31, 2004 also included $20 million in escrow for SESI that had not been spent on construction projects and $16.3 million in escrow for Yankee Gas, which represented payment for Yankee Gas’ first mortgage bonds that were paid on June 1, 2005.  

T.

Restricted Cash - LMP Costs

Restricted cash - LMP costs represents incremental LMP cost amounts that were collected by CL&P and deposited into an escrow account.

U.

Excise Taxes

Certain excise taxes levied by state or local governments are collected by NU from its customers. These excise taxes are accounted for on a gross  basis with collections in revenues and payments in expenses.  For the years ended December 31, 2005, 2004 and 2003, gross receipts taxes, franchise taxes and other excise taxes of $112.7 million, $97 million, and $96.8 million, respectively, are included in operating revenues and taxes other than income taxes on the accompanying consolidated statements of (loss)/ income.

V.

Other Income, Net

The pre-tax components of other income/(loss) items are as follows:

	For the Years Ended December 31,
(Millions of Dollars)	2005	2004	2003
Other Income:
Investment income	$ 20.1	$ 12.5	$  5.6
CL&P procurement fee	17.8	11.7	-
AFUDC - equity funds	12.3	3.8	6.5
Gain on disposition of property	2.7	3.8	2.6
Return on regulatory deferrals	1.4	1.8	5.8
Conservation and load management incentive	7.7	6.7	2.3
Equity in earnings of regional nuclear      generating and transmission companies	3.3	2.6	4.5
Gain on sale of RMS	-	0.8	-
Other	5.9	5.1	3.8
Total Other Income	71.2	48.8	31.1
Other Loss:
Environmental reserves	(5.1)	(0.3)	-
Charitable contributions	(4.7)	(4.6)	(9.2)
Investment write-downs	(6.9)	(13.8)	(1.4)
Rate reduction bond administrative fees	(3.3)	(3.4)	(3.5)
Other	(14.0)	(12.1)	(12.9)
Total Other Loss	(34.0)	(34.2)	(27.0)
Total Other Income, Net	$ 37.2	$ 14.6	$   4.1

None of the amounts in either other income - other or other loss - other are individually significant as defined by the SEC.

W.

Supplemental Cash Flow Information

	For the Years Ended December 31,
(Millions of Dollars)	2005	2004	2003
Cash (received)/paid during the year for:     Interest, net of amounts capitalized	$276.7	$244.6	$241.3
Income taxes	$(56.1)	$  74.3	$248.3

In 2005, NU Enterprises sold certain assets of SECI-NH.  The sales price included a note receivable of $0.3 million with interest only payments due on the note for the first two years and the principle amount due at the end of two years.

X.

Marketable Securities

SERP and Prior Spent Nuclear Fuel Trusts:  NU’s marketable securities are classified as available-for-sale, as defined by SFAS No. 115, "Accounting for Certain Investments and Debt and Equity Securities."  Unrealized gains and losses are reported as a component of accumulated other comprehensive income on the consolidated statements of shareholders’ equity.  NU currently maintains two trusts that hold marketable securities.  The trusts are used to fund NU’s Supplemental Executive Retirement Plan (SERP) and WMECO’s prior spent nuclear fuel liability.  Realized gains and losses related to the SERP assets are included in other income, net, on the consolidated statements of (loss)/income.  Realized gains/(losses) associated with the WMECO spent nuclear fuel trust are included in fuel, purchased and net interchange power on the consolidated statements of (loss)/income.

Globix:  On July 19, 2004, NEON Communications, Inc. (NEON) and Globix Corporation (Globix) announced a definitive merger agreement in which Globix, an unaffiliated publicly owned entity, would acquire NEON for shares of Globix common stock. Prior to the merger announcement, NU invested $2.1 million in 2004 in exchange for an additional 341,000 shares of NEON common stock.  Management calculated the estimated fair value of its investment in NEON based on the Globix share price at December 31, 2004 and the conversion factor.  Results of the calculation indicated that the fair value of NU’s investment in NEON was below the carrying value at December 31, 2004 and was impaired.  As a result, NU recorded a pre-tax write-down of $2.2 million in 2004.

The merger closed on March 8, 2005, and NU received 1.2748 shares of Globix common stock for each of the 2.1 million shares of NEON stock it owned.  In connection with the merger, NU recorded a pre-tax write-down of $0.2 million.  After the Globix merger, NU recognized unrealized losses on its Globix investment in accumulated other comprehensive income.  During 2005, the value of Globix common stock declined and management reviewed NU’s investment in Globix, considering the length and severity of its decline in value, other factors about the company, and management’s intentions with respect to holding this investment.  Based on these factors, management recorded an additional pre-tax impairment charge in 2005 of $5.9 million to reflect an other-than-temporary impairment.  This amount is included in the negative $0.9 million after-tax amount which was reclassified from accumulated other comprehensive income and recognize d in earnings in 2005.  

NU's investment in Globix totaled $3.7 million and $9.8 million at December 31, 2005 and 2004, respectively.  

For information regarding marketable securities which also includes NU's investment in Globix, see Note 11, "Marketable Securities," to the consolidated financial statements.

Y.

Counterparty Deposits

Balances collected from counterparties resulting from Select Energy’s credit management activities totaled $28.9 million at December 31, 2005 and $57.7 million at December 31, 2004.  These amounts are recorded as current liabilities and included as counterparty deposits on the accompanying consolidated balance sheets.  To the extent Select Energy requires collateral from counterparties, cash is received as a part of the total collateral required.  The right to receive such cash collateral in an unrestricted manner is determined by the terms of Select Energy’s agreements.  Key factors affecting the unrestricted status of a portion of this cash collateral include the financial standing of Select Energy and of NU as its credit supporter.

Z.

Provision for Uncollectible Accounts

NU maintains a provision for uncollectible accounts to record its receivables at an estimated net realizable value.  This provision is determined based upon a variety of factors, including applying an estimated uncollectible account percentage to each receivables aging category, historical collection and write-off experience and management’s assessment of collectibility from individual customers.  Management reviews at least quarterly the collectibility of the receivables, and if circumstances change, collectibility estimates are adjusted accordingly.  Receivable balances are written-off against the provision for uncollectible accounts when these balances are deemed to be uncollectible.

2.

Wholesale Contract Market Changes

NU recorded $440.9 million of pre-tax wholesale contract market changes for the year ended December 31, 2005, related to the changes in the fair value of wholesale contracts that the company is in the process of exiting.  These amounts are reported as wholesale contract market changes, net on the consolidated statements of (loss)/income.  These changes are comprised of the following items:

·

A charge of $406.9 million related to the mark-to-market of certain long-dated wholesale electricity contracts in New England and New York with municipal and other customers.  The charge reflects negative mark-to-market movements on these contracts through December 31, 2005 as a result of rising energy prices, partially offset by positive effects of buying out certain obligations in 2005 at prices less than their marks at the time;

·

A charge of approximately $80 million related to purchases of additional electricity for an increase in the load forecasts related to a full requirements contract with a customer in the Pennsylvania-New Jersey-Maryland (PJM) power pool;

·

A benefit of approximately $38 million related to mark-to-market gains on certain generation related contracts which the company is in the process of exiting;

·

A benefit of $59.9 million for mark-to-market gains primarily related to retail supply contracts, by the wholesale business that were previously held to serve certain retail electric load which the company has exited or settled.  Included in the $59.9 million is $30 million related to retail supply contracts marked-to-market as a result of the March 9, 2005 decision to exit the wholesale marketing business.  

·

A charge of $15.5 million in the fourth quarter of 2005 in connection with the decision to exit the competitive generation business related to marking-to-market two contracts to sell the output of its generation in 2007 and 2008.  NU Enterprises is in the process of exiting these contracts.  These two generation sales contracts were formerly accounted for under accrual accounting; however, accrual accounting was terminated in the fourth quarter of 2005 due to the high probability that these contracts would be net settled instead of physically delivered.  

·

A charge of $36.4 million for mark-to-market contract asset write-offs related to long-term wholesale electricity contracts and a contract termination payment in March of 2005.

For further information regarding these derivative assets and liabilities that are being exited, see Note 6, "Derivative Instruments," to the consolidated financial statements.

3.

Restructuring and Impairment Charges

The company evaluates long-lived assets such as property, plant and equipment to determine if these assets are impaired when events or changes in circumstances occur such as the 2005 announced decisions to exit all of the NU Enterprises businesses.  

When the company believes one of these events has occurred, the determination needs to be made if a long-lived asset should be classified as an asset to be held and used or if that asset should be classified as held for sale.  For assets classified as held and used, the company estimates the undiscounted future cash flows associated with the long-lived asset or asset group and an impairment loss is recognized if the carrying amount of an asset is not recoverable and exceeds its fair value.  The carrying amount is not recoverable if it exceeds the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset.  For assets held for sale, a long-lived asset or disposal group is measured at the lower of its carrying amount or fair value less cost to sell.  

In order to estimate an asset's future cash flows, the company considers historical cash flows, changes in the market and other factors that may affect future cash flows.  The company considers various relevant factors, including the method and timing of recovery, forward price curves for energy, fuel costs, and operating costs.  Actual future market prices, costs and cash flows could vary significantly from those assumed in the estimates, and the impact of such variations could be material.

NU Enterprises recorded $69.2 million of pre-tax restructuring and impairment charges for the year ended December 31, 2005 related to the decision to exit the merchant energy businesses and its energy services businesses.  The amounts related to continuing operations are included as restructuring and impairment charges on the consolidated statements of (loss)/income with the remainder included in discontinued operations.  These charges are included as part of the NU Enterprises reportable segment in Note 17, "Segment Information," to the consolidated financial statements.  A summary of those 2005 pre-tax charges is as follows:  

(Millions of Dollars)	Year Ended  December 31, 2005
Merchant Energy:
Wholesale Marketing:
Impairment charges	$ 9.7
Restructuring charges	6.7
Subtotal	16.4
Retail Marketing:
Impairment charges	9.2
Competitive Generation:
Impairment charges	1.5
Subtotal - Merchant Energy	27.1
Energy Services and Other:
Impairment charges	39.1
Restructuring charges	3.0
Subtotal - Energy Services and Other	42.1
Total restructuring and   impairment charges	69.2
Restructuring and impairment  charges included in   discontinued operations	25.1
Total restructuring and impairment   charges included in   continuing operations	$44.1

On March 9, 2005, NU concluded that NU Enterprises’ energy services businesses are not central to NU’s long-term strategy and do not meet the company’s expectations of profitability and as a result, the company concluded that it would explore ways to exit those businesses in a manner that maximizes their value.  On November 7, 2005, NU announced its decision to exit the remainder of its merchant energy business segment, which includes the retail marketing and competitive generation business.  During 2005, as a result of impairment analyses performed, assets of $9.7 million, $9.2 million and $1.5 million relating to wholesale marketing, retail marketing, and competitive generation businesses, respectively, including goodwill and intangible assets totaling $12.4 million, were determined to be impaired and were written off.  

In 2005, NU Enterprises hired an outside firm to assist in valuing its energy services businesses and their exit.  Based in part on that firm's work, the company concluded that $29.1 million of goodwill associated with those businesses and $9.2 million of intangible assets were impaired.  Also in 2005, the energy services businesses and NU Enterprises parent recorded an impairment charge of $0.8 million due to the impairment of certain fixed assets.  

In 2005, pre-tax restructuring charges totaling $9.7 million of which $6.7 million and $3 million relate to the wholesale marketing and energy services businesses, respectively, were recorded for employee termination costs, consulting fees and other costs.  Additional restructuring charges will be recognized as incurred and may include professional fees and employee-related and other costs.

At December 31, 2005, NU determined that no additional impairment existed for the competitive generation business assets based on NU's evaluation using cash flow methodologies and an analysis of comparable companies or transactions.  

The following table summarizes the liabilities related to restructuring costs which are recorded in accounts payable and other current liabilities on the accompanying consolidated balance sheet at December 31, 2005:  

(Millions of Dollars)	Employee Termination Costs	Consulting Fees	Total
Restructuring liability as of January 1, 2005	$     -	$     -	$     -
Costs incurred	2.3	7.4	9.7
Cash payments	(0.5)	(2.1)	(2.6)
Restructuring liability as of December 31, 2005	$ 1.8	$ 5.3	$ 7.1

4.

Assets Held for Sale and Discontinued Operations

Assets Held for Sale:  On March 9, 2005, NU announced the decision to exit NU Enterprises' energy services businesses.  During the third quarter of 2005, management determined that it expected to sell four of its energy services within one year.  Two of these businesses, SECI-NH (including Reeds Ferry) and Woods Network, were sold on November 8, 2005 and November 22, 2005, respectively.  

Certain assets and liabilities of the energy services businesses are being accounted for as held for sale.  These businesses, which are valued at the lower of their carrying amount or fair value less cost to sell, are as follows:  SESI, a performance contracting subsidiary that specializes in upgrading the energy efficiency of large governmental and institutional facilities, and Woods Electrical, a subsidiary of NGS which provides third-party electrical services.  These businesses are included as part of the NU Enterprises reportable segment in Note 17, "Segment Information," to the consolidated financial statements.  The major classes of assets and liabilities that are held for sale at December 31, 2005 are as follows:

(Millions of Dollars)
Special deposits	$  10.2
Accounts and notes receivable	8.6
Other current assets	1.3
Other assets	2.2
Long-term contract receivables	79.5
Total assets	101.8
Accounts and notes payable	3.0
Other current liabilities	3.2
Long-term debt	86.3
Other liabilities	9.0
Total liabilities	101.5
Net assets	$   0.3

Discontinued Operations:  NU's consolidated statements of (loss)/income for the years ended December 31, 2005, 2004, and 2003 present the operations for SESI, Woods Electrical, SECI-NH, and Woods Network as discontinued operations as a result of meeting certain criteria requiring this presentation.  Under this presentation, revenues and expenses of these businesses are classified net of tax in (loss)/income from discontinued operations on the accompanying consolidated statements of (loss)/income and all prior periods have been reclassified.  These businesses are included as part of the NU Enterprises reportable segment in Note 17, "Segment Information," to the consolidated financial statements.  Summarized financial information for the discontinued operations is as follows:  

	For the Years Ended December 31,
(Millions of Dollars)	2005	2004	2003
Operating revenue	$116.3	$170.9	$130.7
Restructuring and impairment charges	$  25.1	$        -	$        -
(Loss)/income before income tax  (benefit)/expense	$(38.1)	$    4.6	$    7.8
Loss from sale	$  (1.1)	$        -	$        -
Income tax (benefit)/expense	$(15.9)	$    1.0	$    3.1
Net (loss)/income from   discontinued operations	$(23.3)	$    3.6	$    4.7

On November 8, 2005, NU Enterprises completed the sale of certain assets of SECI-NH (including 100 percent of the common stock of Reeds Ferry) and recognized a pre-tax loss on disposal of $0.3 million.  On November 22, 2005, NU Enterprises completed the sale of Woods Network and recognized a pre-tax loss on disposal of $0.8 million.  The proceeds from these two sales totaled $6.5 million.  The pre-tax losses on disposal associated with the sales of these businesses are included as losses from dispositions in discontinued operations on the accompanying consolidated statement of (loss)/income for the year ended December 31, 2005.

Included in discontinued operations for the years ended December 31, 2005, 2004, and 2003 is $11.7 million, $26.3 million, and $5 million, respectively, of intercompany revenues that are not eliminated in consolidation due to the separate presentation of discontinued operations.  At

December 31, 2005, NU does not expect that after the disposal it will have significant ongoing involvement or continuing cash flows with the entities presented in discontinued operations.

5.

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, the FERC, or by their respective state regulators.  On October 28, 2005 the SEC amended its June 30, 2004 order, granting authorization to allow NU, CL&P, WMECO, and Yankee Gas to incur total short-term borrowings up to a maximum of $700 million, $450 million, $200 million, and $150 million, respectively, through June 30, 2007.  The SEC also granted authorization for borrowing through the NU Money Pool (Pool) until June 30, 2007.  Although PUHCA was repealed on February 8, 2006, under FERC's transition rules, all of the existing orders under PUHCA relevant to FERC authority will continue to be in effect until December 31, 2007, except for those related to NU and Yankee Gas, which will have no borrowing limitations after February 8, 2006.  CL&P and WMECO will be subject to FERC jurisdiction as to issuing short-term debt after February 8, 2006 and must renew any short-term authority after the PUHCA order expires on December 31, 2007.  

PSNH is authorized by the NHPUC to incur short-term borrowings up to a maximum of $100 million.  As a result of this NHPUC authorization, PSNH is not required to obtain SEC or FERC approval for its short-term debt borrowings.

The charter of CL&P contains preferred stock provisions restricting the amount of unsecured debt that CL&P may incur.  In November of 2003, CL&P obtained authorization from its stockholders to issue unsecured indebtedness with a maturity of less than 10 years in excess of the 10 percent of total capitalization limitation in CL&P's charter, provided that all unsecured indebtedness would not exceed 20 percent of total capitalization for a ten-year period expiring in March of 2014.  On March 18, 2004, the SEC approved this change in CL&P's charter.  As of December 31, 2005, CL&P is permitted to incur $531.9 million of additional unsecured debt.

Utility Group Credit Agreement:  On December 9, 2005, CL&P, PSNH, WMECO, and Yankee Gas amended their 5-year unsecured revolving credit facility for $400 million by extending the expiration date by one year to November 6, 2010.  CL&P may draw up to $200 million, with PSNH, WMECO and Yankee Gas able to draw up to $100 million each, subject to the $400 million maximum borrowing limit.  This total commitment may be increased to $500 million, subject to approval, at the request of the borrower.  Under this facility, each company may borrow on a short-term basis or on a long-term basis, subject to regulatory approval.  At December 31, 2005, there were no borrowings outstanding under this facility.  At December 31, 2004, there were $80 million in borrowings under this credit facility.

NU Parent Credit Agreement:  On December 9, 2005, NU amended and restated its 5-year unsecured revolving credit and LOC facility of $500 million to a maximum borrowing limit of $700 million and extended the expiration date by one year to November 6, 2010.  The amended facility provides a total commitment of $700 million which is available for advances, subject to an LOC sub-limit.  Subject to the advances outstanding, LOCs may be issued in notional amounts up to $550 million for periods up to 364 days.  The agreement provides for LOCs to be issued in the name of NU or any of its subsidiaries.  This total commitment may be increased to $800 million, subject to approval, at the request of the borrower.  Under this facility, NU can borrow either on a short-term or a long-term basis.   At December 31, 2005 and 2004, there were $32 million and $100 million, respectively, in borrowings under this credit facil ity.  In addition, there were $253 million and $48.9 million in LOCs outstanding at December 31, 2005 and 2004, respectively.

Under these credit agreements, NU and its subsidiaries may borrow at variable rates plus an applicable margin based upon certain debt ratings, as rated by the higher of Standard and Poor's (S&P) or Moody's Investors Service (Moody's).  The weighted average interest rates on NU's notes payable to banks outstanding on December 31, 2005 and 2004, were 7.25 percent and 4.53 percent, respectively.

Under these credit agreements, NU and its subsidiaries must comply with certain financial and non-financial covenants, including but not limited to consolidated debt ratios.  The parties to the credit agreements currently are and expect to remain in compliance with these covenants.

Amounts outstanding under these credit facilities are classified as current liabilities as notes payable to banks on the accompanying consolidated balance sheets as management anticipates that all borrowings under these credit facilities will be outstanding for no more than 364 days at one time.

Other Credit Facility:  On June 30, 2005, Boulos, a subsidiary of NGS, renewed its $6 million line of credit.  This credit facility replaced a similar credit facility that expired on June 30, 2005 and unless extended, will expire on June 30, 2006.  This credit facility limits Boulos’ ability to pay dividends if borrowings are outstanding and limits access to the Pool for additional borrowings.  At December 31, 2005 and 2004, there were no borrowings under this credit facility.

6.

Derivative Instruments

Contracts that are derivatives and do not meet the definition of a cash flow hedge and are not elected as normal purchases or normal sales are 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.  The ineffective portion of contracts that meet the cash flow hedge requirements is recognized currently in earnings.  Derivative contracts designated as fair value hedges and the item they are hedging are both recorded at fair value with changes in fair value of both items recognized currently in earnings.  Derivative contracts that are elected and meet the requirements of a normal purchase or sale are recognized in revenues or expenses, as applicable, when the quantity of the contract is delivered.  

For the year ended December 31, 2005, $3.2 million, net of tax, was reclassified to expense from accumulated other comprehensive income in connection with the consummation of the underlying hedged transactions and recognized in earnings, and a $2.4 million, net of tax, was reclassified to expense from accumulated other comprehensive income related to the mark-to-market changes for wholesale contracts that NU Enterprises is in the process of exiting.  During 2005, new cash flow hedge transactions were entered into that hedge cash flows through 2010.  As a result of the

consummation of the above transactions and market value changes since January 1, 2005, and new transactions entered into during the year, accumulated other comprehensive income increased by $21.7 million, net of tax.  Accumulated other comprehensive income at December 31, 2005 was a positive $18.2 million, net of tax (increase to equity), relating to hedged transactions and it is estimated that a positive $19.6 million included in this net of tax balance will be reclassified as an increase to earnings in the next twelve months.  Cash flows from hedge contracts are reported in the same category as cash flows from the underlying hedged transaction.  

A negative pre-tax $3.4 million was recognized in earnings in 2005 for the ineffective portion of fair value hedges; at the same time a positive $1.2 million was recorded in earnings for the change in fair value of the hedged natural gas inventory.  The changes in the fair value of both the fair value hedges and the natural gas inventory being hedged totaling a negative pre-tax $2.2 million was recorded in fuel, purchased, and net interchange power on the accompanying consolidated statements of (loss)/income.  

The table below summarizes current and long-term derivative assets and liabilities at December 31, 2005.  At December 31, 2005, derivative assets and liabilities have been segregated between wholesale, retail, generation and hedging amounts.  As a result of the March 9, 2005 and November 7, 2005 combined decisions to exit these businesses, the fair value of these contracts may not represent amounts that will be realized.  

	At December 31, 2005
(Millions of Dollars)	Assets		Liabilities
	Current	Long- Term	Current	Long- Term	Net  Total
NU Enterprises:
Wholesale	$256.6	$103.5	$(369.3)	$(220.9)	$(230.1)
Retail	35.3	-	(18.3)	-	17.0
Generation	9.2	-	(5.1)	(15.5)	(11.4)
Hedging	19.7	12.9	(8.9)	0.4	24.1
Utility Group – Gas:
Non-trading	0.1	-	(0.4)	-	(0.3)
Utility Group – Electric:
Non-trading	82.6	308.6	(0.5)	(31.8)	358.9
NU Parent:
Hedging	-	-	-	(5.2)	(5.2)
Totals	$403.5	$425.0	$(402.5)	$(273.0)	$ 153.0

The business activities of NU Enterprises that result in the recognition of derivative assets include exposures to credit risk to energy marketing and trading counterparties.  At December 31, 2005, Select Energy had $437.2 million of derivative assets from wholesale, retail, generation, and hedging activities that are exposed to counterparty credit risk.  However, a significant portion of these assets is contracted with investment grade rated counterparties or collateralized with cash.  

The table below summarizes current and long-term derivative assets and liabilities at December 31, 2004.  Prior to the decision to exit the wholesale and retail marketing businesses and the competitive generation business, these current and long-term derivative assets and liabilities were classified as trading, non-trading and hedging derivative assets and liabilities.  For NU Enterprises, current and long-term derivative assets totaled $55.6 million and $31.7 million, respectively, while current and long-term derivative liabilities totaled $125.8 million and $15.9 million, respectively, at December 31, 2004.  

	At December 31, 2004
(Millions of Dollars)	Assets		Liabilities
	Current	Long- Term	Current	Long- Term	Net Total
NU Enterprises:
Trading	$49.6	$ 31.7	$ (46.2)	$ (5.5)	$ 29.6
Non-trading	1.5	-	(70.5)	(9.6)	(78.6)
Hedging	4.5	-	(9.1)	(0.8)	(5.4)
Utility Group – Gas:
Non-trading	0.2	-	(0.1)	-	0.1
Hedging	1.5	-	-	-	1.5
Utility Group – Electric
Non-trading	24.2	167.1	(4.4)	(42.8)	144.1
NU Parent:
Hedging	0.1	-	-	-	0.1
Totals	$81.6	$198.8	$(130.3)	$(58.7)	$ 91.4

The amounts above do not include option premiums paid, which are recorded as prepayments and amounted to $29.3 million related to wholesale activities at December 31, 2004.  These amounts also do not include option premiums received, which are recorded as other current liabilities and amounted to $27.1 million related to wholesale activities at December 31, 2004.  

NU Enterprises - Wholesale:  Certain electricity and natural gas derivative contracts are part of Select Energy's wholesale marketing business that the company is in the process of exiting.  These contracts also include other wholesale short-term and long-term electricity supply and sales contracts,

which include contracts to sell electricity to utilities under full requirements contracts and contracts to sell electricity to municipalities with terms up to eight remaining years.  The fair value of electricity contracts was determined by prices from external sources for years through 2009 and by models based on natural gas prices and a heat-rate conversion factor to electricity for subsequent periods.  The fair value of the natural gas contracts was primarily determined by prices provided by external sources and actively quoted markets.  In addition, to gather market intelligence and utilize this information in risk management activities for the wholesale marketing activities, Select Energy conducted limited energy trading activities in electricity, natural gas, and oil.  Select Energy manages open trading positions with strict policies that limit its exposure to market risk and require daily reporting to management of potential financial exposures.   

Derivatives used in wholesale activities are recorded at fair value and included in the consolidated balance sheets as derivative assets or liabilities. Changes in fair value are recorded as wholesale contract market changes, net on the accompanying consolidated statements of (loss)/income in the period of change.  The net fair value position of the wholesale portfolio at December 31, 2005 was a liability of $230.1 million.    

NU Enterprises - Retail:  Select Energy is in the process of exiting its retail business.  Select Energy generally acquires retail customers in smaller increments than it acquired wholesale customers, which while requiring careful sourcing, allows energy purchases to be acquired in smaller increments with lower risk.  However, fluctuations in prices, fuel costs, competitive conditions, regulations, weather, transmission costs, lack of market liquidity, plant outages and other factors can all impact the retail marketing business adversely from time to time. The retail sales contracts are generally executory contracts where revenues are recorded when the electricity or gas is delivered.  

From time to time, the retail marketing business enters into contracts that do not immediately meet the criteria for the normal election and accrual accounting.  Therefore, changes in fair value are required to be marked-to-market in earnings and included in the consolidated balance sheets as derivative assets or liabilities.  Changes in fair value are recognized in fuel, purchased and net interchange power in the consolidated statements of (loss)/income in the period of change.  The net fair value position of the retail portfolio at December 31, 2005 was an asset of $17 million.

Select Energy's retail portfolio also includes New York Mercantile Exchange (NYMEX) futures, financial swaps, and physical power transactions, the fair value of which is based on closing exchange prices; over-the-counter forwards, and financial swaps, the fair value of which is based on the mid-point of bid and ask market prices; bilateral contracts for the purchase or sale of electricity or natural gas, the fair value of which is determined using available information from external sources; and financial transmission rights and transmission congestion contracts, the fair value of which is based on historical settlement prices as well as external sources.

NU Enterprises - Generation: Select Energy is in the process of exiting these generation contracts.  These derivative contracts include generation asset-specific sales and forward sales of electricity at hub trading points.  The fair value of generation contracts was determined by prices from external sources for years through 2009 and by models based on natural gas prices and a heat-rate conversion factor to electricity for subsequent periods.  The fair value of the natural gas contracts was primarily determined by prices provided by external sources and actively quoted markets.  As a result of NU’s decision to exit the competitive generation business in the fourth quarter of 2005, Select Energy began to record all derivatives related to generation activities, with the exception of intercompany transactions, at fair value which are included in the consolidated balance sheets as derivative assets or liabilities as the comp any could no longer assert probability of physical delivery.  Changes in fair value are recognized in revenues in the consolidated statements of (loss)/income in the period of change for the contacts that were recorded at fair value beginning in the first quarter of 2005, while changes in fair value of contracts formerly accounted for on an accrual basis are recorded as wholesale contract market changes, net.  The net fair value position of the generation derivative contract portfolio at December 31, 2005 was a liability of $11.4 million.  

NU Enterprises - Hedging:  Select Energy utilizes derivative financial and commodity instruments, including futures and forward contracts, to reduce market risk associated with fluctuations in the price of electricity and natural gas purchased to meet firm sales and purchase commitments to certain retail customers.  Select Energy also utilizes derivatives, including price swap agreements, call and put option contracts, and futures and forward contracts to manage the market risk associated with a portion of its anticipated supply and delivery requirements. These derivatives have been designated as cash flow hedging instruments and are used to reduce the market risk associated with fluctuations in the price of electricity or natural gas.  A derivative that hedges exposure to the variable cash flows of a forecasted transaction (a cash flow hedge) is initially recorded at fair value with changes in fair value recorded in accumulated oth er comprehensive income.  Cash flow hedges impact net income when the forecasted transaction being hedged occurs, when hedge ineffectiveness is measured and recorded, when the forecasted transaction being hedged is no longer probable of occurring, or when there is accumulated other comprehensive loss and the hedge and the forecasted transaction being hedged are in a loss position on a combined basis.   

Select Energy maintains natural gas service agreements with certain retail customers to supply gas at fixed prices for terms extending through 2010. Select Energy has hedged its gas supply risk under these agreements through NYMEX futures contracts.  Under these contracts, which also extend through 2010, the purchase price of a specified quantity of gas is effectively fixed over the term of the gas service agreements.  At December 31, 2005 the NYMEX futures contracts had notional values of $210.5 million and were recorded at fair value as derivative assets totaling $8.2 million and derivative liabilities of $0.3 million.   

Select Energy also maintains various physical and financial instruments to hedge its electric and gas purchases and sales through April of 2008.  These instruments include forwards, futures and swaps.  These hedging contracts, which are valued at the mid-point of bid and ask market prices, were recorded as derivative assets of $24.4 million and derivative liabilities of $4.8 million at December 31, 2005.   

Select Energy hedges certain amounts of natural gas inventory with gas futures which are accounted for as fair value hedges.  Changes in the fair value of hedging instruments and natural gas inventory are recorded in earnings.  The change in fair value of the futures were included in derivative liabilities and amounted to $3.4 million at December 31, 2005.  The change in fair value of the hedged natural gas inventory was recorded as an increase to fuel, materials and supplies of $1.2 million at December 31, 2005.   

Utility Group - Gas - Non-Trading:  Yankee Gas’ non-trading derivatives consist of peaking supply arrangements to serve winter load obligations and firm retail sales contracts with options to curtail delivery.  These contracts are subject to fair value accounting because these contracts are derivatives that cannot be designated as normal purchases or sales, because of the optionality in the contract terms.  Non-trading derivatives at December 31, 2005 included assets of $0.1 million and liabilities of $0.4 million.  At December 31, 2004, non-trading derivatives included assets of $0.2 million and liabilities of $0.1 million.  

Utility Group - Electric - Non-Trading:  CL&P has two IPP contracts to purchase power that contain pricing provisions that are not clearly and closely related to the price of power and therefore do not qualify for the normal purchases and sales exception. The fair values of these IPP non-trading derivatives at December 31, 2005 include a derivative asset with a fair value of $391.2 million and a derivative liability with a fair value of $32.3 million.  An offsetting regulatory liability and an offsetting regulatory asset were recorded, as these contracts are part of the stranded costs, and management believes that these costs will continue to be recovered or refunded in rates.  At December 31, 2004, the fair values of these IPP non-trading derivatives included a derivative asset with a fair value of $191.3 million and a derivative liability with a fair value of $47.2 million.

NU Parent - Hedging:  In March of 2003, NU parent entered into a fixed to floating interest rate swap on its $263 million, 7.25 percent fixed rate note that matures on April 1, 2012.  As a matched-terms fair value hedge, the changes in fair value of the swap and the hedged debt instrument are recorded on the consolidated balance sheets but are equal and offsetting in the consolidated statements of (loss)/income.  The cumulative change in the fair value of the hedged debt of $5.2 million is included as a decrease to long-term debt on the consolidated balance sheets.  The hedge is recorded as a derivative liability of $5.2 million at December 31, 2005, and as a derivative asset of $0.1 million at December 31, 2004.  The resulting changes in interest payments made are recorded as adjustments to interest expense.

7.

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 (Pension Plan) covering substantially all regular NU employees.  Benefits are based on years of service and the employees’ highest eligible compensation during 60 consecutive months of employment.  NU uses a December 31^st measurement date for the Pension Plan. Pension (income)/expense attributable to earnings is as follows:

	For the Years Ended December 31,
(Millions of Dollars)	2005	2004	2003
Total pension expense/(income)	$54.2	$  8.0	$(31.8)
Amount capitalized as utility plant	(11.5)	2.6	15.4
Total pension expense/(income),   net of amounts capitalized	$42.7	$10.6	$(16.4)

Amounts above include pension curtailments and termination benefits expense of $11.7 million in 2005 and $2.1 million in 2004.

Pension Curtailments and Termination Benefits:  As a result of the decision to pursue a fundamentally different business strategy, and align the structure of the company to support this business strategy, NU recorded a $2.7 million pre-tax curtailment expense in 2005.  NU also accrued certain related termination benefits and recorded a $2.8 million pre-tax charge in 2005.

On December 15, 2005, the NU Board of Trustees approved a benefit for new non-union employees hired on and after January 1, 2006 to receive retirement benefits under a new 401(k) benefit rather than under the Pension Plan.  Non-union employees actively employed on December 31, 2005 will be given the choice in 2006 to elect to continue participation in the Pension Plan or instead receive a new employer contribution under the 401(k) Savings Plan effective January 1, 2007.  If the new benefit is elected, their accrued pension liability in the Pension Plan will be frozen as of December 31, 2006.  Non-union employees will make this election in the second half of 2006.  This decision resulted in the recording of an estimated pre-tax curtailment expense of $6.2 million in 2005, as a certain number of employees are expected to elect the new 401(k) benefit, resulting in a reduction in aggregate estimated future years of service under the Pension Plan.  Management estimated the amount of the curtailment expense associated with this change based upon actuarial calculations and certain assumptions, including the expected level of transfers to the new 401(k) benefit.

In April of 2004, as a result of litigation with nineteen former employees, NU was ordered by the court to modify its Pension Plan to include special retirement benefits for fifteen of these former employees retroactive to the dates of their retirement and provide increased future monthly benefit payments.  NU recorded $2.1 million in termination benefits related to this litigation in 2004 and made a lump sum benefit payment totaling $1.5 million to these former employees.

There were no curtailments or termination benefits in 2003 that impacted earnings.

Market-Related Value of Pension Plan Assets:  NU bases the actuarial determination of pension plan expense or income on a market-related valuation of assets, which reduces year-to-year volatility.  This market-related valuation calculation recognizes investment gains or losses over a four-year period from the year in which they occur.  Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the fair value of assets.  Since the market-related valuation calculation recognizes gains or losses over a four-year period, the future value of the market-related assets will be impacted as previously deferred gains or losses are recognized.

Postretirement Benefits Other Than Pensions:  NU’s subsidiaries also provide certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired employees (PBOP Plan).  These benefits are available for employees retiring from NU who have

met specified service requirements.  For current employees and certain retirees, the total benefit is limited to two times the 1993 per retiree health care cost.  These costs are charged to expense over the estimated work life of the employee.  NU uses a December 31^st measurement date for the PBOP Plan.

NU annually funds postretirement costs through external trusts with amounts that have been and will continue to be recovered in rates and which also are tax deductible.  Currently, there are no pending regulatory actions regarding postretirement benefit costs and there are no postretirement benefit costs that are deferred as regulatory assets.

Impact of New Medicare Changes on PBOP:  On December 8, 2003, the President signed into law a bill that expands Medicare, primarily by adding a prescription drug benefit starting in 2006 for Medicare-eligible retirees as well as a federal subsidy to plan sponsors of retiree health care benefit plans who provide a prescription drug benefit at least actuarially equivalent to the new Medicare benefit.

Based on the current PBOP Plan provisions, NU qualifies for this federal subsidy because the actuarial value of NU’s PBOP Plan exceeds the threshold required for the subsidy.  The Medicare changes decreased the PBOP benefit obligation by $27 million.  The total $27 million decrease is currently being amortized as a reduction to PBOP expense over approximately 13 years.  For the years ended December 31, 2005 and 2004, this reduction in PBOP expense totaled approximately $3.6 million, including amortization of the actuarial gain of $2 million and a reduction in interest cost and service cost based on a lower PBOP benefit obligation of $1.6 million.  

PBOP Curtailments and Termination Benefits:  NU recorded an estimated $3.7 million pre-tax curtailment expense at December 31, 2005 relating to NU's change in business strategy.  NU also accrued a $0.5 million pre-tax termination benefit at December 31, 2005 relating to certain benefits provided under the terms of the PBOP Plan.  There were no curtailments or termination benefits in 2004 or 2003.

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)	2005	2004	2005	2004
Change in benefit obligation
Benefit obligation at beginning of year	$(2,133.2)	$(1,941.3)	$(468.3)	$(405.0)
Service cost	(48.7)	(40.7)	(8.0)	(6.0)
Interest cost	(125.6)	(118.9)	(25.2)	(25.3)
Actuarial loss	(148.7)	(136.7)	(32.7)	(68.7)
Benefits paid - excluding lump sum payments	109.1	105.0	38.9	36.7
Benefits paid - lump sum payments	0.1	1.5	-	-
Curtailment/impact of plan changes	63.6	-	2.0	-
Termination benefits	(2.8)	(2.1)	(0.5)	-
Benefit obligation at end of year	$(2,286.2)	$(2,133.2)	$(493.8)	$(468.3)
Change in plan assets
Fair value of plan assets at beginning of year	$ 2,075.5	$ 1,945.1	$  199.8	$  178.0
Actual return on plan assets	156.3	236.9	12.1	16.8
Employer contribution	-	-	49.9	41.7
Benefits paid - excluding lump sum payments	(109.1)	(105.0)	(38.9)	(36.7)
Benefits paid - lump sum payments	(0.1)	(1.5)	-	-
Fair value of plan assets at end of year	$ 2,122.6	$ 2,075.5	$  222.9	$  199.8
Funded status at December 31st	$  (163.6)	$    (57.7)	$(270.9)	$(268.5)
Unrecognized transition obligation	0.5	0.4	78.6	94.8
Unrecognized prior service cost	40.5	56.3	(4.1)	(5.2)
Unrecognized net loss	421.1	353.7	179.9	166.5
Prepaid/(accrued) benefit cost	$   298.5	$    352.7	$  (16.5)	$  (12.4)

The $63.6 million reduction in the plan's obligation that is included in the curtailment/impact of plan changes relates to the reduction in the future years of service expected to be rendered by plan participants.  This reduction is the result of the transition of employees into the new 401(k) benefit and the company's decision to pursue a fundamentally different business strategy, and align the structure of the company to support this business strategy.  This overall reduction in plan obligation serves to reduce the previously unrecognized actuarial losses.

The company amortizes its unrecognized transition obligation over the remaining service lives of its employees as calculated on an individual operating company basis.  The company amortizes the unrecognized prior service cost and unrecognized net loss over the remaining service lives of its employees as calculated on a company-wide basis.

The accumulated benefit obligation for the Pension Plan was $2.061 billion and $1.850 billion at December 31, 2005 and 2004, respectively.

The following actuarial assumptions were used in calculating the plans’ year end funded status:

	At December 31,
	Pension Benefits				Postretirement Benefits
Balance Sheets	2005		2004		2005		2004
Discount rate	5.80	%	6.00	%	5.65	%	5.50	%
Compensation/progression rate	4.00	%	4.00	%	N/A		N/A
Health care cost trend rate	N/A		N/A		7.00	%	8.00	%

The components of net periodic expense/(income) are as follows:

	For the Years Ended December 31,
	Pension Benefits			Postretirement Benefits
(Millions of Dollars)	2005	2004	2003	2005	2004	2003
Service cost	$ 48.7	$  40.7	$  35.1	$ 8.0	$   6.0	$   5.3
Interest cost	125.6	118.9	117.0	25.2	25.3	26.8
Expected return on plan assets	(172.0)	(175.1)	(182.5)	(12.3)	(12.5)	(14.9)
Amortization of unrecognized net transition   (asset)/obligation	(0.3)	(1.5)	(1.5)	11.8	11.9	11.9
Amortization of prior service cost	7.1	7.2	7.2	(0.4)	(0.4)	(0.4)
Amortization of actuarial loss/(gain)	33.4	15.7	(7.1)	-	-	-
Other amortization, net	-	-	-	17.5	11.4	6.4
Net periodic expense/(income) – before  curtailments and termination   benefits	42.5	5.9	(31.8)	49.8	41.7	35.1
Curtailment expense	8.9	-	-	3.7	-	-
Termination benefits expense	2.8	2.1	-	0.5	-	-
Total curtailments and termination benefits	11.7	2.1	-	4.2	-	-
Total - net periodic expense/(income)	$ 54.2	$   8.0	$(31.8)	$54.0	$  41.7	$  35.1

For calculating pension and postretirement benefit expense and income amounts, the following assumptions were used:

	For the Years Ended December 31,
Statements of Income	Pension Benefits						Postretirement Benefits
	2005		2004		2003		2005		2004		2003
Discount rate	6.00	%	6.25	%	6.75	%	5.50	%	6.25	%	6.75	%
Expected long-term rate of return	8.75	%	8.75	%	8.75	%	N/A		N/A		N/A
Compensation/progression rate	4.00	%	3.75	%	4.00	%	N/A		N/A		N/A
Expected long-term rate of return -
Health assets, net of tax	N/A		N/A		N/A		6.85	%	6.85	%	6.85	%
Life assets and non-taxable     health assets	N/A		N/A		N/A		8.75	%	8.75	%	8.75	%

The following table represents the PBOP assumed health care cost trend rate for the next year and the assumed ultimate trend rate:

	Year Following December 31,
	2005		2004
Health care cost trend rate   assumed for next year	10.00	%	7.00	%
Rate to which health care   cost trend rate is assumed to   decline (the ultimate trend rate)	5.00	%	5.00	%
Year that the rate reaches   the ultimate trend rate	2011		2007

At December 31, 2004, the health care cost trend assumption was assumed to decrease by one percentage point each year through 2007.  For December 31, 2005 disclosure purposes, the health care cost trend assumption was reset for 2006 at 10 percent, decreasing one percentage point per year to an ultimate rate of 5 percent in 2011.  

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:

(Millions of Dollars)	One Percentage Point Increase	One Percentage Point Decrease
Effect on total service and   interest cost components	$  0.9	$  (0.8)
Effect on postretirement   benefit obligation	$18.0	$(15.6)

NU’s investment strategy for its Pension Plan and PBOP Plan is to maximize the long-term rate of return on those plans’ assets within an acceptable level of risk.  The investment strategy establishes target allocations, which are routinely reviewed and periodically rebalanced.  NU’s expected long-term rates of return on Pension Plan assets and PBOP Plan assets are based on these target asset allocation assumptions and related expected long-term rates of return.  In developing its expected long-term rate of return assumptions for the Pension Plan and the PBOP Plan, NU also evaluated input from actuaries and consultants, as well as long-term inflation assumptions and NU’s historical 20-year compounded return of approximately 11 percent.  The Pension Plan’s and PBOP Plan’s target asset allocation assumptions and expected long-term rate of return assumptions by asset category are as follows:

	At December 31,
	Pension Benefits		Postretirement Benefits
	2005 and 2004		2005 and 2004
Asset Category	Target Asset Allocation	Assumed Rate of Return	Target Asset Allocation	Assumed Rate of Return
Equity securities:
United States	45%	9.25%	55%	9.25%
Non-United States	14%	9.25%	11%	9.25%
Emerging markets	3%	10.25%	2%	10.25%
Private	8%	14.25%	-	-
Debt Securities:
Fixed income	20%	5.50%	27%	5.50%
High yield fixed income	5%	7.50%	5%	7.50%
Real estate	5%	7.50%	-	-

The actual asset allocations at December 31, 2005 and 2004 approximated these target asset allocations.  The plans’ actual weighted-average asset allocations by asset category are as follows:  

	At December 31,
	Pension Benefits		Postretirement Benefits
Asset Category	2005	2004	2005	2004
Equity securities:
United States	46%	47%	54%	55%
Non-United States	16%	17%	14%	14%
Emerging markets	4%	3%	1%	1%
Private	5%	4%	-	-
Debt Securities:
Fixed income	19%	19%	29%	28%
High yield fixed income	5%	5%	2%	2%
Real estate	5%	5%	-	-
Totals	100%	100%	100%	100%

Estimated Future Benefit Payments:  The following benefit payments, which reflect expected future service, are expected to be paid for the Pension and PBOP Plans:

(Millions of Dollars)
Year	Pension Benefits	Postretirement Benefits	Government Subsidy
2006	$111.1	$  44.1	$ 4.3
2007	114.2	45.0	4.6
2008	117.3	44.7	4.9
2009	120.6	44.4	5.2
2010	124.3	44.2	5.5
2011-2015	690.4	217.0	33.1

Government subsidy represents amounts expected to be received from the federal government for the new Medicare prescription drug benefit under the PBOP Plan.

Contributions:  NU does not expect to make any contributions to the Pension Plan in 2006 and expects to make $49.5 million in contributions to the PBOP Plan in 2006.  

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.

Postretirement health plan assets for non-union employees are subject to federal income taxes.

B.

401(k) Savings Plan

NU maintains a 401(k) Savings Plan for substantially all NU employees.  This savings plan provides for employee contributions up to specified limits.  NU matches employee contributions up to a maximum of three percent of eligible compensation with one percent cash and two percent NU common shares.  The 401(k) matching contributions of cash and NU common shares made by NU were $10.7 million in 2005, $10.5 million in 2004 and $9.9 million in 2003.

C.

Employee Stock Ownership Plan

NU maintains an Employee Stock Ownership Plan (ESOP) for purposes of allocating shares to employees participating in 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 (ESOP Notes) 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 to NU on the ESOP Notes at the same rate that ESOP shares are allocated to employees.  NU makes annual contributions to the ESOP trust equal to the ESOP’s debt service, less dividends received by the ESOP.  NU’s contributions to the ESOP trust totaled $11.2 million in 2005, $12 million in 2004 and $14.7 million in 2003.  Interest expense on the unsecured notes was $3.3 million, $5.7 million and $7.6 million in 2005, 2004 and 2003, respectively.  For the years ended December 31, 2005, 2004 and 2003, NU recognized $7.7 million, $7.3 million and $6.9 million, respectively, of expense related to the ESOP, excluding the interest expense on the unsecured notes.

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 2004, NU paid a $0.15 per share quarterly dividend.  During the third quarter of 2004 through the second quarter of 2005, NU paid a $0.1625 per share quarterly dividend.  NU paid a $0.175 per share dividend during the third and fourth quarters of 2005.

In 2005 and 2004, the ESOP trust issued 590,173 and 567,907 of NU common shares, respectively, to satisfy 401(k) Savings Plan obligations to employees.  At December 31, 2005 and 2004, total allocated ESOP shares were 8,773,884 and 8,183,711, respectively, and total unallocated ESOP shares were 2,026,301 and 2,616,474, respectively.  The fair market value of the unallocated ESOP shares at December 31, 2005 and 2004, was $39.9 and $49.3 million, respectively.

D.

Equity-Based Compensation

Impact of SFAS No. 123R:  See Note 1C, "Summary of Significant Accounting Policies - Accounting Standards Issued But Not Yet Adopted," for information on the implementation of SFAS No. 123R.

Employee Share Purchase Plan (ESPP):  NU maintains an ESPP for all eligible employees.  Under the ESPP, NU common shares were purchased at six-month intervals at 85 percent of the lower of the price on the first or last day of each six-month period.  Employees may purchase shares having a value not exceeding 25 percent of their compensation as of the beginning of the purchase period.  During 2005 and 2004, employees purchased 209,184 and 194,838 shares, respectively, at discounted prices of $15.85 and $15.90 in 2005 and $14.17 and $15.90 in 2004. At December 31, 2005 and 2004, 1,181,219 shares and 1,390,403 shares remained registered for future issuance under the ESPP, respectively.

Effective February 1, 2006, the ESPP was amended to change the discount rate to five percent of the market price and the pricing date was changed to the last day of the purchase period.  As a result, the ESPP will qualify as a non-compensatory plan under SFAS No. 123R, which is effective on January 1, 2006 for NU.  This amendment may also reduce the number of shares purchased under the ESPP.  

Incentive Plans:  Under the Incentive Plan, NU is authorized to grant various types of awards, including restricted stock, performance units, restricted stock units, and stock options to eligible employees and board members.  The number of shares that may be utilized for grants and awards during a given calendar year may not exceed the aggregate of one percent of the total number of NU common shares outstanding as of the first day of that calendar year and the shares not utilized in previous years.  At December 31, 2005 and 2004, NU had 906,154 and 1,361,528 shares of common stock, respectively, registered for issuance under the Incentive Plan.

Restricted Stock and Restricted Stock Units:  NU granted 304,724 restricted stock units during 2005 and 25,000 restricted shares and 382,395 restricted stock units during 2004.  The restricted stock units granted had a fair value of $5.8 million and $7.4 million in 2005 and 2004, respectively.  The restricted stock granted in 2004 had a fair value of $0.4 million.  NU currently accounts for restricted stock and restricted stock units in accordance with APB No. 25 and amortizes the intrinsic value of the stock at the award date over the related service period using the straight-line method.  Awards granted in 2005, 2004, and 2003 were subject to three and four-year graded vesting periods.  During 2005, 2004 and 2003, $4.3 million, $3.8 million and $2 million, respectively, was expensed related to restricted stock and restricted stock units.

Performance Units:  Under the Incentive Plan, NU also granted 38,996, 30,122, and 35,303 performance units during 2005, 2004 and 2003, respectively.  The performance units are valued at $100 at target and vest ratably over three years and will be paid in cash at the end of the vesting period.  NU records a liability for the performance units based on the achievement of the performance unit goals. A liability of $2.9 million and $3.2 million, which is included in other current liabilities on the accompanying consolidated balance sheets, was recorded at December 31, 2005 and

2004, respectively, for these performance units.  During 2005, 2004 and 2003, $0.3 million, $1.7 million and $0.2 million, respectively, was recorded as an expense related to these performance units.  

Stock Options:  Prior to 2003, NU granted stock options to certain employees.  The exercise price of stock options, as set at the time of grant, was equal to the fair market value per share at the date of grant, and therefore no equity-based compensation cost was reflected in net income.  A summary of stock option transactions is as follows:

		Exercise Price Per Share
	Options	Range			Weighted Average
Outstanding - December 31, 2002	3,837,309	$  9.6250	-	$22.2500	$16.8738
Exercised	(562,982)	$  9.6250	-	$19.5000	$14.6223
Forfeited and cancelled	(151,005)	$14.9375	-	$21.0300	$19.0227
Outstanding – December 31, 2003	3,123,322	$  9.6250	-	$22.2500	$17.1270
Exercised	(612,666)	$  9.6250	-	$19.5000	$12.3181
Forfeited and cancelled	(516,914)	$16.5500	-	$19.5000	$16.6139
Outstanding - December 31, 2004	1,993,742	$14.9375	-	$22.2500	$18.7370
Exercised	(368,192)	$14.9375	-	$20.0600	$12.7262
Forfeited and cancelled	(503,009)	$18.4375	-	$21.0300	$18.1703
Outstanding - December 31, 2005	1,122,541	$14.9375	-	$22.2500	$18.4484
Exercisable - December 31, 2003	2,027,413	$  9.6250	-	$22.2500	$16.6969
Exercisable - December 31, 2004	1,877,595	$14.9375	-	$22.2500	$18.7778
Exercisable - December 31, 2005	1,122,541	$14.9375	-	$22.2500	$18.4484

For certain options that were granted in 2002, the vesting schedule for these options is ratably over three years from the date of grant.  Additionally, certain options granted in 2002 vest 50 percent at the date of grant and 50 percent one year from the date of grant, while other options granted in 2002 vest 100 percent after five years.

The fair value of each stock option grant has been estimated on the date of grant using the Black-Scholes option pricing model and is used to calculate the pro forma net (loss)/income and EPS over the service period, as disclosed in Note 1N, "Summary of Significant Accounting Policies - Equity-Based Compensation," to the consolidated financial statements.  No stock options were granted during 2005, 2004 or 2003.  The weighted average remaining contractual lives for the options outstanding at December 31, 2005 is 4.89 years.

For information regarding the adoption of SFAS No. 123R on January 1, 2006, equity-based compensation, see Note 1C, "Summary of Significant Accounting Policies – Accounting Standards Issued But Not Yet Adopted," to the consolidated financial statements.

E.

Supplemental Executive Retirement and Other Plans

NU has maintained a 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 $26 million and $24.2 million at December 31, 2005 and 2004, respectively, which is included in deferred credits and other liabilities - other on the accompanying consolidated balance sheets, represents NU’s actuarially-determined obligation under the SERP.  During 2005, 2004 and 2003, $3.7 million, $4 million, and $3.9 million, respectively, was expensed related to the SERP.

The SERP is the only NU retirement plan for which a minimum pension liability has been recorded. Recording this minimum pension liability resulted in a negative $0.4 million in accumulated other comprehensive income at December 31, 2005.

NU maintains a plan for retirement and other benefits for certain current and past company officers. The actuarially-determined liability for this plan which is included in deferred credits and other liabilities – other on the accompanying consolidated balance sheets, was $37.4 million and $36.7 million at December 31, 2005 and 2004, respectively.  During 2005, 2004 and 2003, $4.5 million, $4.5 million and $6.3 million, respectively, was expensed related to this plan.

For information regarding SERP investments that are used to fund the SERP liability, see Note 11, "Marketable Securities," to the consolidated financial statements.

F.

Severance Benefits

The restructuring charges and liabilities described in Note 3, "Restructuring and Impairment Charges," do not include severance costs related to employee terminations as a result of the decision to pursue a fundamentally different business strategy and align the structure of the company to support this business strategy.  These charges, totaling $16.9 million were recorded as other operating expenses on the accompanying consolidated statement of (loss)/income for the year ended December 31, 2005.  

8.

Goodwill and Other Intangible Assets

SFAS No. 142, "Goodwill and Other Intangible Assets," requires that goodwill and intangible assets deemed to have indefinite useful lives be reviewed for impairment at least annually by applying a fair value-based test.  NU uses October 1^st as the annual goodwill impairment testing date.  Goodwill impairment is deemed to exist if the net book value of a reporting unit exceeds its estimated fair value and if the implied fair value of goodwill based on the estimated fair value of the reporting unit is less than the carrying amount.

NU’s reporting units that maintained goodwill are generally consistent with the operating segments underlying the reportable segments identified in Note 17, "Segment Information," to the consolidated financial statements.  Consistent with the way management reviews the operating results of its reporting units, NU's reporting unit under the NU Enterprises reportable segment that maintains goodwill is the merchant energy reporting unit.  The merchant energy reporting unit is comprised of the operations of Select Energy, NGC and the generation operations of HWP and NGS.  The other reporting unit that maintains goodwill is the Yankee Gas reporting unit, which was classified under the Utility Group - gas reportable segment. The goodwill recorded related to the acquisition of Yankee Gas is not being recovered from the customers of Yankee Gas.  A summary of NU's goodwill balances at December 31, 2005 and 2004 by reportable segment and reporting units is as follows:  

	At December 31,
(Millions of Dollars)	2005	2004
Utility Group - Gas:
Yankee Gas	$287.6	$287.6
NU Enterprises:
Merchant Energy	-	3.2
Energy Services	-	29.1
Totals	$287.6	$319.9

As a result of NU’s 2005 announcements to exit the competitive wholesale and retail marketing businesses, the competitive generation business and the energy services businesses, certain goodwill balances and intangible assets were deemed to be impaired.  The goodwill balances in the NU Enterprises merchant energy and energy services businesses were determined to be impaired in their entirety, and $3.2 million and $29.1 million, respectively, in write-offs were recorded.  

The retail marketing business had an exclusivity agreement with an unamortized balance of $7.2 million and a customer list asset with an unamortized balance of $2 million that were also deemed to be impaired and were written off.Additionally, the energy services businesses intangible assets not subject to amortization were also impaired, and an $8.5 million pre-tax write-off was recorded, while an additional pre-tax $0.7 million of other intangible assets were also impaired.  These charges related to continuing operations are included in restructuring and impairment charges on the accompanying consolidated statements of (loss)/income and in the NU Enterprises reportable segment in Note 17, "Segment Information," to the consolidated financial statements, with the remainder included in discontinued operations.

NU recorded amortization expenses of $1.7 million, $3.6 million and $3.7 million for the years ended December 31, 2005, 2004 and 2003, respectively, related to these intangible assets prior to these write-offs.  

NU completed its impairment analysis of the Yankee Gas goodwill balance as of October 1, 2005, and has determined that no impairment exists.  In completing this analysis, the fair value of the reporting unit was estimated using both discounted cash flow methodologies and an analysis of comparable companies or transactions.

At December 31, 2005, NU Enterprises' remaining intangible assets totaled $0.1 million and relate to the energy services businesses which are expected to be sold.  

9.

Commitments and Contingencies

A.

Regulatory Developments and Rate Matters

Connecticut:

CTA and SBC Reconciliation: The CTA allows CL&P to recover stranded costs, such as securitization costs associated with the rate reduction bonds, amortization of regulatory assets, and IPP over market costs, while the SBC allows CL&P to recover certain regulatory and energy public policy costs, such as public education outreach costs, hardship protection costs, transition period property taxes, and displaced worker protection costs.

A final decision in the 2004 CTA and SBC docket was issued on December 19, 2005 by the DPUC.  That decision ordered a refund to customers of $100.8 million over the twelve-month period beginning with January 2006 consumption.  In a subsequent decision in CL&P’s docket to establish the 2006 transitional standard offer (TSO) rates dated December 28, 2005, the DPUC ordered CL&P to issue a revised CTA refund of $108 million over the twelve-month period beginning with January 2006 consumption and an additional CTA refund of $40 million for the months of January, February and March of 2006.  

In the 2001 CTA and SBC reconciliation filing, and subsequently in a September 10, 2002 petition to reopen related proceedings, CL&P requested that a deferred intercompany tax liability associated with the intercompany sale of generation assets be excluded from the calculation of CTA revenue requirements. This liability is currently included as a reduction in the calculation of CTA revenue requirements.  On September 10, 2003, the DPUC issued a final decision denying CL&P’s request, and on October 24, 2003, CL&P appealed the DPUC’s final decision to the Connecticut Superior Court.  The appeal has been fully briefed and argued.  If CL&P’s request is granted and upheld through these court proceedings, there would be additional amounts due to CL&P from its customers.  The amount due is contingent upon the findings of the court.  However, management believes that CL&P's pre-tax earnings would in crease by a minimum of $15 million in 2006 if CL&P's position is adopted by the court.  

Purchased Gas Adjustment:  On September 9, 2005 the DPUC issued a draft decision regarding Yankee Gas Purchased Gas Adjustment (PGA) clause charges for the period of September 1, 2003 through August 31, 2004.  The draft decision disallowed approximately $9 million in previously recovered PGA revenues associated with two separate Yankee Gas unbilled sales and revenue adjustments.  At the request of Yankee Gas, the DPUC

reopened the PGA hearings on September 20, 2005 and requested that Yankee Gas file supplemental information regarding the two adjustments.  Yankee Gas complied with this request.  The remaining schedule for the proceeding has not yet been established.  If upheld, this disallowance would result in a $9 million pre-tax write-off.  Management believes the unbilled sales and revenue adjustments and resultant charges to customers through the PGA clause were appropriate.  Based on the facts of the case and the supplemental information provided to the DPUC, management believes the appropriateness of the PGA charges to customers for the time period under review will be approved.  

New Hampshire:

SCRC Reconciliation Filing:  The SCRC allows PSNH to recover its stranded costs.  On an annual basis, PSNH files with the NHPUC a SCRC reconciliation filing for the preceding calendar year.  This filing includes the reconciliation of stranded cost revenues and costs and Transition Energy Service Rate and Default Energy Service Rate, collectively referred to as Energy Service Rate (ES) revenues and costs.  The NHPUC reviews the filing, including a prudence review of the operations within PSNH's generation business segment.  The cumulative deferral of SCRC revenues in excess of costs was $303.3 million at December 31, 2005.  This cumulative deferral will decrease the amount of non-securitized stranded costs to be recovered from PSNH's customers in the future from $368 million to $64.7 million.

The 2004 SCRC reconciliation filing was filed with the NHPUC on May 2, 2005.  In October of 2005, PSNH, the NHPUC staff and the New Hampshire Office of Consumer Advocate (OCA) reached a settlement agreement in this case.  The major provisions of this settlement agreement include the following: 1) PSNH will be allowed to recover its 2004 ES costs and stranded costs without disallowances, 2) PSNH will be allowed to include its cumulative unbilled revenues in its ES and stranded cost reconciliations and 3) the NHPUC will defer any action regarding PSNH’s coal supply and transportation procedures until it completes a review using an outside expert.  The NHPUC issued its order on December 22, 2005, approving the settlement agreement as filed.  While management believes its coal procurement and transportation policies and procedures are prudent and consistent with industry practice, it is unable to determine the impact, if any, of the expected NHPUC review on PSNH's net income or financial position.  

Litigation with IPPs:  Two wood-fired IPPs that sell their output to PSNH under long-term rate orders issued by the NHPUC brought suit against PSNH in state superior court.  The IPPs and PSNH dispute the end dates of the above-market long-term rates set forth in the respective rate orders.  Subsequent to the IPP's court filing, PSNH petitioned the NHPUC to decide this matter, and requested that the court stay its proceeding pending the NHPUC's decision.  By court order dated October 20, 2005, the court granted PSNH's motion to stay indicating that the NHPUC had primary jurisdiction over this matter.  

On November 11, 2005, the IPPs filed motions with the NHPUC seeking to disqualify two of the three NHPUC commissioners from participating in this proceeding.  As a result, the NHPUC chair excused himself from participating in this proceeding.  On December 7, 2005, the IPPs then filed an interlocutory appeal with the New Hampshire Supreme Court (Supreme Court) on the basis that the forum for resolving this dispute is in state superior court.  On December 27, 2005, PSNH and the New Hampshire Attorney General’s Office (representing the NHPUC) each filed motions for summary disposition with the Supreme Court.  On February 7, 2006, the Supreme Court declined to accept the IPP's interlocutory appeal.  As a result, the matter will return to the NHPUC for decision.  PSNH recovers the over market costs of IPP contracts through the SCRC.

Environmental Legislation:  The New Hampshire legislature is considering a bill in its 2006 legislative session that would place strict limitations on the level of mercury that PSNH’s existing generation plants can emit.  Legislation was first proposed in the 2005 session and passed by the New Hampshire senate in 2005 which would require PSNH to achieve fixed annual caps as early as 2009.  The bill was subsequently defeated by the New Hampshire House of Representatives early in 2006.  The legislature will now take up a new bill that requires PSNH to reduce power plant mercury emissions by at least 80 percent by 2013 while providing incentives for early reductions.  Management has been reviewing the proposed legislation.  PSNH's primary long-term alternative is to install wet scrubber equipment at its Merrimack Station at a cost of approximately $250 million.  PSNH's other alternatives include the use of carb on injection pollution control equipment, reducing operating capacity of its plants and possible retirement or repowering of one or more of its generating units.  While state law and PSNH's restructuring agreement provide for the recovery of its generation costs, including the cost to comply with state environmental regulations, at this time management is unable to determine the impact of any potential new legislation on PSNH's net income or financial position.

Massachusetts:

Transition Cost Reconciliation:  On March 31, 2005, WMECO filed its 2004 transition cost reconciliation with the Massachusetts Department of Telecommunications and Energy (DTE).  The DTE has combined the 2003 transition cost reconciliation filing, standard offer service and default service reconciliation, the transmission cost adjustment filing, and the 2004 transition cost reconciliation filing into a single proceeding.  The timing of a decision in the combined proceeding is uncertain, but management does not expect the outcome to have a material adverse impact on WMECO's net income or financial position.

B.

Environmental Matters

General:  NU is subject to environmental laws and regulations intended to mitigate or remove the effect of past operations and improve or maintain the quality of the environment.  These laws and regulations require the removal or the remedy of the effect on the environment of the disposal or release of certain specified hazardous substances at current and former operating sites.  As such, NU has an active environmental auditing and training program and believes that it is substantially in compliance with all enacted laws and regulations.

Environmental reserves are accrued using a probabilistic model approach when assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated.  The probabilistic model approach estimates the liability based on the most likely action plan from a variety of available remediation options, including, no action is required or several different remedies ranging from establishing institutional controls to full site remediation and monitoring.

These estimates are subjective in nature as they take into consideration several different remediation options at each specific site.  The reliability and precision of these estimates can be affected by several factors including new information concerning either the level of contamination at the site, recently enacted laws and regulations or a change in cost estimates due to certain economic factors.

The amounts recorded as environmental liabilities on the consolidated balance sheets represent management’s best estimate of the liability for environmental costs and takes into consideration site assessment and remediation costs.  Based on currently available information for estimated site assessment and remediation costs at December 31, 2005 and 2004, NU had $30.7 million and $38.7 million, respectively, recorded as environmental reserves.  A reconciliation of the activity in these reserves at December 31, 2005 and 2004 is as follows:

	For the Years Ended December 31,
(Millions of Dollars)	2005	2004
Balance at beginning of year	$38.7	$40.8
Additions and adjustments	4.2	6.4
Payments	(12.2)	(8.5)
Balance at end of year	$30.7	$38.7

Of the 52 sites NU has currently included in the environmental reserve, 26 sites are in the remediation or long-term monitoring phase, 20 sites have had some level of site assessments completed and the remaining 6 sites are in the preliminary stages of site assessment.

For 9 sites that are included in the company’s liability for environmental costs, the information known and nature of the remediation options at those sites allows for an estimate of the range of losses to be made.  These sites primarily relate to manufactured gas plant (MGP) sites. At December 31, 2005, $7 million has been accrued as a liability for these sites, which represents management’s best estimate of the liability for environmental costs.  This amount differs from an estimated range of loss from $0.3 million to $23.4 million as management utilizes the probabilistic model approach to make its estimate of the liability for environmental costs.  For the 43 remaining sites for which an estimate is based on the probabilistic model approach, determining an estimated range of loss is not possible.

These liabilities are estimated on an undiscounted basis and do not assume that any amounts are recoverable from insurance companies or other third parties.  The environmental reserve includes sites at different stages of discovery and remediation and does not include any unasserted claims.

At December 31, 2005, there are 11 sites for which there are unasserted claims; however, any related remediation costs are not probable or estimable at this time.  NU’s environmental liability also takes into account recurring costs of managing hazardous substances and pollutants, mandated expenditures to remediate previously contaminated sites and any other infrequent and non-recurring clean up costs.

It is possible that new information or future developments could require a reassessment of the potential exposure to related environmental matters.  As this information becomes available, management will continue to assess the potential exposure and adjust the reserves accordingly.

MGP Sites:  MGP sites comprise the largest portion of NU’s environmental liability. MGPs are sites that manufactured gas from coal which produced certain byproducts that may pose a risk to human health and the environment. At December 31, 2005 and 2004, $25.3 million and $33.2 million, respectively, represents amounts for the site assessment and remediation of MGPs. At December 31, 2005 and 2004, the five largest MGP sites comprise approximately 64 percent and 58 percent, respectively, of the total MGP environmental liability.

On January 19, 2005, the DPUC issued a final decision approving the sale proceeding of a former MGP site that was held for sale at December 31, 2004.  The final decision approved the price of $24 million for the sale of the land and also approved the deferral of the gain in the amount of $14 million ($8.4 million net of tax).  At December 31, 2004, NU had $7.9 million related to remediation efforts at the property and other sale costs recorded in other deferred debits and other assets – other on the accompanying consolidated balance sheets.  During 2005, the former MGP site was sold to an independent third party.  

CERCLA Matters:  The Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA) and its amendments or state equivalents impose joint and several strict liabilities, regardless of fault, upon generators of hazardous substances resulting in removal and remediation costs and environmental damages.  Liabilities under these laws can be material and in some instances may be imposed without regard to fault or for past acts that may have been lawful at the time they occurred.  NU has four superfund sites under CERCLA for which it has been notified that it is a potentially responsible party (PRP).  For sites where there are other PRPs and NU’s subsidiaries are not managing the site assessment and remediation, the liability accrued represents NU’s estimate of what it will pay to settle its obligations with respect to the site.

It is possible that new information or future developments could require a reassessment of the potential exposure to related environmental matters.  As this information becomes available management will continue to assess the potential exposure and adjust the reserves accordingly.  

Rate Recovery:  PSNH and Yankee Gas have rate recovery mechanisms for environmental costs.  CL&P recovers a certain level of environmental costs currently in rates but does not have an environmental cost recovery tracking mechanism.  Accordingly, changes in CL&P’s environmental reserves impact CL&P’s earnings.  WMECO does not have a regulatory mechanism to recover environmental costs from its customers, and changes in WMECO’s environmental reserves also impact WMECO’s earnings.

C.

Spent Nuclear Fuel Disposal Costs

Under the Nuclear Waste Policy Act of 1982 (the Act), 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) for CL&P and WMECO, 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, 2005 and 2004, fees due to the DOE for the disposal of Prior Period Fuel were $267.8 million and $259.7 million, respectively, including interest costs of $185.7 million and $177.6 million, respectively.

During 2004, WMECO established a trust, which holds marketable securities to fund amounts due to the DOE for the disposal of WMECO’s Prior Period Fuel.  For further information on this trust, see Note 11, "Marketable Securities," to the consolidated financial statements.

D.

Long-Term Contractual Arrangements

Utility Group:

Vermont Yankee Nuclear Power Corporation (VYNPC):  Previously under the terms of their agreements, NU’s companies paid their ownership (or entitlement) shares of costs, which included depreciation, O&M expenses, taxes, the estimated cost of decommissioning, and a return on invested capital to VYNPC and recorded these costs as purchased-power expenses.  On July 31, 2002, VYNPC consummated the sale of its nuclear generating unit to a subsidiary of Entergy Corporation for approximately $180 million.  CL&P, PSNH and WMECO have commitments to buy approximately 16 percent of the VYNPC plant’s output through March of 2012 at a range of fixed prices.  The total cost of purchases under contracts with VYNPC amounted to $25.7 million in 2005, $26.8 million in 2004 and $29.9 million in 2003.

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 $275.3 million in 2005, $323.3 million in 2004 and $283.4 million in 2003.  These amounts relate to IPP contracts and do not include contractual commitments related to CL&P’s transitional standard offer or standard offer, PSNH’s short-term power supply management or WMECO’s basic and default service.

Natural Gas Procurement Contracts: Yankee Gas has entered into long-term contracts for the purchase of a specified quantity of natural gas in the normal course of business as part of its portfolio to meet its actual sales commitments.  The majority of these contracts have expiration dates in 2006 and 2007.  The total cost of Yankee Gas’ procurement portfolio, including these contracts, amounted to $321.2 million in 2005, $250.5 million in 2004 and $218.6 million in 2003.

Portland Natural Gas Transmission System (PNGTS) Pipeline Commitments:  PSNH has a contract for capacity on the PNGTS pipeline which extends through 2018.  The total cost under this contract amounted to $1.6 million in 2005, $2 million in 2004 and $1.9 million in 2003.  These costs are not recovered from PSNH's retail customers.

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.  The total cost of these agreements amounted to $21.2 million in 2005, $23.7 million in 2004 and $25.3 million in 2003.

Transmission Business Project Commitments:  These amounts represent commitments for various services and materials associated with CL&P's Bethel, Connecticut to Norwalk, Connecticut and the Middletown, Connecticut to Norwalk, Connecticut projects and other projects.  

Yankee Gas Liquefied Natural Gas (LNG) Storage Facility: In 2004, Yankee Gas signed a contract for the design and building of the LNG facility.  Yankee Gas anticipates that the facility will become operational in time for the 2007/2008 heating season.  Certain future estimated construction expenditures totaling $16 million are not included in the contract signed to build the LNG facility and are not included in the table of estimated future annual Utility Group costs below.  

Northern Wood Power Project:  In October of 2004, PSNH received the approvals necessary to begin construction related to the conversion of one of three 50 MW units at the coal-fired Schiller Station to burn wood (Northern Wood Power Project).  Construction of the $75 million Northern Wood Power Project began in 2004 and significant construction has been completed.  Certain other estimated construction expenditures totaling $3.8 million are not included in the contracts signed for the Northern Wood Power Project and are not included in the table of estimated future annual Utility Group costs below.

Yankee Companies FERC-Approved Billings, Subject to Refund:  NU has significant decommissioning and plant closure cost obligations to the Yankee Companies. Each plant has been shut down and is undergoing decommissioning.  The Yankee Companies collect decommissioning and closure costs through wholesale, FERC-approved rates charged under power purchase agreements with several New England utilities, including NU’s electric utility companies.  These companies in turn pass these costs on to their customers through state regulatory commission-approved retail rates.  YAEC and MYAPC received FERC approval to collect all presently estimated decommissioning and closure costs.  On November 23, 2005, YAEC submitted an application to the FERC to increase YAEC's wholesale decommissioning charges.  On January 31, 2006, the FERC issued an order accepting the rate increase, effective February 1, 2006, subject to refund after hearings and settlement judge proceedings.  CYAPC received an order on August 30, 2004 from the FERC allowing collection of its decommissioning and closure costs, subject to refund.  The table of estimated future annual Utility Group costs below includes the estimated decommissioning and closure costs for YAEC, MYAPC and CYAPC.

Estimated Future Annual Utility Group Costs:  The estimated future annual costs of the Utility Group's significant long-term contractual arrangements at December 31, 2005 are as follows:

(Millions of Dollars)	2006	2007	2008	2009	2010	Thereafter
VYNPC	$ 28.6	$ 27.5	$ 27.8	$ 30.2	$ 29.2	$      37.1
Electricity procurement contracts	336.3	267.4	230.4	200.7	179.2	930.5
Natural gas procurement contracts	239.6	103.3	38.0	37.5	37.1	73.0
PNGTS pipeline commitments	2.0	2.0	2.0	2.0	2.0	15.9
Hydro-Quebec	23.4	22.3	22.1	21.9	21.9	216.9
Transmission business project commitments	173.8	7.0	7.0	7.0	-	-
Yankee Gas LNG facility	41.9	4.0	-	-	-	-
Northern Wood Power Project	6.5	-	-	-	-	-
Yankee Companies FERC-approved billings,   subject to refund	95.1	75.4	65.4	61.7	60.6	-
Totals	$947.2	$508.9	$392.7	$361.0	$330.0	$1,273.4

NU Enterprises:  

Select Energy Purchase Agreements:  Select Energy maintains long-term agreements to purchase energy as part of its portfolio of resources to meet its actual or expected sales commitments.  These sales commitments were formerly accounted for on the accrual basis but are now recorded at their mark-to-market value.  

Contract Assignment Agreement:  During the fourth quarter of 2005, Select Energy settled a wholesale contract for $55.9 million with payments commencing in January of 2006 and ending in December of 2008.  If certain conditions are met, these payments could be accelerated.

NGC Northfield Mountain Commitment:  NGC has a commitment to purchase a spare main transformer to be delivered in the summer of 2006 for on-site storage.  The transformer will cost $4 million and will replace one of the two existing in-service transformers.

HWP Project Commitments:  In March of 2005, HWP notified Massachusetts environmental regulators that it planned to install a selective catalytic reduction system at the 146 MW Mt. Tom coal-fired station in Holyoke, Massachusetts.  The $14 million project commenced in July of 2005 and is expected to be completed by mid-2006.  Amounts spent on this project through December 31, 2005 totaled $9.9 million.  

HWP Coal Commitments:  In July of 2005, HWP entered into a $50.4 million contract to purchase coal to fuel the Mt. Tom coal-fired station in Holyoke, Massachusetts.  Obligations under this contract will commence in 2006.

Estimated Future Annual NU Enterprises Costs:  The estimated future annual costs of NU Enterprises' significant contractual arrangements are as follows:  

(Millions of Dollars)	2006	2007	2008	2009	2010	Thereafter
Select Energy purchase agreements	$2,226.1	$657.0	$281.1	$20.3	$18.2	$5.0
Contract assignment agreement	18.5	18.3	19.1	-	-	-
NGC Northfield Mountain commitment	4.0	-	-	-	-	-
HWP project commitments	4.1	-	-	-	-	-
HWP coal commitments	2.3	22.9	22.9	2.3	-	-
Totals	$2,255.0	$698.2	$323.1	$22.6	$18.2	$5.0

Select Energy’s purchase contract amounts exceed the amount expected to be reported in fuel, purchased and net interchange power because energy trading transactions are classified in revenues. Select Energy also maintains certain wholesale energy commitments whose mark-to-market values have been recorded on the consolidated balance sheets as derivative assets and liabilities.  The aggregate amount of these purchase contracts was $2.6 billion at December 31, 2005.

The amounts and timing of the costs associated with Select Energy’s purchase agreements could be impacted by the exit from NU Enterprises’ merchant energy business.  

E.

Deferred Contractual Obligations

FERC Proceedings:  In 2003, CYAPC increased the estimated decommissioning and plant closure costs for the period 2000 through 2023 by approximately $395 million over the April 2000 estimate of $436 million approved by the FERC in a 2000 rate case settlement.  The revised estimate reflects the increases in the projected costs of spent fuel storage, increased security and liability and property insurance costs, and the fact that CYAPC is now self performing all work to complete the decommissioning of the plant due to the termination of the decommissioning contract with Bechtel Power Corporation (Bechtel) in July of 2003.  NU's share of CYAPC's increase in decommissioning and plant closure costs is approximately $194 million.  On July 1, 2004, CYAPC filed with the FERC for recovery seeking to increase its annual decommissioning collections from $16.7 million to $93 million for a six-year period beginning on January 1, 2005.   On August 30, 2004, the FERC issued an order accepting the rates, with collection beginning on February 1, 2005, subject to refund.

Both the DPUC and Bechtel filed testimony in the FERC proceeding claiming that CYAPC was imprudent in its management of the decommissioning project.  In its testimony, the DPUC recommended a disallowance of $225 million to $234 million out of CYAPC's requested rate

increase of approximately $395 million.  NU's share of the DPUC's recommended disallowance would be between $110 million to $115 million.  The FERC staff also filed testimony that recommended a $38 million decrease in the requested rate increase claiming that CYAPC should have used a different gross domestic product (GDP) escalator.  NU's share of this recommended decrease is $18.6 million.  

On November 22, 2005, a FERC administrative law judge issued an initial decision finding no imprudence on CYAPC's part.  However, the administrative law judge did agree with the FERC staff’s position that a lower GDP escalator should be used for calculating the rate increase and found that CYAPC should recalculate its decommissioning charges to reflect the lower escalator.  Briefs to the full FERC addressing these issues were filed in January and February of 2006, and a final order is expected later in 2006.  Management expects that if the FERC staff's position on the decommissioning GDP cost escalator is found by the FERC to be more appropriate than that used by CYAPC to develop its proposed rates, then CYAPC would review whether to reduce its estimated decommissioning obligation and reduce the customers' obligation, including CL&P, PSNH and WMECO.  

The company cannot at this time predict the timing or outcome of the FERC proceeding required for the collection of the increased CYAPC decommissioning costs.  The company believes that the costs have been prudently incurred and will ultimately be recovered from the customers of CL&P, PSNH and WMECO.  However, there is a risk that some portion of these increased costs may not be recovered, or will have to be refunded if recovered, as a result of the FERC proceedings.  

On June 10, 2004, the DPUC and the Connecticut Office of Consumer Counsel (OCC) filed a petition seeking a declaratory order that CYAPC be allowed to recover all decommissioning costs from its wholesale purchasers, including CL&P, PSNH and WMECO, but that such purchasers may not be allowed to recover in their retail rates any costs that the FERC might determine to have been imprudently incurred.  On August 30, 2004, the FERC denied this petition.  On September 29, 2004, the DPUC and OCC asked the FERC to reconsider the petition and on October 20, 2005, the FERC denied the reconsideration, holding that the sponsor companies are only obligated to pay CYAPC for prudently incurred decommissioning costs and the FERC has no jurisdiction over the sponsors' rates to their retail customers.  On December 12, 2005, the DPUC sought review of these orders by the United States Court of Appeals for the D.C. Circuit.  The FERC and CYAPC have aske d the court to dismiss the case and the DPUC has objected to a dismissal.  NU cannot predict the timing or the outcome of these proceedings.

Bechtel Litigation:  CYAPC and Bechtel commenced litigation in Connecticut Superior Court over CYAPC's termination of Bechtel's contract for the decommissioning of CYAPC's nuclear generating plant.  After CYAPC terminated the contract, responsibility for decommissioning was transitioned to CYAPC, which recommenced the decommissioning process.

On March 7, 2006, CYAPC and Bechtel executed a settlement agreement terminating this litigation.  Bechtel has agreed to pay CYAPC $15 million, and CYAPC will withdraw its termination of the contract for default and deem it terminated by agreement.

Spent Nuclear Fuel Litigation:  CYAPC, YAEC and MYAPC also commenced litigation in 1998 charging that the federal government breached contracts it entered into with each company in 1983 under the Act.  Under the Act, the DOE was to begin removing spent nuclear fuel from the nuclear plants of the Yankee Companies no later than January 31, 1998 in return for payments by each company into the nuclear waste fund.  No fuel has been collected by the DOE, and spent nuclear fuel is stored on the sites of the Yankee Companies' plants.  The Yankee Companies collected the funds for payments into the nuclear waste fund from wholesale utility customers under FERC-approved contract rates.  The wholesale utility customers in turn collect these payments from their retail electric customers.  The Yankee Companies' individual damage claims attributed to the government's breach ranging from $523 million to $543 million are specific to e ach plant and include incremental storage, security, construction and other costs through 2010.  The CYAPC damage claim ranges from $186 million to $198 million, the YAEC damage claim ranges from $177 million to $185 million and the MYAPC damage claim is $160 million.  The DOE trial ended on August 31, 2004 and a verdict has not been reached.  

Post-trial findings of facts and final briefs were filed by the parties in January of 2005.  The Yankee Companies' current rates do not include an amount for recovery of damages in this matter.  Management can predict neither the outcome of this matter nor its ultimate impact on NU.

YAEC:  In November of 2005, YAEC established an updated estimate of the cost of completing the decommissioning of its plant resulting in an increase of approximately $85 million.  NU's share of the increase in estimated costs is $32.7 million.  This estimate reflects the cost of completing site closure activities from October of 2005 forward and storing spent nuclear fuel and other high level waste on site until 2020.  This estimate projects a total cost of $192.1 million for the completion of decommissioning and long-term fuel storage.  To fund these costs, on November 23, 2005, YAEC submitted an application to the FERC to increase YAEC’s wholesale decommissioning charges.  The DPUC and the Massachusetts attorney general protested these increases.  On January 31, 2006, the FERC issued an order accepting the rate increase, effective February 1, 2006, subject to refund after hearings and settlement judge proc eedings.  The hearings have been suspended pending settlement discussions between YAEC, the FERC and other intervenors in the case.  NU has a 38.5 percent ownership interest in YAEC and can predict neither the outcome of this matter nor its ultimate impact on NU.

F.

NRG Energy, Inc. Exposures

Certain subsidiaries of NU, including CL&P and Yankee Gas, have entered into transactions with NRG Energy, Inc. (NRG) and certain of its subsidiaries.  On May 14, 2003, NRG and certain of its subsidiaries filed voluntary bankruptcy petitions and on December 5, 2003, NRG emerged from bankruptcy.  NU’s NRG-related exposures as a result of these transactions relate to 1) the recovery of congestion charges incurred by NRG prior to the implementation of standard market design (SMD) on March 1, 2003, which is still pending before the court, 2) the recovery of CL&P’s station service billings from NRG, which is currently the subject of an arbitration, and 3) the recovery of Yankee Gas’ and CL&P’s expenditures that were incurred related to an NRG subsidiary’s generating plant construction project that has ceased.  While it is unable to determine the ultimate outcome of these issues, management does not expect th eir resolution will have a material adverse effect on NU’s consolidated financial condition or results of operations.

G.

Consolidated Edison, Inc. Merger Litigation

Certain gain and loss contingencies exist with regard to the merger agreement between NU and Consolidated Edison, Inc. (Con Edison) and the related litigation.  

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' 1999 merger agreement (Merger Agreement).  On March 12, 2001, NU filed suit against Con Edison seeking damages in excess of $1 billion.  

In an opinion dated October 12, 2005, a panel of three judges at the Second Circuit held that the shareholders of NU had no right to sue Con Edison for its alleged breach of the parties' Merger Agreement.  NU's request for a rehearing was denied on January 3, 2006.  This ruling left intact the remaining claims between NU and Con Edison for breach of contract, which include NU’s claim for recovery of costs and expenses of approximately $32 million and Con Edison's claim for damages of "at least $314 million."  NU is currently considering whether to seek review by the United States Supreme Court.  At this stage, NU cannot predict the outcome of this matter or its ultimate effect on NU.

10.

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 and Special Deposits: The carrying amounts approximate fair value due to the short-term nature of these cash items.

SERP Investments: Investments held for the benefit of the SERP are recorded at fair market value based upon quoted market prices.  The investments having a cost basis of $54 million and $50.1 million held for benefit of the SERP were recorded at their fair market values at December 31, 2005 and 2004, of $58.1 million and $55.1 million, for 2005 and 2004, respectively.  For further information regarding the SERP liabilities and related investments, see Note 7E, "Employee Benefits - Supplemental Executive Retirement and Other Plans," and Note 11, "Marketable Securities," to the consolidated financial statements.

Prior Spent Nuclear Fuel Trust: During 2004, WMECO established a trust to fund the amounts due to the DOE for its prior spent nuclear fuel obligation.  These investments having a cost basis of $51.1 million and $49.5 million for 2005 and 2004, respectively, were recorded at their fair market value of $50.8 million and $49.3 million at December 31, 2005 and 2004, respectively.  For further information regarding these investments, see Note 11, "Marketable Securities," 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, 2005
(Millions of Dollars)	Carrying Amount	Fair   Value
Preferred stock not subject   to mandatory redemption	$  116.2	$    98.5
Long-term debt -
First mortgage bonds	1,314.8	1,425.7
Other long-term debt	1,744.3	1,791.5
Rate reduction bonds	1,350.5	1,433.6

	At December 31, 2004
(Millions of Dollars)	Carrying Amount	Fair    Value
Preferred stock not subject   to mandatory redemption	$   116.2	$   101.4
Long-term debt -
First mortgage bonds	1,072.3	1,228.8
Other long-term debt	1,812.4	1,898.7
Rate reduction bonds	1,546.5	1,674.0

Other long-term debt includes $268 million and $259.7 million of fees and interest due for spent nuclear fuel disposal costs at December 31, 2005 and 2004, respectively.

Other Financial Instruments:  The carrying value of financial instruments included in current assets and current liabilities, including investments in securitizable assets, approximates their fair value.

11.

Marketable Securities

The following is a summary of NU’s available-for-sale securities which are recorded at their fair market values and are included in current and long-term marketable securities on the accompanying consolidated balance sheets.  Changes in the fair value of these securities are recorded as unrealized gains and losses in accumulated other comprehensive income.  

	At December 31,
(Millions of Dollars)	2005	2004
Globix	$    3.7	(a)
SERP securities	58.1	$  55.1
WMECO prior spent nuclear fuel trust	50.8	49.3
Totals	$112.6	$104.4

For 2005, management determined that the decline in the value of the Globix investment was other than temporary in nature and recorded pre-tax charges totaling $6.1 million in other income, net on the accompanying consolidated statements of (loss)/income.  This amount is included in the negative $0.9 million after-tax amount which was reclassified from accumulated other comprehensive income and recognized in earnings in 2005.  

(a)

At December 31, 2004, NU’s $9.8 million investment in NEON was not a marketable security.  On March 8, 2005, NEON merged with Globix, and NU’s investment in Globix became a marketable security at that time.  For further information regarding the Globix investment, see Note 1X, "Summary of Significant Accounting Policies – Marketable Securities," to the consolidated financial statements.  

At December 31, 2005 and 2004, these marketable securities are comprised of the following:

(Millions of Dollars) At December 31, 2005	Amortized Cost	Pre-Tax  Gross  Unrealized  Gains	Pre-Tax  Gross  Unrealized  Losses	Estimated  Fair Value
United States equity securities	$  23.2	$3.9	$(0.3)	$  26.8
Non-United States   equity securities	6.3	0.9	-	7.2
Fixed income securities	79.3	0.2	(0.9)	78.6
Totals	$108.8	$5.0	$(1.2)	$112.6

(Millions of Dollars) At December 31, 2004	Amortized  Cost	Pre-Tax  Gross  Unrealized  Gains	Pre-Tax  Gross  Unrealized  Losses	Estimated  Fair Value
United States equity securities	$19.3	$3.8	$(0.2)	$  22.9
Non-United States   equity securities	5.6	1.3	-	6.9
Fixed income securities	74.7	0.3	(0.4)	74.6
Totals	$99.6	$5.4	$(0.6)	$104.4

At December 31, 2005 and 2004, NU evaluated the securities in an unrealized loss position and has determined that none of the related unrealized losses are deemed to be other-than-temporary in nature.  At December 31, 2005 and 2004, the gross unrealized losses and fair value of NU's investments that have been in a continuous unrealized loss position for less than 12 months and 12 months or greater were as follows:

	Less than 12 Months		12 Months or Greater		Total
(Millions of Dollars) At December 31, 2005	Estimated Fair Value	Pre-Tax Gross Unrealized Losses	Estimated Fair Value	Pre-Tax Gross Unrealized Losses	Estimated Fair Value	Pre-Tax Gross Unrealized Losses
United States equity securities	$ 2.9	$(0.2)	$0.4	$(0.1)	$ 3.3	$(0.3)
Non-United States   equity securities	- -	-	-	-	-	-
Fixed income securities	39.8	(0.7)	5.7	(0.2)	45.6	(0.9)
Totals	$42.7	$(0.9)	$6.1	$(0.3)	$48.9	$(1.2)

	Less than 12 Months		12 Months or Greater		Total
(Millions of Dollars) At December 31, 2004	Estimated Fair Value	Pre-Tax Gross Unrealized Losses	Estimated Fair Value	Pre-Tax Gross Unrealized Losses	Estimated Fair Value	Pre-Tax Gross Unrealized Losses
United States equity securities	$ 1.7	$(0.2)	$   -	$     -	$ 1.7	$(0.2)
Non-United States   equity securities	-	-	-	-	-	- -
Fixed income securities	40.0	(0.4)	-	-	40.0	(0.4)
Totals	$41.7	$(0.6)	$   -	$     -	$41.7	$(0.6)

For information related to the change in net unrealized holding gains and losses included in shareholders' equity, see Note 15, "Accumulated Other Comprehensive Income/(Loss)," to the consolidated financial statements.

For the years ended December 31, 2005, 2004, and 2003, realized gains and losses recognized on the sale of available-for-sale securities are as follows:

(Millions of Dollars)	Realized  Gains	Realized  Losses	Net Realized  Gains/(Losses)
2005	$1.3	$(7.1)	$(5.8)
2004	0.9	(0.3)	0.6
2003	0.5	(0.1)	0.4

For the year ended December 31, 2005, realized losses of $0.4 million relating to the WMECO spent nuclear fuel trust are included in fuel, purchased and net interchange power on the accompanying consolidated statements of (loss)/income.  There were no realized losses relating to the WMECO spent nuclear fuel trust in 2004 or 2003.  For the years ended December 31, 2005, 2004 and 2003, all other net realized (losses)/gains of $(5.4) million, $0.6 million, and $0.4 million, respectively, are included in other income, net on the accompanying consolidated statements of (loss)/income.  

NU utilizes the specific identification basis method for the Globix and SERP securities and the average cost basis method for the WMECO prior spent nuclear fuel trust to compute the realized gains and losses on the sale of available-for-sale securities.

Proceeds from the sale of these securities, including proceeds from short-term investments, totaled $137.1 million, $106.2 million, and $34.1 million for the years ended December 31, 2005, 2004 and 2003, respectively.

At December 31, 2005, the contractual maturities of the available-for-sale securities are as follows:

(Millions of Dollars)	Amortized  Cost	Estimated  Fair Value
Less than one year	$  51.8	$  56.0
One to five years	28.7	28.5
Six to ten years	6.7	6.6
Greater than ten years	21.6	21.5
Totals	$108.8	$112.6

NU’s investment in Globix is included in the one to five years maturity category in the table above.  All other available-for-sale equity securities are included in the less than one year maturity category in the table above.  

For further information regarding marketable securities, see Note 1X, "Summary of Significant Accounting Policies - Marketable Securities" to the consolidated financial statements.

12.

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.  Certain lease agreements contain contingent lease payments.  The contingent lease payments are based on various factors, such as the commercial paper rate plus a credit spread or the consumer price index.

Capital lease rental payments were $3.4 million in 2005, $3.3 million in 2004 and $3.7 million in 2003.  Interest included in capital lease rental payments was $1.9 ­million in 2005, $2 million in 2004 and $2.3 million in 2003.  Capital lease asset amortization was $1.4 million in 2005, $1.3 million in 2004, and $1.4 million in 2003.  

Operating lease rental payments charged to expense were $15.6 million in 2005, $16.3 million in 2004 and $16.1 million in 2003.  These amounts include $0.9 million, $0.9 million, and $0.7 million included in (loss)/income from discontinued operations on the accompanying consolidated statements of (loss)/income for the years ended December 31, 2005, 2004, and 2003, respectively.  The capitalized portion of operating lease payments was approximately $9.4 million, $8.2 million, and $7.7 million for the years ended December 31, 2005, 2004, and 2003, respectively.  

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, 2005 are as follows:

(Millions of Dollars)	Capital  Leases	Operating  Leases
2006	$ 2.7	$  33.4
2007	2.6	29.9
2008	2.3	26.8
2009	2.0	18.8
2010	1.5	15.5
Thereafter	16.6	42.3
Future minimum lease payments	27.7	$166.7
Less amount representing interest	13.7
Present value of future minimum    lease payments	$14.0

Total projected future operating lease payments of $166.7 million above includes an aggregate amount of $1.8 million related to companies classified as discontinued operations in the accompanying consolidated financial statements.  

13.

Long-Term Debt

Long-term debt maturities and cash sinking fund requirements on debt outstanding at December 31, 2005, for the years 2006 through 2010 and thereafter, which exclude $268 million of fees and interest due for spent nuclear fuel disposal costs and a negative $9.1 million related to net unamortized premiums or discounts and other fair value adjustments at December 31, 2005, are as follows (millions of dollars):

Year
2006	$     22.7
2007	4.1
2008	155.3
2009	56.5
2010	8.0
Thereafter	2,544.5
Total	$2,791.1

Essentially all utility plant of CL&P, PSNH, NGC, and Yankee Energy System, Inc. is subject to the liens of each company’s respective first mortgage bond indenture.

CL&P has $315.5 million of tax-exempt Pollution Control Revenue Bonds (PCRBs) secured by second mortgage liens on transmission assets, junior to the liens of its first mortgage bond indentures.

CL&P has $62 million of tax-exempt PCRBs with bond insurance and secured by the first mortgage bonds.  For financial reporting purposes, this debt is not considered to be first mortgage bonds unless CL&P failed to meet its obligations under the PCRBs.

PSNH entered into financing arrangements with the Business Finance Authority (BFA) of the state of New Hampshire, pursuant to which the BFA issued five series of PCRBs and loaned the proceeds to PSNH.  At both December 31, 2005 and 2004, $407.3 million of the PCRBs were outstanding.  PSNH’s obligation to repay each series of PCRBs is secured by bond insurance and by first mortgage bonds.  Each such series of first mortgage bonds contains similar terms and provisions as the applicable series of PCRBs.  For financial reporting purposes, these first mortgage bonds would not be considered outstanding unless PSNH failed to meet its obligations under the PCRBs.

NU’s long-term debt agreements provide that certain of its subsidiaries must comply with certain financial and non-financial covenants as are customarily included in such agreements, including but not limited to, debt service coverage ratios and interest coverage ratios.  The parties to these agreements currently are and expect to remain in compliance with these covenants.

On November 2, 2005, NU entered into an unsecured credit facility, under which all borrowings will have a maturity of 13 months, with such borrowings being classified as long-term debt.  The new facility provides a total commitment of $310 million in borrowings and LOCs.  This facility will expire no later than November 30, 2007, although no advances or LOCs will be available under the facility beyond October 30, 2006.  NU may borrow at variable rates plus an applicable margin based upon certain debt ratings, as rated by the higher of Standard and Poor's or Moody's.  Under this facility, NU must comply with certain financial and non-financial covenants as are customarily included in such agreements, including but not limited to, consolidated debt ratios.  NU currently is and expects to remain in compliance with these covenants.  At December 31, 2005, there were no borrowings outstanding under this facility.

Long-term debt - first mortgage bonds on the accompanying consolidated statements of capitalization at December 31, 2005 include $200 million, $50 million, and $50 million of long-term debt issued in 2005 related to CL&P, PSNH and Yankee Gas, respectively.   

The weighted-average effective interest rate on PSNH's variable-rate pollution control notes was 2.51 percent for 2005 and 1.25 percent for 2004.  The pollution control note due in 2031, has an interest rate of 3.35 percent effective through October 1, 2008, at which time the bonds will be remarketed, and the interest rate will be adjusted.

Other long-term debt - other on the accompanying consolidated statements of capitalization at December 31, 2005 includes $50 million of long-term debt issued in 2005 related to WMECO.

Liabilities of assets held for sale at December 31, 2005 includes $82.6 million relating to SESI long-term debt.  

For information regarding fees and interest due for spent nuclear fuel disposal costs, see Note 9C, "Commitments and Contingencies - Spent Nuclear Fuel Disposal Costs," to the consolidated financial statements.

The change in fair value totaling a negative $5.2 million and a positive $0.1 million at December 31, 2005 and 2004, respectively, on the accompanying consolidated statements of capitalization, reflects the NU parent 7.25 percent amortizing note, due 2012 in the amount of $263 million, and is hedged with a fixed to floating interest rate swap.  The change in fair value of the debt was recorded as an adjustment to long-term debt with an equal and offsetting adjustment to derivative assets for the change in fair value of the fixed to floating interest rate swap.

14.

Dividend Restrictions

The Federal Power Act and certain state statutes limit the payment of dividends by CL&P, PSNH, and WMECO to their respective retained earnings balances.  Yankee Gas is also subject to certain restrictions.  At December 31, 2005, retained earnings available for payment of dividends totaled $330.4 million.

NGC is subject to certain dividend payment restrictions under its bond covenants.

15.

Accumulated Other Comprehensive Income/(Loss)

The accumulated balance for each other comprehensive income/(loss) item is as follows:

(Millions of Dollars)	December 31,  2004	Current  Period     Change	December 31,  2005
Qualified cash flow   hedging instruments	$(3.5)	$21.7	$18.2
Unrealized gains   on securities	3.2	(0.9)	2.3
Minimum supplemental  executive retirement   pension liability   adjustments	(0.9)	0.4	(0.5)
Accumulated other     comprehensive (loss)/income	$(1.2)	$21.2	$20.0

(Millions of Dollars)	December 31,  2003	Current    Period  Change	December 31,  2004
Qualified cash flow   hedging instruments	$24.8	$(28.3)	$(3.5)
Unrealized gains   on securities	2.0	1.2	3.2
Minimum supplemental  executive retirement   pension liability   adjustments	(0.8)	(0.1)	(0.9)
Accumulated other     comprehensive income/(loss)	$26.0	$(27.2)	$(1.2)

The changes in the components of other comprehensive income/(loss) are reported net of the following income tax effects:

(Millions of Dollars)	2005	2004	2003
Qualified cash flow   hedging instruments	$(13.4)	$14.4	$(6.4)
Unrealized gains  on securities	0.6	(0.7)	(1.4)
Minimum supplemental  executive retirement   pension liability   adjustments	(0.3)	0.1	0.5
Accumulated other     comprehensive income	$(13.1)	$13.8	$(7.3)

Adjustments to accumulated other comprehensive income/(loss) for NU's qualified cash flow hedging instruments are as follows:

	At December 31,
(Millions of Dollars, Net of Tax)	2005	2004
Balance at beginning of year	$(3.5)	$24.8
Hedged transactions   recognized to earnings	5.6	(57.8)
Change in fair value	11.0	25.0
Cash flow transactions entered   into for the period	5.1	4.5
Net change associated with the   current period hedging transactions	21.7	(28.3)
Total fair value adjustments   included in accumulated other   comprehensive income	$18.2	$(3.5)

16.

Earnings Per Share

EPS is computed based upon the weighted-average number of common shares outstanding, excluding unallocated ESOP shares, during each year.  Diluted EPS is computed on the basis of the weighted-average number of common shares outstanding plus the potential dilutive effect if certain securities are converted into common stock.  In 2005, 2004 and 2003, 1,122,541 options, 696,994 options and 355,153 options, respectively, were excluded from the following table as these options were antidilutive.  The weighted average common shares outstanding at December 31, 2005 include the impact of the issuance of 23 million common shares on December 12, 2005 which were outstanding for 20 days in 2005.  The following table sets forth the components of basic and diluted EPS:

(Millions of Dollars,  except share information)	2005	2004	2003
(Loss)/income from continuing operations	$(229.2)	$113.0	$116.4
(Loss)/income from discontinued operations	(23.3)	3.6	4.7
(Loss)/income before cumulative effects of accounting changes	(252.5)	116.6	121.1
Cumulative effects of accounting changes, net of tax benefits	(1.0)	-	(4.7)
Net (loss)/income	$(253.5)	$116.6	$116.4
Basic EPS common shares outstanding (average)	131,638,953	128,245,860	127,114,743
Dilutive effect of employee stock options	-	150,216	125,981
Fully diluted EPS common shares outstanding (average)	131,638,953	128,396,076	127,240,724
Basic and fully diluted EPS:
(Loss)/income from continuing operations	$ (1.74)	$0.88	$0.91
(Loss)/income from discontinued operations	(0.18)	0.03	0.04
Cumulative effects of accounting changes, net of tax benefits	(0.01)	-	(0.04)
Net (loss)/income	$ (1.93)	$0.91	$0.91

17.

Segment Information

Presentation:  NU is organized between the Utility Group and NU Enterprises businesses based on a combination of factors, including the characteristics of each business’ products and services, the sources of operating revenues and expenses and the regulatory environment in which they operate.  Effective January 1, 2005, the portion of NGS's business that supports NGC's and HWP's generation assets was reclassified from the services and other segment to the merchant energy segment within the NU Enterprises segment.  Effective January 1, 2004, separate detailed information regarding the Utility Group’s transmission businesses and NU Enterprises’ merchant energy business is now included in the following segment information.  Segment information for all periods has been restated to conform to the current presentation except for total asset information for the transmission business segment as this information is not av ailable.

The Utility Group segment, including both the regulated electric distribution and transmission businesses, as well as the gas distribution business comprising Yankee Gas, represents approximately 74.4 percent, 70.1 percent, and 73.1 percent of NU’s total revenues for the years ended December 31, 2005, 2004 and 2003, respectively, and includes the operations of the regulated electric utilities, CL&P, PSNH and WMECO, whose complete financial statements are included in NU’s report on Form 10-K. PSNH’s distribution segment includes generation activities. Also included

in NU’s report on Form 10-K is detailed information regarding CL&P’s, PSNH’s, and WMECO’s transmission businesses. Utility Group revenues from the sale of electricity and natural gas are primarily derived from residential, commercial and industrial customers and are not dependent on any single customer.

The NU Enterprises merchant energy business segment includes Select Energy, NGC, NGS, and the generation operations of HWP, while the NU Enterprises services and other business segment includes Boulos, Woods Electrical, and NGS Mechanical, Inc., (which are subsidiaries of NGS), SESI, SECI, HEC/Tobyhanna, HEC/CJTS, and intercompany eliminations.  The results of NU Enterprises parent are also included within services and other.  On March 9, 2005, NU announced its decision to exit the wholesale marketing business and the energy services businesses.  On November 7, 2005, NU announced its decision to also exit its retail marketing and competitive generation businesses.  In November of 2005, NU Enterprises sold SECI-NH (a division of SECI) and Woods Network.  For further information regarding NU Enterprises' businesses, which are being exited, see Note 2, "Wholesale Contract Market Changes," Note 3, "Restructuring a nd Impairment Charges," and Note 4, "Assets Held for Sale and Discontinued Operations," to the consolidated financial statements.  

NU's consolidated statements of (loss)/income for the years ended December 31, 2005, 2004 and 2003 present the operations for SESI, SECI-NH, Woods Network, and Woods Electrical as discontinued operations.  For further information, see Note 4, "Assets Held for Sale and Discontinued Operations," to the consolidated financial statements.

Other in the tables includes the results for Mode 1 Communications, Inc., an investor in Globix, the results of the non-energy-related subsidiaries of Yankee (Yankee Energy Services Company, Yankee Energy Financial Services Company, and NorConn Properties, Inc.), the non-energy operations of HWP, and the results of NU's parent and service companies.  Interest expense included in other primarily relates to the debt of NU parent.  

Other includes pre-tax investment write-downs totaling $6.9 million, $13.8 million, and $1.4 million in 2005, 2004, and 2003, respectively.

Intercompany Transactions:  Select Energy has served a portion of CL&P’s TSO or standard offer load for 2004 and 2003.  Total Select Energy revenues from CL&P for CL&P’s standard offer load, TSO load and for other transactions with CL&P, represented approximately $53.4 million for the year ended December 31, 2005, $611.3 million for the year ended December 31, 2004 and $688 million for the year ended December 31, 2003, of total NU Enterprises’ revenues.  Total CL&P purchases from Select Energy are eliminated in consolidation.

WMECO’s purchases from Select Energy for standard offer and default service and for other transactions with Select Energy represented $36.3  million, $108.5 million and $143 million of total NU Enterprises’ revenues for the years ended December 31, 2005, 2004 and 2003, respectively.  Total WMECO purchases from Select Energy are eliminated in consolidation.

Customer Concentrations:  Select Energy revenues related to contracts with NSTAR companies represented $296.7 million of total NU Enterprises’ revenues for the year ended December 31, 2005 and represented $300.2 million of total NU Enterprises' revenues for the year ended December 31, 2004.  Select Energy also provides basic generation service in the New Jersey and Maryland market.  Select Energy revenues related to these contracts represented $530 million of total NU Enterprises’ revenues for the year ended December 31, 2005, $334.2 million for the year ended December 31, 2004 and $380.4 million for the year ended December 31, 2003.  No other individual customer represented in excess of 10 percent of NU Enterprises’ revenues for the years ended December 31, 2005, 2004, or 2003.

Due to the decision to exit the wholesale business, all wholesale revenues, including intercompany revenues, have been included in fuel, purchased and net interchange power beginning in the second quarter of 2005.  

NU’s segment information for the years ended December 31, 2005, 2004, and 2003 is as follows (some amounts may not agree between segment schedules due to rounding):

	For the Year Ended December 31, 2005
	Utility Group
	Distribution
(Millions of Dollars)	Electric	Gas	Transmission	NU Enterprises	Other	Eliminations	Total
Operating revenues	$4,836.5	$  503.3	$167.5	$1,963.6	$  353.0	$   (426.5)	$ 7,397.4
Wholesale contract market   changes, net	- -	-	-	(440.9)	- -	- -	(440.9)
Restructuring and impairment charges	-	-	-	(44.1)	-	-	(44.1)
Depreciation and amortization	(549.1)	(22.0)	(24.0)	(14.7)	(17.8)	13.6	(614.0)
Other operating expenses	(4,010.0)	(440.8)	(72.6)	(2,001.4)	(355.1)	427.6	(6,452.3)
Operating income/(loss)	277.4	40.5	70.9	(537.5)	(19.9)	14.7	(153.9)
Interest expense, net of AFUDC	(169.5)	(17.1)	(15.0)	(49.7)	(34.9)	16.4	(269.8)
Interest income	3.6	0.3	0.6	6.6	17.0	(19.2)	8.9
Other income/(loss), net	38.8	(0.3)	(1.5)	(5.6)	150.6	(153.6)	28.4
Income tax (expense)/benefit	(41.1)	(6.1)	(12.5)	212.3	18.4	(8.2)	162.8
Preferred dividends	(5.6)	-	-	-	-	-	(5.6)
Income/(loss) from   continuing operations	103.6	17.3	42.5	(373.9)	131.2	(149.9)	(229.2)
Loss from discontinued operations	-	-	-	(23.3)	-	-	(23.3)
Income/(loss) before cumulative  effect of accounting change	103.6	17.3	42.5	(397.2)	131.2	(149.9)	(252.5)
Cumulative effect of accounting  change, net of tax benefit	- -	- -	- -	(1.0)	- -	- -	(1.0)
Net income/(loss)	$   103.6	$     17.3	$ 42.5	$  (398.2)	$   131.2	$   (149.9)	$    (253.5)
Total assets (1)	$8,923.3	$1,195.3	$       -	$ 2,424.7	$4,796.3	$(4,770.5)	$12,569.1
Cash flows for total   investments in plant	$   400.9	$      74.6	$247.0	$23.2	$29.7	$           -	$    775.4

	For the Year Ended December 31, 2004
	Utility Group
	Distribution
(Millions of Dollars)	Electric	Gas	Transmission	NU Enterprises	Other	Eliminations	Total
Operating revenues	$4,040.0	$  407.8	$140.7	$2,709.7	$   289.6	$(1,045.7)	$6,542.1
Depreciation and amortization	(458.5)	(26.2)	(21.6)	(18.4)	(16.4)	13.8	(527.3)
Other operating expenses	(3,273.0)	(347.5)	(68.5)	(2,677.8)	(284.5)	1,038.7	(5,612.6)
Operating income/(loss)	308.5	34.1	50.6	13.5	(11.3)	6.8	402.2
Interest expense, net of AFUDC	(159.1)	(16.6)	(12.3)	(44.5)	(26.3)	11.3	(247.5)
Interest income	4.8	0.1	0.3	2.1	17.0	(13.0)	11.3
Other income/(loss), net	20.2	(0.5)	(0.2)	(5.1)	85.5	(96.6)	3.3
Income tax (expense)/benefit	(56.8)	(3.0)	(8.9)	15.3	15.3	(12.6)	(50.7)
Preferred dividends	(5.6)	-	-	-	-	-	(5.6)
Income/(loss) from   continuing operations	112.0	14.1	29.5	(18.7)	80.2	(104.1)	113.0
Income from discontinued operations	-	-	-	3.6	-	-	3.6
Net income/(loss)	$   112.0	$     14.1	$  29.5	$   (15.1)	$     80.2	$   (104.1)	$     116.6
Total assets (1)	$8,393.3	$1,147.9	$        -	$2,176.2	$4,313.1	$(4,392.1)	$11,638.4
Cash flows for total   investments in plant	$   408.7	$     59.5	$172.3	$     17.6	$     13.4	$            -	$     671.5

(1)

Information for segmenting total assets between electric distribution and transmission is not available at December 31, 2005 or December 31, 2004.  On a NU consolidated basis, these distribution and transmission assets are disclosed in the electric distribution columns above.  

	For the Year Ended  December 31, 2003
	Utility Group
	Distribution
(Millions of Dollars)	Electric	Gas	Transmission	NU Enterprises	Other	Eliminations	Total
Operating revenues	$  3,865.8	$   361.5	$117.9	$2,450.0	$    257.9	$(1,109.6)	$   5,943.5
Depreciation and amortization	(483.8)	(23.4)	(18.7)	(18.8)	(14.2)	10.4	(548.5)
Other operating expenses	(3,079.4)	(312.7)	(51.9)	(2,395.2)	(238.2)	1,088.5	(4,988.9)
Operating income/(loss)	302.6	25.4	47.3	36.0	5.5	(10.7)	406.1
Interest expense, net of AFUDC	(166.2)	(13.1)	(3.5)	(43.1)	(23.5)	8.8	(240.6)
Interest income	3.8	-	0.1	1.2	9.4	(9.5)	5.0
Other income/(loss), net	7.2	(1.4)	(0.9)	(3.3)	100.2	(102.7)	(0.9)
Income tax (expense)/benefit	(44.8)	(3.6)	(14.8)	1.1	14.6	(0.1)	(47.6)
Preferred dividends	(5.6)	-	-	-	-	-	(5.6)
Income/(loss) from   continuing operations	97.0	7.3	28.2	(8.1)	106.2	(114.2)	116.4
Income from discontinued operations	-	-	-	4.7	-	-	4.7
Income/(loss) before cumulative   effect of accounting change	97.0	7.3	28.2	(3.4)	106.2	(114.2)	121.1
Cumulative effect of accounting   change, net of tax benefit	-	-	-	-	(4.7)	-	(4.7)
Net income/(loss)	$       97.0	$       7.3	$  28.2	$     (3.4)	$   101.5	$   (114.2)	$     116.4
Cash flows for total   investments in plant	$     361.2	$     49.7	$  95.3	$     18.7	$     33.2	$            -	$    558.1

NU Enterprises' segment information for the years ended December 31, 2005, 2004, and 2003 is as follows.  Eliminations are included in the services and other columns.  

	NU Enterprises – For the Year Ended December 31, 2005
(Millions of Dollars)	Merchant Energy	Services and Other	Total
Operating revenues	$1,869.0	$ 94.6	$1,963.6
Wholesale contract market charges, net	(440.9)	-	(440.9)
Restructuring and impairment charges	(27.1)	(17.0)	(44.1)
Depreciation and amortization	(13.9)	(0.8)	(14.7)
Other operating expenses	(1,902.3)	(99.1)	(2,001.4)
Operating loss	(515.2)	(22.3)	(537.5)
Interest expense	(49.2)	(0.5)	(49.7)
Interest income	5.4	1.2	6.6
Other loss, net	(5.6)	-	(5.6)
Income tax benefit	205.0	7.3	212.3
Loss from continuing operations	(359.6)	(14.3)	(373.9)
Loss from discontinued operations	-	(23.3)	(23.3)
Loss before cumulative effect  of accounting change	(359.6)	(37.6)	(397.2)
Cumulative effect of accounting  change, net of tax benefit	(1.0)	- -	(1.0)
Net loss	$  (360.6)	$ (37.6)	$ (398.2)
Total assets	$ 2,222.2	$ 202.5	$2,424.7
Cash flows for total investments in plant	$      23.2	$        -	$     23.2

	NU Enterprises – For the Year Ended December 31, 2004
(Millions of Dollars)	Merchant Energy	Services and Other	Total
Operating revenues	$2,599.4	$110.3	$2,709.7
Depreciation and amortization	(17.6)	(0.8)	(18.4)
Other operating expenses	(2,564.8)	(113.0)	(2,677.8)
Operating income/(loss)	17.0	(3.5)	13.5
Interest expense	(44.3)	(0.2)	(44.5)
Interest income	1.7	0.4	2.1
Other loss, net	(2.6)	(2.5)	(5.1)
Income tax benefit	10.9	4.4	15.3
Loss from continuing operations	(17.3)	(1.4)	(18.7)
Income from discontinued operations	-	3.6	3.6
Net (loss)/income	$   (17.3)	$    2.2	$   (15.1)
Total assets	$1,914.2	$262.0	$2,176.2
Cash flows for total investments in plant	$     17.6	$        -	$     17.6

	NU Enterprises – For the Year Ended December 31, 2003
(Millions of Dollars)	Merchant Energy	Services and Other	Total
Operating revenues	$2,369.4	$  80.6	$2,450.0
Depreciation and amortization	(18.0)	(0.8)	(18.8)
Other operating expenses	(2,311.1)	(84.1)	(2,395.2)
Operating income/(loss)	40.3	(4.3)	36.0
Interest expense	(43.0)	(0.1)	(43.1)
Interest income	1.1	0.1	1.2
Other (loss)/income, net	(5.4)	2.1	(3.3)
Income tax expense	0.3	0.8	1.1
Loss from continuing operations	(6.7)	(1.4)	(8.1)
Income from discontinued operations	-	4.7	4.7
Net (loss)/income	$ (6.7)	$    3.3	$     (3.4)
Cash flows for total investment in plant	$ 18.7	$        -	$     18.7

Consolidated Statements Of Quarterly Financial Data (Unaudited)

	Quarter Ended (a)(b)(c)
(Thousands of Dollars, except per share information)	March 31,	June 30,	September 30,	December 31,
2005
Operating Revenues	$2,233,265	$1,531,429	$1,754,862	$1,877,834
Operating (Loss)/Income	(91,953)	14,348	(62,580)	(13,680)
Loss from Continuing Operations	(100,489)	(26,052)	(91,959)	(10,723)
Loss from Discontinued Operations	(17,230)	(1,652)	(2,533)	(1,845)
Cumulative effect of accounting change, net of tax benefit	-	-	-	(1,005)
Net Loss	(117,719)	(27,704)	(94,492)	(13,573)
Basic and Fully Diluted Loss Per Common Share:
Loss from Continuing Operations	(0.78)	(0.20)	(0.71)	(0.08)
Loss from Discontinued Operations	(0.13)	(0.01)	(0.02)	(0.01)
Cumulative effect of accounting change, net of tax benefit	-	-	-	(0.01)
Net Loss	(0.91)	(0.21)	(0.73)	(0.10)
2004
Operating Revenues	$1,799,291	$1,485,060	$1,624,487	$1,633,282
Operating Income	170,882	97,462	31,377	102,496
Income/(Loss) from Continuing Operations	67,668	25,583	(9,297)	29,041
Net (Loss)/Income from Discontinued Operations	(226)	(1,591)	1,389	4,021
Net Income/(Loss)	67,442	23,992	(7,908)	33,062
Basic and Fully Diluted Earnings/(Loss) Per Common Share:
Income/(Loss) from Continuing Operations	0.53	0.20	(0.07)	0.23
Net (Loss)/Income from Discontinued Operations	-	(0.01)	0.01	0.03
Net Income/(Loss)	0.53	0.19	(0.06)	0.26

(a)

The summation of quarterly earnings per share data may not equal annual data due to rounding.  

(b)

Amounts differ from those previously reported as a result of the presentation of discontinued operations as a result of meeting certain criteria requiring this presentation in the third quarter of 2005.  

(c)

Quarterly operating (loss)/income amounts differ from those previously reported as a result of the change in classification of certain costs that were not recoverable from regulated customers.  These amounts, previously presented in other income, net, have been reclassified to other operation expenses and are summarized as follows (thousands of dollars):  

Quarter Ended	2005	2004
March 31,	$  (374)	$(1,309)
June 30,	(2,241)	(1,427)
September 30,	(1,209)	(2,075)

The amount for the second quarter of 2005 also includes an additional reclassification totaling $0.8 million related to an additional reclassification from other income, net to other operation expenses.  

Selected Consolidated Financial Data (Unaudited)

(Thousands of Dollars, except percentages and share information)	2005		2004		2003		2002		2001
Balance Sheet Data:
Property, Plant and Equipment, Net	$6,417,230		$ 5,864,161		$   5,429,916		$ 5,049,369		$ 4,472,977
Total Assets (a)	12,569,075		11,638,396		11,216,487		10,764,880		10,331,923
Total Capitalization (b)	5,595,405		5,293,644		4,926,587		4,670,771		4,576,858
Obligations Under Capital Leases (b)	13,987		14,806		15,938		16,803		17,539
Income Data:
Operating Revenues	$7,397,390		$6,542,120		$5,943,514		$5,161,091		$5,692,094
(Loss)/Income from Continuing Operations	(229,223)		112,995		116,434		148,529		263,453
(Loss)/Income from Discontinued Operations	(23,260)		3,593		4,718		3,580		2,489
(Loss)/Income Before Cumulative Effects of Accounting Changes,      Net of Tax Benefits	(252,483)		116,588		121,152		152,109		265,942
Cumulative Effects of Accounting Changes, Net of Tax Benefits	(1,005)		-		(4,741)		-		(22,432)
Net (Loss)/Income	$(253,488)		$  116,588		$      116,411		$    152,109		$    243,510
Common Share Data:
Basic and Fully Diluted (Loss)/Earnings Per Common Share:
(Loss)/Income from Continuing Operations	$(1.74)		$0.88		$0.91		$1.15		$1.94
(Loss)/Income from Discontinued Operations	(0.18)		0.03		0.04		0.03		0.03
Cumulative Effects of Accounting Changes, Net of Tax Benefits	(0.01)		-		(0.04)		-		(0.17)
Net (Loss)/Income	$(1.93)		$0.91		$0.91		$1.18		$1.80
Basic Common Shares Outstanding (Average)	131,638,953		128,245,860		127,114,743		129,150,549		135,632,126
Fully Diluted Common Shares Outstanding  (Average)	131,638,953		128,396,076		127,240,724		129,341,360		135,917,423
Dividends Per Share	$  0.68		$  0.63		$  0.58		$  0.53		$  0.45
Market Price - Closing (high) (c)	$21.79		$20.10		$20.17		$20.57		$23.75
Market Price - Closing (low) (c)	$17.61		$17.30		$13.38		$13.20		$16.80
Market Price - Closing (end of year) (c)	$19.69		$18.85		$20.17		$15.17		$17.63
Book Value Per Share (end of year)	$15.85		$17.80		$17.73		$17.33		$16.27
Tangible Book Value Per Share (end of year)	$13.98		$15.17		$15.05		$14.62		$13.71
Rate of Return Earned on Average Common Equity (%)	(10.7)		5.1		5.2		7.0		11.2
Market-to-Book Ratio (end of year)	1.2		1.1		1.1		0.9		1.1
Capitalization:
Common Shareholders’ Equity	43	%	44	%	46	%	47	%	46	%
Preferred Stock (b) (d)	2		2		2		3		3
Long-Term Debt (b)	55		54		52		50		51
	100	%	100	%	100	%	100	%	100	%

(a)

Total assets were not adjusted for cost of removal prior to 2002.

(b)

Includes portions due within one year.

(c)

Market price information reflects closing prices as reflected by the New York Stock Exchange.

(d)

Excludes $100 million of Monthly Income Preferred Securities.

Consolidated Sales Statistics (Unaudited)
	2005		2004		2003		2002		2001
Revenues:  (Thousands)
Utility Group:
Residential	$2,080,395		$1,707,434		$1,669,199		$1,512,397		$1,490,487
Commercial	1,727,278		1,429,608		1,411,881		1,298,939		1,310,701
Industrial	577,834		513,999		514,076		485,591		544,806
Wholesale	411,361		344,254		405,120		567,608		854,002
Streetlighting and Railroads	47,769		41,976		44,977		43,679		43,889
Miscellaneous and eliminations	159,402		143,431		(61,564)		(84,513)		52,794
Total Electric	5,004,039		4,180,702		3,983,689		3,823,701		4,296,679
Total Gas	503,303		407,812		361,470		281,206		378,033
Total - Utility Group	$5,507,342		$4,588,514		$4,345,159		$4,104,907		$4,674,712
NU Enterprises:
Retail	$1,212,176		$   857,355		$  660,145		$   508,734		$  209,838
Wholesale (a)	644,541		1,722,603		1,684,448		1,108,370		1,675,647
Generation	210,833		196,191		185,493		170,143		184,878
Services	153,844		178,854		143,403		220,638		213,996
Miscellaneous and eliminations	(257,750)		(245,275)		(223,440)		(207,062)		(209,435)
Total - NU Enterprises	$ 1,963,644		$2,709,728		$2,450,049		$1,800,823		$2,074,924
Other miscellaneous and eliminations	(73,596)		(756,122)		(851,694)		(668,730)		(988,687)
Total	$7,397,390		$6,542,120		$5,943,514		$5,237,000		$5,760,949
Utility Group Sales:  (kWh - Millions)
Residential	15,518		14,866		14,824		13,923		13,322
Commercial	15,234		14,710		14,471		14,103		13,751
Industrial	6,023		6,274		6,223		6,265		6,790
Wholesale	4,856		5,787		6,813		15,915		21,239
Streetlighting and Railroads	348		348		348		344		332
Total	41,979		41,985		42,679		50,550		55,434
Utility Group Customers:  (Average)
Residential	1,674,563		1,659,419		1,631,582		1,614,239		1,610,154
Commercial	195,844		194,233		186,792		183,577		171,218
Industrial	7,638		7,752		7,644		7,763		7,730
Wholesale	3,912		3,930		3,858		3,949		3,969
Total Electric	1,881,957		1,865,334		1,829,876		1,809,528		1,793,071
Gas	196,870		194,212		192,816		190,855		190,998
Total	2,078,827		2,059,546		2,022,692		2,000,383		1,984,069
Utility Group - Average Annual Use Per     Residential Customer (kWh)	9,267		8,960		9,087		8,611		8,251
Utility Group - Average Annual Bill Per Residential Customer	$1,242.38		$1,028.97		$1,024.20		$    934.90		$    923.70
Utility Group - Average Revenue Per kWh:
Residential	13.41	¢	11.48	¢	11.27	¢	10.86	¢	11.20	¢
Commercial	11.34		9.70		9.74		9.18		9.48
Industrial	9.59		8.19		8.26		7.75		8.10

(a)

Operating revenue amounts for 2002 through 2005 reflect the application of EITF Issue No. 03-11.  Operating revenue amounts prior to 2002 have not been reclassified.  

EX-13.1

Exhibit 13.1

Management’s Discussion and Analysis

Financial Condition and Business Analysis

Executive Summary

The following items in this executive summary are explained in more detail in this annual report.

Results:

·

The Connecticut Light and Power Company (CL&P or the company) reported earnings of $94.8 million in 2005 compared to $88 million in 2004 and $68.9 million in 2003.  Included in earnings were transmission earnings of $30.7 million, $19.8 million and $17.1 million in 2005, 2004 and 2003, respectively, and distribution earnings of $64.1 million, $68.2 million and $51.8 million in 2005, 2004 and 2003, respectively.

Legislative Items:

·

On July 6, 2005, Connecticut adopted legislation creating a mechanism to true-up annually the retail transmission charge in local electric distribution company rates.  In accordance with this legislation, effective January 1, 2006, CL&P raised its retail transmission rate to collect $21 million of additional revenues over the first six months of 2006.

·

On July 22, 2005, Connecticut also adopted legislation that provides local electric distribution companies, including CL&P, with financial incentives to promote construction of distributed generation and also provides such companies with the possibility of owning generation on a limited basis.  The Connecticut Department of Public Utility Control (DPUC) is conducting a number of new dockets to implement this legislation.

·

On August 8, 2005, President Bush signed into law comprehensive federal energy legislation with several provisions affecting CL&P. As part of this legislation, the Public Utility Holding Company Act of 1935 (PUHCA) was repealed.  Some but not all of the Securities and Exchange Commission's (SEC) responsibilities under PUHCA were transferred to the Federal Energy Regulatory Commission (FERC).  

Regulatory Items:

·

CL&P has received regulatory approval to recover the increased cost of energy being supplied to its customers in 2006.  This increased cost is primarily the result of increased fuel and purchased power costs.  

·

On December 1, 2005, CL&P filed at the FERC a request to include 50 percent of construction work in progress (CWIP) for its four major southwest Connecticut transmission projects in its formula rate for transmission service.  The FERC approved the filing with the new rates, including CWIP, effective on February 1, 2006.  The new rates allow CL&P to collect 50 percent of the construction financing expenses while these projects are under construction.

·

A final decision in the 2004 Competitive Transition Assessment (CTA) and System Benefits Charge (SBC) docket was issued on December 19, 2005 by the DPUC.  In a subsequent decision in CL&P’s docket to establish the 2006 transitional standard offer (TSO) rates dated December 28, 2005, the DPUC ordered CL&P to issue a revised CTA refund of $108 million over the twelve-month period beginning with January 2006 consumption and an additional CTA refund of $40 million for the months of January, February and March of 2006.

·

On March 6, 2006, the New England Independent System Operator (ISO-NE) and a broad cross-section of critical stakeholders from around the region, including CL&P, filed a comprehensive settlement agreement at the FERC implementing a Forward Capacity Market (FCM) in place of Locational Installed Capacity (LICAP).  The settlement agreement must be approved by the FERC, and the parties have asked for a decision by June 30, 2006.

Liquidity:

·

On April 7, 2005, CL&P closed on the sale of $100 million of 10-year first mortgage bonds and $100 million of 30-year first mortgage bonds.

·

In 2005, CL&P's capital expenditures totaled $444.4 million compared with $389.3 million in 2004.  The increased level of capital expenditures was caused primarily by a need to continue to improve the capacity and reliability of CL&P's transmission system.  

·

Cash flows from operations increased by $143.4 million to $297.3 million in 2005 from $153.9 million in 2004.

Overview

CL&P is a wholly owned subsidiary of Northeast Utilities (NU).  NU’s other regulated electric subsidiaries include Public Service Company of New Hampshire (PSNH) and Western Massachusetts Electric Company (WMECO).  

CL&P earned $94.8 million in 2005, compared with $88 million in 2004 and $68.9 million in 2003.  The 2005 decline in CL&P’s distribution earnings to $64.1 million in 2005 from $68.2 million in 2004 resulted from the after-tax employee termination and benefit plan curtailment charges totaling $8.5 million, and higher operation, interest and depreciation expenses, partially offset by a $25 million distribution rate increase that took effect January 1, 2005 and a 3 percent increase in retail electric sales.

The 2005 increase in CL&P's transmission earnings to $30.7 million from $19.8 million in 2004, resulted primarily from increased investment in its transmission system.  CL&P's retail electric sales were positively impacted by weather in 2005, particularly by an unseasonably hotter than average third quarter of 2005, which increased electricity consumption.  CL&P's retail electric sales increased by only 0.1 percent over 2004 on a weather-adjusted basis.  

With a commodity-driven increase taking effect early in 2006 and the weather being much milder to date in 2006, management is concerned that actual sales could be lower in 2006 than in 2005.  While sales volume does not affect transmission business earnings positively or negatively, lower electric sales do negatively affect distribution company earnings.

Liquidity

Cash flows from operations increased by $143.4 million to $297.3 million in 2005 from $153.9 million in 2004.  The increase in cash flows is primarily due to a decrease in regulatory refunds, an increase in accounts payable related to the timing of payments to standard offer suppliers and a decrease in tax payments.

Cash flows from operations decreased by $351.9 million from $505.8 million in 2003 to $153.9 million in 2004.  The decrease in year over year operating cash flows is due to regulatory (refunds)/over-recoveries primarily due to lower CTA and generation service charge (GSC) collections in 2004 as CL&P refunds amounts to its ratepayers for past overcollections or uses those amounts to recover current costs.  These refunds are also the primary reason for the positive change in year over year deferred income taxes, which has increased operating cash flows as refunded amounts were currently deducted for tax purposes.  The change in lower current taxes paid because of income taxes also benefited cash flows from operations in 2004 due to bonus tax depreciation on newly completed plant assets.  

On April 7, 2005, CL&P sold $100 million of 10-year first mortgage bonds carrying a coupon rate of 5.00 percent and $100 million of 30-year first mortgage bonds carrying a coupon rate of 5.625 percent.  Proceeds were used to repay short-term borrowings used to finance capital expenditures.

On December 9, 2005, CL&P amended its 5-year unsecured revolving credit facility by extending the termination date by one year to November 6, 2010.  Under this facility, CL&P can borrow up to $200 million on a short-term basis, or subject to regulatory approvals, on a long-term basis.  At December 31, 2005, there were no borrowings outstanding under this facility.  At December 31, 2004, there were $15 million in borrowings under this credit facility.

In addition to its revolving credit line, CL&P has an arrangement with a financial institution under which CL&P can sell up to $100 million of accounts receivable and unbilled revenues.  At December 31, 2005, CL&P had sold $80 million to that financial institution.  For more information regarding the sale of receivables, see Note 1L, "Summary of Significant Accounting Policies - Sale of Receivables" to the consolidated financial statements.

CL&P's senior secured debt is rated A3, BBB+, and A- by Moody's Investors Service (Moody's), Standard & Poor's (S&P), and Fitch Ratings, respectively.  All outlooks are stable.

In 2005, CL&P paid approximately $53.8 million to NU in the form of common dividends.

Capital expenditures described herein are cash capital expenditures and do not include cost of removal, allowance for funds used during construction (AFUDC), and the capitalized portion of pension expense or income.  CL&P's capital expenditures totaled $444.4 million in 2005, compared with $389.3 million in 2004 and $318.5 million in 2003.  The increase in CL&P's capital expenditures was primarily the result of higher transmission capital expenditures.  

CL&P expects to fund approximately half of its expected capital expenditures over the next several years through internally generated cash flows.  As a result, CL&P expects to issue debt regularly.  

Business Development and Capital Expenditures

In 2005, CL&P’s capital expenditures totaled $444.4 million compared with $389.3 million in 2004 and $318.5 million in 2003.  In 2006, capital expenditures are projected to approach $600 million and approximately $2.5 billion from 2007 through 2010.  The increasing level of capital expenditures relates to the need to continue to improve the capacity and reliability of CL&P’s transmission system.  That increased level of capital expenditures is increasing the amount of plant in service and CL&P’s earnings base, provided CL&P achieves timely recovery of its investment.  Unless otherwise noted, the capital expenditure amounts below exclude AFUDC.  

In 2005, CL&P's distribution capital expenditures totaled $236.6 million, compared with $254.7 million in 2004 and $255.9 million in 2003.  In 2006, CL&P projects distribution capital expenditures of approximately $200 million and approximately $1 billion from 2007 through 2010.  In December of 2003, the DPUC approved a total of $900 million of distribution capital expenditures for CL&P from 2004 through 2007.  Those expenditures are intended to improve the reliability of the distribution system and to meet growth requirements on the distribution system.  

CL&P’s transmission capital expenditures totaled $207.8 million in 2005, compared with $134.6 million in 2004 and $62.6 million in 2003.  The increase in CL&P's transmission capital expenditures in 2005 was primarily the result of increased spending on a new 21-mile 345

kilovolt (kV) transmission project between Bethel, Connecticut and Norwalk, Connecticut.  In 2006, CL&P's transmission capital expenditures are projected to total approximately $400 million and approximately $1.5 billion from 2007 through 2010.  

Transmission capital expenditures in Connecticut are focused primarily on four major transmission projects in southwest Connecticut.  These projects include 1) the Bethel to Norwalk project noted above, 2) a Middletown to Norwalk 345 kV transmission project, 3) a related 115 kV underground project (Glenbrook Cables), and 4) the replacement of the existing 138 kV cable between Connecticut and Long Island.  Each of these projects has received approval from the Connecticut Siting Council (CSC) and ISO-NE.  Capital expenditures for these projects in southwest Connecticut totaled $156 million (including AFUDC) in 2005 out of the $207.8 million ($257.3 million including AFUDC) in total transmission and other capital expenditures in 2005.  

Underground line construction activities began in April of 2005 on a 21-mile 115 kV/345 kV line project between Bethel and Norwalk, with overhead line work commencing in September of 2005.  The first substation (Plumtree) was successfully energized on September 23, 2005.  The first 6.2 mile section of 115 kV cable was energized in the fourth quarter of 2005.  This project is expected to cost approximately $350 million of which CL&P spent $130.7 million (including AFUDC) in 2005.  The project is approximately 70 percent complete and CL&P had capitalized $196 million associated with the project through December 31, 2005.  This project is expected to be completed by the end of 2006.

On April 7, 2005, the CSC unanimously approved a proposal by CL&P and United Illuminating to build a 69-mile 345 kV transmission line from Middletown to Norwalk, Connecticut.  Approximately 24 miles of the 345 kV line will be built underground with the balance being built overhead.  The project still requires CSC review of detailed construction plans, as well as United States Army Corps of Engineers approval to bury the line beneath certain navigable rivers and Department of Environmental Protection (DEP) approvals.  The CSC decision included provisions for low-magnetic field designs in certain areas and made variations to the proposed route.  CL&P's portion of the project is estimated to cost approximately $1.05 billion.  CL&P received final technical approval from ISO-NE on January 20, 2006 and expects to award the major construction-related contracts during the second quarter of 2006.  CL&P expects th e project to be completed by the end of 2009.  Legal review of three appeals related to this project is ongoing.  At this time, CL&P does not expect any of these three appeals to delay construction.  At December 31, 2005, CL&P has capitalized $41 million associated with this project.

CL&P’s construction of the Glenbrook Cables Project, two 115 kV underground transmission lines between Norwalk and Stamford, Connecticut, was approved by the CSC on July 20, 2005 and by ISO-NE on August 3, 2005.  There were no court appeals of the project, which is expected to cost approximately $120 million and help meet growing electric demands in the area.  Management expects to begin construction during 2007 and expects the lines to be in service during 2008.  At December 31, 2005, CL&P has capitalized $7 million associated with this project.

On October 1, 2004, CL&P and the Long Island Power Authority (LIPA) jointly filed plans with the Connecticut DEP to replace an undersea 13-mile electric transmission line between Norwalk, Connecticut and Northport - Long Island, New York, consistent with a comprehensive settlement agreement reached on June 24, 2004.  CL&P and LIPA each own approximately 50 percent of the line.  On June 20, 2005, the New York State Controller’s Officer and the New York State Attorney General approved the settlement agreement between CL&P and LIPA to replace the cable and the project had earlier received CSC approval.  State and federal permits are expected to be issued in the second quarter of 2006.  Assuming these permits are received by no later than the second quarter of 2006 and the necessary construction contracts are signed, construction activities will begin when material lead times allow.  Management will provide the estim ated removal and in service dates when these construction contracts are signed.  At December 31, 2005, CL&P has capitalized $6 million associated with this project.

In the fourth quarter of 2005, CL&P began construction of a new substation in Killingly, Connecticut that will improve CL&P’s 345 kV and 115 kV transmission systems in northeast Connecticut.  The project is expected to be completed by the end of 2006 at a cost of approximately $32 million.  At December 31, 2005, CL&P has capitalized $2.5 million associated with this project.

During 2005, CL&P placed in service $175 million of electric transmission projects, including $70 million related to the Bethel to Norwalk project.

Transmission Access and FERC Regulatory Changes

In January of 2005, the New England transmission owners approved activation of the New England Regional Transmission Organization (RTO) which occurred on February 1, 2005.  CL&P is now a member of the New England RTO and provides regional open access transmission service over its transmission system under the ISO-NE Transmission, Markets and Services Tariff, FERC Electric Tariff No. 3 and local open access transmission service under the ISO-NE Transmission, Markets and Services Tariff, FERC Electric No. 3, Schedule 21 - NU.

As a result of the RTO start-up on February 1, 2005, the return on equity (ROE) in the local network service (LNS) tariff was increased to 12.8 percent.  The ROE being utilized in the calculation of the current New England Regional Network Service (RNS) rates is the sum of the 12.8 percent "base" ROE, plus a 50 basis point incentive adder for joining the RTO, or a total of 13.3 percent.  An initial decision by a FERC administrative law judge (ALJ) has set the base ROE at 10.72 percent as compared with the 12.8 percent requested by the New England RTO.  One of the adjustments made by the ALJ was to modify the underlying proxy group used to determine the ROE, resulting in a reduction in the base ROE of approximately 50 basis points.  The ALJ deferred to the FERC for final resolution on the 100 basis point incentive adder for new transmission investments but reaffirmed the 50 basis point incentive for joining the RTO.  The New England transmission owners have challenged the ALJ’s findings and recommendations through written exceptions filed on June 27, 2005 and a final order from the FERC is expected in 2006.  The result of this order, if upheld by the FERC, would be an ROE for LNS of 10.72 percent and an ROE for RNS of 11.22 percent.  When blended, the resulting "all in" ROE would be approximately 11.15 percent for the NU transmission business.  Management cannot at this time predict what ROE will ultimately be established by the FERC in these proceedings but for purposes of current earnings accruals and estimates, the transmission business is assuming an ROE of 11.5 percent.

In November of 2005, the FERC announced that it was considering a number of proposals to provide financial incentives for the construction of high-voltage electric transmission in the United States.  Those proposals included reflecting in rate base 100 percent of CWIP; accelerated recovery of depreciation; imputing hypothetical capital structures in ratemaking; establishing ROEs for transmission owners that join RTOs; and other incentives that could improve the earnings and/or cash flows associated with CL&P's transmission capital expenditures.  Comments on the FERC proposals were submitted in January of 2006 and final rules are expected by the summer of 2006.  

Legislative Matters

Federal Energy Legislation:  On August 8, 2005, President Bush signed into law comprehensive energy legislation.  Among provisions potentially affecting CL&P are the repeal of PUHCA, FERC backstop siting authority for transmission, transmission pricing and rate reform, renewable production tax credits, and accelerated depreciation for certain new electric and gas facilities.  The accelerated depreciation provision, assuming timely rate recovery, is expected to increase CL&P cash flows by more than $4.5 million annually.  As part of this legislation, some but not all of the SEC's responsibilities under PUHCA were transferred to the FERC.

Transmission Tracking Mechanism:  On July 6, 2005, Connecticut adopted legislation creating a mechanism to allow the DPUC to true-up, at least annually, the retail transmission charge in local electric distribution company rates based on changes in FERC-approved charges.  This mechanism allows CL&P to include forward-looking transmission charges in its retail transmission rate and promptly recover its transmission expenditures.  On December 20, 2005, the DPUC approved CL&P’s August 1, 2005 proposal to implement the mechanism effective July 1, 2005, which includes two adjustments annually, in January and June.  On January 1, 2006, consistent with that approval, CL&P raised its retail transmission rate to collect $21 million of additional revenues over the first six months of 2006.  

Energy Legislation:  Public Act 05-01, an "Act Concerning Energy Independence," (Act) was signed by Governor Rell on July 22, 2005.  The new legislation provides incentives to encourage the construction of distributed generation, new large-scale generation, and conservation and load management initiatives to reduce federally mandated congestion charges (FMCC) charges.  FMCC charges represent the costs of power market rules approved by the FERC that are resulting in significantly higher costs for Connecticut.  The most significant cost item in 2005 is reliability must run (RMR) contracts.  The legislation requires regulators to a) implement near-term measures as soon as possible, and b) commence a new request for proposals to build customer side distributed resources and contracts for new or repowered larger generating facilities in the state.  Developers could receive contracts of up to 15 years from the dis tribution companies.  The legislation provides utilities with the opportunity to earn one-time awards for generation that is installed in their service territories. Those awards can be as high as $200 per kilowatt for distributed generation and $25 per kilowatt for more traditional generation.  It also allows distribution companies, such as CL&P, to bid as much as 250 megawatts (MW) of capacity into the request for proposals.  If such utility bid was accepted, then the unit after five years would have to be a) sold, b) have its capacity sold, or c) both, provided that the DPUC could waive these requirements.  The DPUC is conducting a number of new dockets to implement this legislation.  The legislation also requires the DPUC to investigate the financial impact on distribution companies of entering into long-term contracts and to allow distribution companies to recover through rates any increased costs.  The DPUC ruled that at this point the impact is hypothetical and instruc ted the utilities to raise the issue in subsequent rate cases.

Regulatory Issues and Rate Matters

Transmission - Wholesale Rates:  Wholesale transmission revenues are based on rates and formulas that are approved by the FERC.  Most of CL&P’s wholesale transmission revenues are collected through a combination of the RNS tariff and CL&P’s LNS tariff.  CL&P’s LNS rate is reset on January 1 and June 1 of each year.  CL&P's RNS rate is reset on June 1 of each year.  On January 1, 2006, CL&P's LNS rates increased CL&P's wholesale revenues by approximately $10.4 million on an annualized basis.  The LNS and RNS rates to be effective on June 1, 2006 have not yet been determined.  Additionally, CL&P's LNS tariff provides for a true-up to actual costs, which ensures that CL&P's transmission business recovers its total transmission revenue requirements, including the allowed ROE.  At December 31, 2005, this true-up resulted in the recognition of a $1.3 million regulatory liability.  

On December 1, 2005, CL&P filed at the FERC a request to include 50 percent of CWIP for its four major southwest Connecticut transmission projects in its formula rate for transmission service (Schedule 21 – NU (LNS)).  The FERC approved the filing with new rates effective on February 1, 2006.  The new rates allow CL&P to collect 50 percent of the construction financing expenses while these projects are under construction.  

Transmission - Retail Rates:  A significant portion of transmission business revenue comes from ISO-NE charges to the distribution businesses of CL&P.  The distribution business recovers these costs through the retail rates that are charged to their retail customers.  In July of 2005, CL&P began tracking its retail transmission revenues and expenses.  CL&P filed for a transmission adjustment clause on August 1, 2005 with the rate tracking mechanism effective on July 1, 2005.  The DPUC approved the mechanism on December 20, 2005.  On January 1, 2006, consistent with that approval, CL&P raised its retail transmission rate to collect $21 million of additional revenues over the first six months of 2006.  CL&P adjusts its retail transmission rates on a regular basis, thereby recovering all of its retail transmission expenses on a timely basis.  This new tracking mechanism resulted from th e enactment of the new legislation passed by the Connecticut legislature in 2005.

LICAP:  In March of 2004, ISO-NE proposed at the FERC an administratively determined electric generation capacity pricing mechanism known as LICAP, intended to provide a revenue stream sufficient to maintain existing generation assets and encourage the construction of new generation assets at levels sufficient to serve peak load, plus fixed reserve and contingency margins.

After opposition from state regulators, utilities and various Congressional delegations, the FERC ordered settlement negotiations before an ALJ to determine whether there was an acceptable alternative to LICAP.  On March 6, 2006, ISO-NE and a broad cross-section of critical stakeholders from around the region, including CL&P, filed a comprehensive settlement agreement at the FERC implementing a FCM in place of LICAP.  The settlement agreement provides for a fixed level of compensation to generators from December 1, 2006 through May 31,

2010 without regard to location in New England, and annual forward capacity auctions, beginning in 2008, for the 1-year period ending on May 31, 2011, and annually thereafter.  The settlement agreement must be approved by the FERC, and the parties have asked for a decision by June 30, 2006.  According to preliminary estimates, FCM would require CL&P to pay approximately $470 million during the 3½-year transition period.  CL&P would be able to recover these costs from its customers through the FMCC mechanism.

Streetlighting Decision:  On June 30, 2005, the DPUC issued a final decision which required CL&P to recalculate all previously issued refunds (except the towns of Stamford and Middletown) utilizing applicable approved pre-tax cost of capital rates.  The final decision also provided for a five-year period for those towns that wish to phase in the purchase of their streetlights in which they can complete the asset purchase.  As a result of this decision, CL&P recorded an additional $7.4 million pre-tax reserve for streetlight billing in the second quarter of 2005 and subsequently reduced the reserve by $3.3 million after submitting its compliance calculations and receiving approval from the DPUC.  The net impact in 2005 was an additional $4.1 million of pre-tax reserve.  CL&P filed an appeal of this decision on August 11, 2005 in the Connecticut Superior Court.  The court has not yet set a schedule for the a ppeal.  

Procurement Fee Rate Proceedings:  CL&P is currently allowed to collect a fixed procurement fee of 0.50 mills per kilowatt-hour (kWh) from customers who purchase TSO service through 2006. One mill is equal to one-tenth of a cent.  That fee can increase to 0.75 mills per kWh if CL&P outperforms certain regional benchmarks.  The fixed portion of the procurement fee amounted to approximately $12 million (approximately $7 million after-tax) for 2004.  CL&P submitted to the DPUC its proposed methodology to calculate the variable portion (incentive portion) of the procurement fee.  CL&P requested approval of $5.8 million for its 2004 incentive payment.  On December 8, 2005, a draft decision was issued in this docket, which accepted the methodology proposed by CL&P and authorized payment of the $5.8 million incentive fee.  The DPUC has not set a date for issuing a final decision.

CTA and SBC Reconciliation:  The CTA allows CL&P to recover stranded costs, such as securitization costs associated with the rate reduction bonds, amortization of regulatory assets, and independent power producer (IPP) over market costs, while the SBC allows CL&P to recover certain regulatory and energy public policy costs, such as public education outreach costs, hardship protection costs, transition period property taxes, and displaced worker protection costs.

A final decision in the 2004 CTA and SBC docket was issued on December 19, 2005 by the DPUC.  That decision ordered a refund to customers of $100.8 million over the twelve-month period beginning with January 2006 consumption.  In a subsequent decision in CL&P’s docket to establish the 2006 TSO rates dated December 28, 2005, the DPUC ordered CL&P to issue a revised CTA refund of $108 million over the twelve-month period beginning with January 2006 consumption and an additional CTA refund of $40 million for the months of January, February and March of 2006.  

In the 2001 CTA and SBC reconciliation filing, and subsequently in a September 10, 2002 petition to reopen related proceedings, CL&P requested that a deferred intercompany tax liability associated with the intercompany sale of generation assets be excluded from the calculation of CTA revenue requirements.  This liability is currently included as a reduction in the calculation CTA revenue requirements.  On September 10, 2003, the DPUC issued a final decision denying CL&P’s request, and on October 24, 2003, CL&P appealed the DPUC’s final decision to the Connecticut Superior Court.  The appeal has been fully briefed and argued.  If CL&P’s request is granted and upheld through these court proceedings, there would be additional amounts due to CL&P from its customers.  The amount due is contingent upon the findings of the court.  However, management believes that CL&P's pre-tax earnings would increase by a minimum of $15 million in 2006 if CL&P's position is adopted by the court.  

CL&P TSO Rates:  Most of CL&P’s customers buy their energy at CL&P’s TSO rate, rather than buying energy directly from competitive suppliers.  CL&P secured half of its 2006 TSO requirements during bidding in 2003 and 2004.  Bids to supply CL&P with its remaining 50 percent 2006 TSO requirements were received on November 15, 2005.  On December 29, 2005, the DPUC approved CL&P’s TSO rates for 2006.  As a result of significantly higher supplier bids for 2006, CL&P increased TSO rates by 17.5 percent on January 1, 2006 and will increase rates another 4.9 percent on April 1, 2006, representing a total increase of $676.5 million on an annualized basis.  

On December 22, 2004, the DPUC approved an increase of 16.2 percent in TSO rates effective January 1, 2005, although the impact was partially offset by a continuation of the CTA refund. The DPUC also ordered that projected 2004 and 2005 CTA overrecoveries and half of projected 2004 distribution overrecoveries be used to moderate increases for customers that otherwise would occur when the current CTA refund expired on May 1, 2005.  Overall, the final decision approved an increase to the January 2004 TSO rates of approximately 10.4 percent, including the effects of existing and new refunds and overrecoveries.  The DPUC denied requests by the Connecticut Attorney General and Office of Consumer Counsel (OCC) to defer the recovery of higher supplier costs into future years.  On February 3, 2005, the OCC filed an appeal with the Connecticut Superior Court challenging this decision, which was dismissed by the court on October 20, 2005.< /P>

Also, pursuant to state law, on December 19, 2003, the DPUC set CL&P’s TSO rates for January 1, 2004 through December 31, 2004 and confirmed that state law exempted FMCC charges, Energy Adjustment Clause (EAC) charges and certain other charges from the statutorily imposed rate cap.  The OCC filed appeals of this decision with the Connecticut Superior Court. The OCC claimed that the decision improperly implements an EAC charge under Connecticut law, fails to properly define and identify the fees that CL&P will be allowed to collect from customers and improperly calculates base rates for purposes of determining the rate cap.

On May 16, 2005, the DPUC approved a 4.8 percent increase to customer rates related to $79.8 million of additional RMR contract costs, which have been approved by the FERC.  This additional amount was recovered over the period June through December of 2005 through an increase to the FMCC rates effective June 1, 2005.  On August 24, 2005, the DPUC issued a final decision supporting the interim rate increase approved in May of 2005.  On February 1, 2006, CL&P filed with the DPUC its annual FMCC reconciliation filing for the year ended 2005.  No change in the current rates was proposed.  The DPUC has not set a schedule for review of this filing.  

Application for Issuance of Long-Term Debt:  On January 26, 2005, the DPUC approved CL&P's request to issue $600 million in long-term debt through December 31, 2007.  Additionally, the final decision approved CL&P's request to enter into hedging transactions in connection with any prospective or outstanding long-term debt in order to reduce the interest rate risk associated with the debt or debt issuances.  On April 7, 2005, CL&P closed on the sale of $200 million of first mortgage bonds with maturities ranging from 10 years to 30 years.  Proceeds were used to repay short-term borrowings.

Distribution Rates:  In its December 2003 rate case decision, the DPUC allowed CL&P to increase distribution rates annually from 2004 through 2007.  A $25 million distribution rate increase effective January 1, 2005, combined with strong hot weather driven third quarter sales, offset by after-tax employee termination and benefit plan curtailment charges totaling $8.5 million, resulted in CL&P earning a cost of capital ROE of 7.51 percent on its average distribution equity in 2005, compared with an allowed ROE of 9.85 percent.  An additional $11.9 million distribution rate increase took effect on January 1, 2006 and another $7 million distribution rate increase is due to take effect on January 1, 2007.  While these increases will help CL&P's performance, they may be inadequate to offset a possible combination of lower retail sales, higher employee-related expenses and higher costs related to the distribution cap ital investment program.

Deferred Contractual Obligations

FERC Proceedings:  In 2003, the Connecticut Yankee Atomic Power Company (CYAPC) increased the estimated decommissioning and plant closure costs for the period 2000 through 2023 by approximately $395 million over the April 2000 estimate of $436 million approved by the FERC in a 2000 rate case settlement.  The revised estimate reflects the increases in the projected costs of spent fuel storage, increased security and liability and property insurance costs, and the fact that CYAPC is now self performing all work to complete the decommissioning of the plant due to the termination of the decommissioning contract with Bechtel Power Corporation (Bechtel) in July of 2003.  CL&P's share of CYAPC's increase in decommissioning and plant closure costs is approximately $136 million.  On July 1, 2004, CYAPC filed with the FERC for recovery seeking to increase its annual decommissioning collections from $16.7 million to $93 million for a six-year period beginning on January 1, 2005.  On August 30, 2004, the FERC issued an order accepting the rates, with collection beginning on February 1, 2005, subject to refund.

Both the DPUC and Bechtel filed testimony in the FERC proceeding claiming that CYAPC was imprudent in its management of the decommissioning project.  In its testimony, the DPUC recommended a disallowance of $225 million to $234 million out of CYAPC's requested rate increase of approximately $395 million.  CL&P's share of the DPUC's recommended disallowance would be between $78 million to $81 million.  The FERC staff also filed testimony that recommended a $38 million decrease in the requested rate increase claiming that CYAPC should have used a different gross domestic product (GDP) escalator.  CL&P's share of this recommended decrease is $13.1 million.  

On November 22, 2005, a FERC ALJ issued an initial decision finding no imprudence on CYAPC's part.  However, the ALJ did agree with the FERC staff’s position that a lower GDP escalator should be used for calculating the rate increase and found that CYAPC should recalculate its decommissioning charges to reflect the lower escalator.  Briefs to the full FERC addressing these issues were filed in January and February of 2006, and a final order is expected later in 2006.  Management expects that if the FERC staff's position on the decommissioning GDP cost escalator is found by the FERC to be more appropriate than that used by CYAPC to develop its proposed rates, then CYAPC would review whether to reduce its estimated decommissioning obligation and reduce the customers' obligation, including CL&P.   

The company cannot at this time predict the timing or outcome of the FERC proceeding required for the collection of the increased CYAPC decommissioning costs.  The company believes that the costs have been prudently incurred and will ultimately be recovered from the customers of CL&P.  However, there is a risk that some portion of these increased costs may not be recovered, or will have to be refunded if recovered, as a result of the FERC proceedings.  

On June 10, 2004, the DPUC and the Connecticut OCC filed a petition seeking a declaratory order that CYAPC be allowed to recover all decommissioning costs from its wholesale purchasers, including CL&P, but that such purchasers may not be allowed to recover in their retail rates any costs that the FERC might determine to have been imprudently incurred.  On August 30, 2004, the FERC denied this petition.  On September 29, 2004, the DPUC and OCC asked the FERC to reconsider the petition and on October 20, 2005, the FERC denied the reconsideration, holding that the sponsor companies are only obligated to pay CYAPC for prudently incurred decommissioning costs and the FERC has no jurisdiction over the sponsors' rates to their retail customers.  On December 12, 2005, the DPUC sought review of these orders by the United States Court of Appeals for the D.C. Circuit.  The FERC and CYAPC have asked the court to dismiss the case and the DPUC has objected to a dismissal.  CL&P cannot predict the timing or the outcome of these proceedings.

Bechtel Litigation:  CYAPC and Bechtel commenced litigation in Connecticut Superior Court over CYAPC's termination of Bechtel's contract for the decommissioning of CYAPC's nuclear generating plant.  After CYAPC terminated the contract, responsibility for decommissioning was transitioned to CYAPC, which recommenced the decommissioning process.

On March 7, 2006, CYAPC and Bechtel executed a settlement agreement terminating this litigation.  Bechtel has agreed to pay CYAPC $15 million, and CYAPC will withdraw its termination of the contract for default and deem it terminated by agreement.

Spent Nuclear Fuel Litigation:  CYAPC, Yankee Atomic Energy Company (YAEC) and Maine Yankee Atomic Power Company (MYAPC) (Yankee Companies) also commenced litigation in 1998 charging that the federal government breached contracts it entered into with each company in 1983 under the Act.  Under the Act, the United States Department of Energy (DOE) was to begin removing spent nuclear fuel from the nuclear plants of the Yankee Companies no later than January 31, 1998 in return for payments by each company into the nuclear waste fund.  No fuel has been collected by the DOE, and spent nuclear fuel is stored on the sites of the Yankee Companies' plants.  The Yankee Companies collected the funds for payments into the nuclear waste fund from wholesale utility customers under FERC-approved contract rates.  The wholesale utility customers in turn collect these payments from their retail electric customers.  The Yankee Companies'

individual damage claims attributed to the government's breach ranging between $523 million and $543 million are specific to each plant and include incremental storage, security, construction and other costs through 2010.  The CYAPC damage claim ranges from $186 million to $198 million, the YAEC damage claim ranges from $177 million to $185 million and the MYAPC damage claim is $160 million.  The DOE trial ended on August 31, 2004 and a verdict has not been reached.  Post-trial findings of facts and final briefs were filed by the parties in January of 2005.  The Yankee Companies' current rates do not include an amount for recovery of damages in this matter.  Management can predict neither the outcome of this matter nor its ultimate impact on CL&P.

YAEC:   In November of 2005, YAEC established an updated estimate of the cost of completing the decommissioning of its plant resulting in an increase of approximately $85 million.  CL&P's share of the increase in estimated costs is $20.8 million.  This estimate reflects the cost of completing site closure activities from October of 2005 forward and storing spent nuclear fuel and other high level waste on site until 2020, when it is assumed to be removed by the DOE.  This estimate projects a total cost of $192.1 million for the completion of decommissioning and long-term fuel storage.  To fund these costs, on November 23, 2005, YAEC submitted an application to the FERC to increase YAEC’s wholesale decommissioning charges.  The DPUC and the Massachusetts attorney general protested these increases.  On January 31, 2006, the FERC issued an order accepting the rate increase, effective February 1, 20 06, subject to refund after hearings and settlement judge proceedings.  The hearings have been suspended pending settlement discussions between YAEC, the FERC and other intervenors in the case.  CL&P has a 24.5 percent ownership interest in YAEC and can predict neither the outcome of this matter nor its ultimate impact on CL&P.

Off-Balance Sheet Arrangements

The CL&P Receivables Corporation (CRC) was incorporated on September 5, 1997 and is a wholly owned subsidiary of CL&P. CRC has an agreement with CL&P to purchase and has an arrangement with a highly-rated financial institution under which CRC can sell up to $100 million of an undivided interest in accounts receivable and unbilled revenues.  At December 31, 2005 and 2004, CRC had sold an undivided interest in its accounts receivable and unbilled revenues of $80 million and $90 million, respectively, to that financial institution with limited recourse.

CRC was established for the sole purpose of selling CL&P’s accounts receivable and unbilled revenues and is included in the consolidated CL&P financial statements. On July 6, 2005, CRC renewed its Receivables Purchase and Sale Agreement with CL&P and the financial institution through July 5, 2006.  CL&P’s continuing involvement with the receivables that are sold to CRC and the financial institution is limited to the servicing of those receivables.

The transfer of receivables to the financial institution under this arrangement qualifies for sale treatment under Statement of Financial Accounting Standards (SFAS) No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities - A Replacement of SFAS No. 125."  Accordingly, the $80 million and $90 million outstanding under this facility are not reflected as debt or included in the consolidated financial statements at December 31, 2005 and 2004, respectively.

This off-balance sheet arrangement is not significant to CL&P’s liquidity or other benefits.  There are no known events, demands, commitments, trends, or uncertainties that will, or are reasonably likely to, result in the termination, or material reduction in the amount available to the company under this off-balance sheet arrangement.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates, assumptions and at times difficult, subjective or complex judgments.  Changes in these estimates, assumptions and judgments, in and of themselves, could materially impact the financial statements of CL&P.  Management communicates to and discusses with NU's Audit Committee of the Board of Trustees all critical accounting policies and estimates.  The following are the accounting policies and estimates that management believes are the most critical in nature.  

Revenue Recognition:  CL&P retail revenues are based on rates approved by the DPUC.  These regulated rates are applied to customers' use of energy to calculate a bill.  In general, rates can only be changed through formal proceedings with the DPUC.

The determination of the energy sales to individual customers is based on the reading of meters, which occurs on a systematic basis throughout the month.  Billed revenues are based on these meter readings.  At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and an estimated amount of unbilled revenues is recorded.

CL&P utilizes regulatory commission approved tracking mechanisms to track the recovery of certain incurred costs.  The tracking mechanisms allow for rates to be changed periodically, with overcollections refunded to customers or undercollections collected from customers in future periods.

Wholesale transmission revenues are based on rates and formulas that are approved by the FERC.  Most of CL&P’s wholesale transmission revenues are collected through a combination of the RNS tariff and CL&P's LNS tariff.  The RNS tariff, which is administered by ISO-NE, recovers the revenue requirements associated with transmission facilities that are deemed by the FERC to be Pool Transmission Facilities.  The LNS tariff, which was accepted by the FERC, provides for the recovery of CL&P's total transmission revenue requirements, net of revenue credits received from various rate components, including revenues received under the RNS rates.  At December 31, 2005, this true-up has resulted in the recognition of a $1.3 million regulatory liability.  

A significant portion of the CL&P transmission business revenue comes from ISO-NE charges to CL&P's electric distribution business.  CL&P recovers these costs through the retail rates that are charged to its retail customers.  In July of 2005, CL&P began tracking its retail transmission revenues and expenses and will adjust its retail transmission rates on a regular basis, thereby recovering all of its retail transmission expenses on a timely basis.  This new tracking mechanism resulted from the enactment of the new legislation passed by the Connecticut legislature in 2005.  

Unbilled Revenues:  Unbilled revenues represent an estimate of electricity or gas delivered to customers that has not yet been billed.  Unbilled revenues are included in revenue on the accompanying consolidated statements of income and are assets on the accompanying consolidated balance sheets that are reclassified to accounts receivable in the following month as customers are billed.

The estimate of unbilled revenues is sensitive to numerous factors that can significantly impact the amount of revenues recorded.  Estimating the impact of these factors is complex and requires management’s judgment.  The estimate of unbilled revenues is important to CL&P’s consolidated financial statements as adjustments to that estimate could significantly impact operating revenues and earnings.

Through December 31, 2004, CL&P estimated unbilled revenues monthly using the requirements method.  The requirements method utilized the total monthly volume of electricity or gas delivered to the system and applied a delivery efficiency (DE) factor to reduce the total monthly volume by an estimate of delivery losses in order to calculate total estimated monthly sales to customers.  The total estimated monthly sales amount less the total monthly billed sales amount resulted in a monthly estimate of unbilled sales.  Unbilled revenues were estimated by first allocating sales to the respective rate classes, then applying an average rate to the estimate of unbilled sales.  The estimated DE factor had a significant impact on estimated unbilled revenue amounts.

In the first quarter of 2005, management adopted a new method to estimate unbilled revenues for CL&P.  The new method allocates billed sales to the current calendar month based on the daily load for each billing cycle (DLC method).  The billed sales are subtracted from total calendar month sales to estimate unbilled sales.  The impact of adopting the new method was not material.  This new method replaces the requirements method described previously.  

Derivative Accounting:  The application of derivative accounting rules is complex and requires management judgment in the following respects: election and designation of the normal purchases and sales exception, identification of derivatives and embedded derivatives, and determining the fair value of derivatives.  

Certain of CL&P's contracts for the purchase or sale of energy or energy-related products are derivatives.  Those contracts that do not qualify for the normal purchases and sales exception are recorded at fair value as derivative assets and liabilities.  At December 31, 2005 and 2004, CL&P recorded the fair value of two existing power purchase contracts as derivatives, one as a derivative asset, and one as a derivative liability.  An offsetting regulatory liability and an offsetting regulatory asset have been recorded as management believes that these costs will continue to be recovered or refunded in rates.

Regulatory Accounting:  The accounting policies of CL&P historically reflect the effects of the rate-making process in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation."  The transmission and distribution businesses of CL&P continue to be cost-of-service rate regulated and management believes the application of SFAS No. 71 to those businesses continues to be appropriate.  Management must reaffirm this conclusion at each balance sheet date.  If, as a result of a change in circumstances, it is determined that any portion of CL&P no longer meets the criteria of regulatory accounting under SFAS No. 71, that portion of the company will have to discontinue regulatory accounting and write-off their regulatory assets and liabilities.  Such a write-off could have a material impact on CL&P's consolidated financial statements.

The application of SFAS No. 71 results in recording regulatory assets and liabilities.  Regulatory assets represent the deferral of incurred costs that are probable of future recovery in customer rates.  In some cases, CL&P records regulatory assets before approval for recovery has been received from the DPUC.  Management must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery.  Management bases its conclusion on certain factors, including changes in the regulatory environment, recent rate orders issued by the DPUC and the status of any potential new legislation.  Regulatory liabilities represent revenues received from customers to fund expected costs that have not yet been incurred or probable future refunds to customers.  

Management uses its best judgment when recording regulatory assets and liabilities; however, the DPUC can reach different conclusions about the recovery of costs, and those conclusions could have a material impact on CL&P’s consolidated financial statements.  Management believes it is probable that CL&P will recover the regulatory assets that have been recorded.

Presentation:  In accordance with current accounting pronouncements, CL&P's consolidated financial statements include all subsidiaries upon which control is maintained and all variable interest entities (VIE) for which CL&P is the primary beneficiary, as defined.  Determining whether the company is the primary beneficiary of the VIE is subjective and requires management's judgment.  There are certain variables taken into consideration to determine whether the company is considered the primary beneficiary to the VIE.  A change in any one of these variables could require the company to reconsider whether or not it is the primary beneficiary of the VIE.  All intercompany transactions between these subsidiaries are eliminated as part of the consolidation process.  

CL&P has less than 50 percent ownership interests in CYAPC, YAEC and MYAPC.  CL&P does not control these companies and does not consolidate them in its financial statements.  CL&P accounts for the investments in these companies using the equity method.  Under the equity method, CL&P records its ownership share of the earnings or losses at these companies.  Determining whether or not CL&P should apply the equity method of accounting for an investment requires management judgment.  

In December of 2003, the FASB issued a revised version of FASB Interpretation No. (FIN) 46 (FIN 46R).  FIN 46R has resulted in fewer CL&P investments meeting the definition of a VIE.  FIN 46R was effective for CL&P for the first quarter of 2004 and did not have an impact on CL&P's consolidated financial statements.

Pension and Postretirement Benefits Other Than Pensions (PBOP):  CL&P participates in a uniform noncontributory defined benefit retirement plan (Pension Plan) covering substantially all regular CL&P employees.  CL&P also participates in a postretirement benefit plan (PBOP Plan) to provide certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired

employees.  For each of these plans, the development of the benefit obligation, fair value of plan assets, funded status and net periodic benefit credit or cost is based on several significant assumptions.  If these assumptions were changed, the resulting change in benefit obligations, fair values of plan assets, funded status and net periodic benefit credits or costs could have a material impact on CL&P's consolidated financial statements.

Pre-tax periodic pension income for the Pension Plan totaled $0.6 million, $14.3 million and $29.1 million for the years ended December 31, 2005, 2004 and 2003, respectively.  The pension income amounts exclude one-time items recorded under SFAS No. 88, "Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits."  

Not included in the pension expense/(income) amount are pension amounts related to intercompany allocations totaling $8.8 million, $2.5 million and $(1) million for the years ended December 31, 2005, 2004 and 2003, respectively, including pension curtailment and termination benefits expense of $2.4 million and $0.5 million for the years ended December 31, 2005 and 2004, respectively.  These amounts are included in other operating expenses on the accompanying consolidated financial statements.  

The pre-tax net PBOP Plan cost, excluding curtailments and termination benefits, totaled $21.5 million, $18.6 million and $16.6 million for the years ended December 31, 2005, 2004 and 2003, respectively.

As a result of NU's decision to pursue a fundamentally different business strategy, and align the structure of the company to support this business strategy, CL&P recorded a $1 million pre-tax curtailment expense in 2005 for the Pension Plan.  CL&P also accrued certain related termination benefits and recorded a $1.3 million pre-tax charge in 2005 for the Pension Plan.  

On December 15, 2005, the NU Board of Trustees approved a benefit for new non-union employees hired on and after January 1, 2006 to receive retirement benefits under a new 401(k) benefit rather than under the Pension Plan.  Non-union employees actively employed on December 31, 2005 will be given the choice in 2006 either to elect to continue participation in the Pension Plan or instead receive a new employer contribution under the 401(k) Savings Plan effective January 1, 2007.  If the new benefit is elected, their accrued pension liability in the Pension Plan will be frozen as of December 31, 2006.  Non-union employees will make this election in the second half of 2006.  This decision resulted in the recording of an estimated pre-tax curtailment expense of $1.3 million in 2005, as a certain number of employees are expected to elect the new 401(k) benefit, resulting in a reduction in aggregate estimated future years of servic e under the Pension Plan.  Management estimated the amount of the curtailment expense associated with this change based upon actuarial calculations and certain assumptions, including the expected level of transfers to the new 401(k) benefit.  Any adjustments to this estimate resulting from actual employee elections will be recorded in 2006.

In April of 2004, as a result of litigation with nineteen former employees, CL&P was ordered by the court to modify its Pension Plan to include special retirement benefits for fifteen of these former employees retroactive to the dates of their retirement and provide increased future monthly benefit payments.  CL&P recorded $1.1 million in termination benefits related to this litigation in 2004 and made a lump sum payment totaling $0.8 million to these former employees.

For the PBOP Plan, CL&P recorded an estimated $2.5 million pre-tax curtailment expense at December 31, 2005 relating to NU's change in business strategy.  CL&P also accrued a $0.2 million pre-tax termination benefit at December 31, 2005 relating to certain benefits provided under the terms of the PBOP Plan.  Additional termination benefits may be recorded in 2006.

There were no curtailments or termination benefits recorded for the Pension Plan or PBOP Plan in 2003.

Long-Term Rate of Return Assumptions:  In developing the expected long-term rate of return assumptions, CL&P evaluated input from actuaries and consultants, as well as long-term inflation assumptions and CL&P's historical 20-year compounded return of approximately 11 percent.  CL&P's expected long-term rates of return on assets is based on certain target asset allocation assumptions and expected long-term rates of return.  CL&P believes that 8.75 percent is a reasonable long-term rate of return on Pension Plan and PBOP Plan assets (life assets and non-taxable health assets) and 6.85 percent for PBOP health assets, net of tax for 2005.  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.  The Pension Plan's and PBOP Plan's target asset allocation assumptions and expected long-t erm rates of return assumptions by asset category are as follows:

	At December 31,
	Pension Benefits		Postretirement Benefits
	2005 and 2004		2005 and 2004
Asset Category	Target Asset Allocation	Assumed Rate of Return	Target Asset Allocation	Assumed Rate of Return
Equity securities:
United States	45%	9.25%	55%	9.25%
Non-United States	14%	9.25%	11%	9.25%
Emerging markets	3%	10.25%	2%	10.25%
Private	8%	14.25%	-	-
Debt Securities:
Fixed income	20%	5.50%	27%	5.50%
High yield fixed income	5%	7.50%	5%	7.50%
Real estate	5%	7.50%	-	-

The actual asset allocations at December 31, 2005 and 2004 approximated these target asset allocations.  CL&P routinely reviews the actual asset allocations and periodically rebalances the investments to the targeted asset allocations when appropriate.  For information regarding actual asset allocations, see Note 4, "Pension Benefits and Postretirement Benefits Other Than Pensions," to the consolidated financial statements.  

Actuarial Determination of Income and Expense:  CL&P bases the actuarial determination of Pension Plan and PBOP Plan income/expense on a market-related valuation of assets, which reduces year-to-year volatility.  This market-related valuation calculation recognizes investment gains or losses over a four-year period from the year in which they occur.  Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the fair value of assets.  Since the market-related valuation calculation recognizes gains or losses over a four-year period, the future value of the market-related assets will be impacted as previously deferred gains or losses are recognized.  There will be no impact on the fair value of Pension Plan and PBOP Plan assets in the trust funds of these plans.

At December 31, 2005, the Pension Plan had cumulative unrecognized investment gains of $36.2 million, which will decrease pension expense over the next four years.  At December 31, 2005, the Pension Plan also had cumulative unrecognized actuarial losses of $203.6 million, which will increase pension expense over the expected future working lifetime of active Pension Plan participants, or approximately 13 years.  The combined total of unrecognized investment gains and actuarial losses at December 31, 2005 is a net unrecognized loss of $167.4 million.  These gains and losses impact the determination of pension expense and the actuarially determined prepaid pension amount recorded on the consolidated balance sheets but have no impact on expected Pension Plan funding.

At December 31, 2005, the PBOP Plan had cumulative unrecognized investment gains of $17.1 million, which will decrease PBOP Plan expense over the next four years.  At December 31, 2005, the PBOP Plan also had cumulative unrecognized actuarial losses of $87.8 million, which will increase PBOP Plan expense over the expected future working lifetime of active PBOP Plan participants, or approximately 13 years.  The combined total of unrecognized investment gains and actuarial losses at December 31, 2005 is a net unrecognized loss of $70.7 million.  These gains and losses impact the determination of PBOP Plan cost and the actuarially determined accrued PBOP Plan cost recorded on the consolidated balance sheets.

Discount Rate:  The discount rate that is utilized in determining future pension and PBOP obligations is based on a yield-curve approach where each cash flow related to the Pension Plan or PBOP Plan liability stream is discounted at an interest rate specifically applicable to the timing of the cash flow.  The yield curve is developed from the top quartile of AA rated Moody's and S&P's bonds without callable features outstanding at December 31, 2005.  This process calculates the present values of these cash flows and calculates the equivalent single discount rate that produces the same present value for future cash flows.  The discount rates determined on this basis are 5.80 percent for the Pension Plan and 5.65 percent for the PBOP Plan at December 31, 2005.  Discount rates used at December 31, 2004 were 6.00 percent for the Pension Plan and 5.50 percent for the PBOP Plan.

Expected Contribution and Forecasted Income/(Expense):  Due to the effect of the unrecognized actuarial losses and based on an expected rate of return on Pension Plan assets of 8.75 percent, a discount rate of 6.00 percent and an expected rate of return on PBOP assets of 6.85 percent for health assets, net of tax and 8.75 percent for life assets and non-taxable health assets, a discount rate of 5.50 percent and various other assumptions, CL&P estimates that expected contributions to and forecasted expense for the Pension Plan and PBOP Plan will be as follows (in millions):

	Pension Plan		Postretirement Plan
Year	Expected Contributions	Forecasted Expense/ (Income)	Expected Contributions	Forecasted Expense
2006	$0.0	$  3.1	$ 21.0	$ 21.0
2007	$0.0	$(6.3)	$ 18.1	$ 18.1
2008	$0.0	$(9.8)	$ 17.2	$ 17.2

Future actual pension and postretirement expense will depend on future investment performance, changes in future discount rates and various other factors related to the populations participating in the plans and amounts capitalized.

Sensitivity Analysis:  The following represents the increase/(decrease) to the Pension Plan's and PBOP Plan's reported cost as a result of the change in the following assumptions by 50 basis points (in millions):

	At December 31,
	Pension Plan		Postretirement Plan
Assumption Change	2005	2004	2005	2004
Lower long-term rate   of return	$  4.5	$ 4.7	$0.3	$0.3
Lower discount rate	$  5.6	$ 5.1	$0.4	$0.4
Lower compensation  increase	$(2.8)	$(2.0)	N/A	N/A

Plan Assets:  The market-related value of the Pension Plan assets has increased by $25.3 million to $990.7 million at December 31, 2005.  The projected benefit obligation (PBO) for the Pension Plan has also increased by $59.3 million to $859.3 million at December 31, 2005.  These changes have decreased the funded status of the Pension Plan on a PBO basis from an overfunded position of $165.4 million at December 31, 2004 to an overfunded position of $131.4 million at December 31, 2005.  The PBO includes expectations of future employee compensation increases.  The accumulated benefit obligation (ABO) of the Pension Plan was approximately $221 million less than Pension Plan assets at December 31, 2005 and approximately $269 million less than Pension Plan assets at December 31, 2004.  The ABO is the obligation for employee service and compensation provided through December 31, 2005.  Under curre nt accounting rules, if the ABO exceeds Pension Plan assets at a future plan measurement date, CL&P will record an additional minimum liability.  CL&P has not made employer contributions since 1991.

The value of PBOP Plan assets has increased from $74.9 million at December 31, 2004 to $85.1 million at December 31, 2005.  The benefit obligation for the PBOP Plan has increased from $192.4 million at December 31, 2004 to $200.7 million at December 31, 2005.  These changes have decreased the underfunded status of the PBOP Plan on an accumulated projected benefit obligation basis from $117.5 million at December 31, 2004 to $115.6 million at December 31, 2005.  CL&P has made a contribution each year equal to the PBOP Plan’s postretirement benefit cost, excluding curtailments, settlements and special termination benefits.

Health Care Cost:  The health care cost trend assumption used to project increases in medical costs was 7 percent for 2005 and 8 percent for 2004, decreasing one percentage point per year to an ultimate rate of 5 percent in 2007.  For December 31, 2005 disclosure purposes, the health care cost trend assumption was reset for 2006 at 10 percent, decreasing one percentage point per year to an ultimate rate of 5 percent in 2011.  The effect of increasing the health care cost trend by one percentage point would have increased service and interest cost components of the PBOP Plan cost by $0.4 million in 2005 and $0.4 million in 2004.

Income Taxes:  Income tax expense is calculated each year in each of the jurisdictions in which CL&P operates.  This process involves estimating CL&P's actual current tax exposures as well as assessing temporary differences resulting from differing treatment of items, such as timing of the deduction and expenses for tax and book accounting purposes.  These differences result in deferred tax assets and liabilities, which are included in CL&P's consolidated balance sheets.  Adjustments made to income taxes could significantly affect CL&P's consolidated financial statements.  Management must also assess the likelihood that deferred tax assets will be recovered from future taxable income, and to the extent that recovery is not likely, a valuation allowance must be established.  Significant management judgment is required in determining income tax expense, deferred tax assets and liabilities and valuation a llowances.

CL&P accounts for deferred taxes under SFAS No. 109, "Accounting for Income Taxes."  For temporary differences recorded as deferred tax liabilities that will be recovered in rates in the future, CL&P has established a regulatory asset.  The regulatory asset amounted to $227.6 million and $207.5 million at December 31, 2005 and 2004, respectively.  Regulatory agencies in certain jurisdictions in which CL&P operates require the tax effect of specific temporary differences to be "flowed through" to utility customers.  Flow through treatment means that deferred tax expense is not recorded in the consolidated statements of income.  Instead, the tax effect of the temporary difference impacts both amounts for income tax expense currently included in customers’ rates and the company’s net income.  Flow through treatment can result in effective income tax rates that are significantly d ifferent than expected income tax rates.  Recording deferred taxes on flow through items is required by SFAS No. 109, and the offset to the deferred tax amounts is the regulatory asset referred to above.  

A reconciliation from expected tax expense at the statutory federal income tax rate to actual tax expense recorded is included in the accompanying footnotes to the consolidated financial statements.  See Note 1H, "Summary of Significant Accounting Policies – Income Taxes," to the consolidated financial statements for further information.

The estimates that are made by management in order to record income tax expense, accrued taxes and deferred taxes are compared each year to the actual tax amounts filed on CL&P’s income tax returns.  The income tax returns were filed in the fall of 2005 for the 2004 tax year, and CL&P recorded differences between income tax expense, accrued taxes and deferred taxes on its consolidated financial statements and the amounts that were on its income tax returns.  

Depreciation:  Depreciation expense is calculated based on an asset’s useful life, and judgment is involved when estimating the useful lives of certain assets.  A change in the estimated useful lives of these assets could have a material impact on CL&P's consolidated financial statements absent timely rate relief for CL&P’s assets.  

Accounting for Environmental Reserves:  Environmental reserves are accrued using a probabilistic model approach when assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated.  Adjustments made to environmental liabilities could have a significant effect on earnings.  The probabilistic model approach estimates the liability based on the most likely action plan from a variety of available remediation options, ranging from no action to remedies ranging from establishing institutional controls to

full site remediation and long-term monitoring.  The probabilistic model approach estimates the liabilities associated with each possible action plan based on findings through various phases of site assessments.  

These estimates are based on currently available information from presently enacted state and federal environmental laws and regulations and several cost estimates from outside engineering and remediation contractors.  These amounts also take into consideration prior experience in remediating contaminated sites and data released by the United States Environmental Protection Agency and other organizations.  These estimates are subjective in nature partly because there are usually several different remediation options from which to choose when working on a specific site.  These estimates are subject to revisions in future periods based on actual costs or new information concerning either the level of contamination at the site or newly enacted laws and regulations.  The amounts recorded as environmental liabilities on the consolidated balance sheets represent management’s best estimate of the liability for environmental costs based on current site information from site assessments and remediation estimates.  These liabilities are estimated on an undiscounted basis.

CL&P recovers a certain level of environmental costs currently in rates but does not have an environmental cost recovery tracking mechanism.  Accordingly, changes in CL&P's environmental reserves impact CL&P's earnings.

Asset Retirement Obligations:  On March 30, 2005, the FASB issued FIN 47, "Accounting for Conditional Asset Retirement Obligations - an Interpretation of FASB Statement No. 143."  FIN 47 requires an entity to recognize a liability for the fair value of an asset retirement obligation (ARO) that is conditional on a future event if the liability’s fair value can be reasonably estimated.  CL&P adopted FIN 47 on December 31, 2005.  Upon adoption, management identified several conditional removal obligations that have been accounted for as AROs.  For further information regarding the adoption of FIN 47, see Note 1M, "Summary of Significant Accounting Policies - Asset Retirement Obligations," to the consolidated financial statements.

Under SFAS No. 71, regulated utilities, including CL&P, currently recover amounts in rates for future costs of removal of plant assets.  At December 31, 2005 and 2004, these amounts totaling $139.4 million and $144.3 million, respectively, are classified as regulatory liabilities on the accompanying consolidated balance sheets.

Special Purpose Entities:In addition to the special purpose entity that is described in the "Off-Balance Sheet Arrangements" section of this Management's Discussion and Analysis, during 2001, to facilitate the issuance of rate reduction certificates intended to finance certain stranded costs, CL&P established CL&P Funding LLC.  CL&P Funding LLC was created as part of a state-sponsored securitization program.  CL&P Funding LLC is restricted from engaging in non-related activities and is required to operate in a manner intended to reduce the likelihood that it would be included in CL&P’s bankruptcy estate if it ever became involved in a bankruptcy proceeding.  CL&P Funding LLC and the securitization amounts are consolidated in the accompanying consolidated financial statements.

For further information regarding the matters in this "Critical Accounting Policies and Estimates," section, see Note 1, "Summary of Significant Accounting Policies," Note 3, "Derivative Instruments," Note 4, "Pension Benefits and Postretirement Benefits Other Than Pensions," and Note 5B, "Commitments and Contingencies - Environmental Matters," to the consolidated financial statements.

Other Matters

Commitments and Contingencies:  For further information regarding other commitments and contingencies, see Note 5, "Commitments and Contingencies," to the consolidated financial statements.

Accounting Standards Issued But Not Yet Adopted:

Accounting Changes and Error Corrections:  In May of 2005, the FASB issued SFAS No. 154, "Accounting Changes and Error Corrections."  SFAS No. 154 is effective beginning on January 1, 2006 for CL&P and requires retrospective application to prior periods’ financial statements of voluntary changes in accounting principle.  It also applies to accounting changes required by a new accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions.  SFAS No. 154 does not change previous guidance for reporting the correction of an error in previously issued financial statements or a change in accounting estimate.  Implementation of SFAS No. 154 on January 1, 2006 is not expected to affect CL&P’s consolidated financial statements until such time that its provisions are required to be applied as described above.

Contractual Obligations and Commercial Commitments:  Information regarding CL&P’s contractual obligations and commercial commitments at December 31, 2005 is summarized through 2010 and thereafter as follows:

(Millions of Dollars)	2006	2007	2008	2009	2010	Thereafter
Long-term debt (a)  (b)	$       -	$       -	$       -	$       -	$        -	$1,043.7
Estimated interest  payments on existing   long-term debt	59.6	59.6	59.6	59.6	59.6	923.7
Capital leases  (c) (d)	2.4	2.4	2.1	2.0	1.5	16.6
Operating leases  (d) (e)	19.5	18.4	15.5	11.0	9.2	26.5
Required funding   of other post-  retirement benefit  obligations (e)	21.0	18.1	17.2	16.3	15.6	N/A
Long-term contractual   arrangements (d) (e)	479.8	299.8	281.0	250.2	220.1	891.6
Totals	$582.3	$398.3	$375.4	$339.1	$306.0	$2,902.1

^(a)  Included in CL&P's debt agreements are usual and customary positive, negative and financial covenants.  Non-compliance with certain covenants, for example timely payment of principal and interest, may constitute an event of default, which could cause an acceleration of

principal in the absence of receipt by the company of a waiver or amendment.  Such acceleration would change the obligations outlined in the table of contractual obligations and commercial commitments.  

^(b)  Long-term debt disclosed above excludes fees and interest due for spent nuclear fuel disposal costs of $216.9 million and unamortized discounts of $1.7 million.  

^(c) The capital lease obligations include imputed interest of $13.5 million.

^(d) CL&P has no provisions in its capital or operating lease agreements or agreements related to its long-term contractual arrangements that could trigger a change in terms and conditions, such as acceleration of payment obligations.

^(e)  Amounts are not included on CL&P's consolidated balance sheets.

Rate reduction bond amounts are non-recourse to CL&P, have no required payments over the next five years and are not included in this table.  CL&P's standard offer service contracts and default service contracts also are not included in this table.  For further information regarding CL&P’s contractual obligations and commercial commitments, see Note 2, "Short-Term Debt," Note 5D, "Commitments and Contingencies - Long-Term Contractual Arrangements," Note 7, "Leases," and Note 11 , "Long-Term Debt," to the consolidated financial statements.

Forward Looking Statements:  This discussion and analysis includes statements concerning CL&P's expectations, plans, objectives, future financial performance and other statements that are not historical facts.  These statements are "forward looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995.  In some cases the reader can identify these forward looking statements by words such as "estimate," "expect," "anticipate," "intend," "plan," "believe," "forecast," "should," "could," and similar expressions.  Forward looking statements involve risks and uncertainties that may cause actual results or outcomes to differ materially from those included in the forward looking statements.  Factors that may cause actual results to differ materially from those included in the forward looking stat ements include, but are not limited to, actions by state and federal regulatory bodies, competition and industry restructuring, changes in economic conditions, changes in weather patterns, changes in laws, regulations or regulatory policy, expiration or initiation of significant energy supply contracts, changes in levels of capital expenditures, developments in legal or public policy doctrines, technological developments, volatility in electric and natural gas commodity markets, effectiveness of our risk management policies and procedures, changes in accounting standards and financial reporting regulations, fluctuations in the value of electricity positions, actions of rating agencies, terrorist attacks on domestic energy facilities and other presently unknown or unforeseen factors. Other risk factors are detailed from time to time in our reports to the SEC.  Management undertakes no obligation to update the information contained in any forward looking statements to reflect developments or circumstances occurring after the statement is made.

Web Site:  Additional financial information is available through CL&P's web site at www.cl-p.com.

RESULTS OF OPERATIONS

The following table provides the variances in income statement line items for the consolidated statements of income included in this annual report for the past two years.  

Income Statement Variances	2005 over/(under) 2004			2004 over/(under) 2003
(Millions of Dollars)	Amount	Percent		Amount	Percent
Operating Revenues	$634	22	%	$128	5	%
Operating Expenses:
Fuel, purchased and net interchange power	447	26		96	6
Other operation	113	26		53	14
Maintenance	14	17		8	11
Depreciation	14	12		15	14
Amortization of regulatory asset, net	35	(a)		(82)	(77)
Amortization of rate reduction bonds	8	7		7	7
Taxes other than income taxes	12	8		1	-
Total operating expenses	643	25		98	4
Operating Income	(9)	(4)		30	16
Interest expense, net	10	9		-	-
Other income, net	13	52		16	(a)
Income before income tax expense	(6)	(5)		46	53
Income tax expense	(13)	(29)		27	(a)
Net income	$   7	8	%	$  19	30	%

(a) Percent greater than 100.  

Comparison of the Year 2005 to the Year 2004

Operating Revenues

Operating revenues increased $634 million in 2005, compared to 2004, due to higher distribution revenues ($615 million) and higher transmission revenues ($19 million).

The distribution revenue increase of $615 million is primarily due to the components of revenues which are included in regulatory commission approved tracking mechanisms that track the recovery of certain incurred costs ($570 million).  The tracking mechanisms allow for rates to be changed periodically with over collections refunded to customers or under collections collected from customers in future periods.  The distribution component of rates which impact earnings increased $45 million, primarily due to the retail rate increase effective January 1, 2005 and increased sales volumes, partially offset by the additional reserve recorded to reflect the final decision on the streetlight docket ($2 million).  Retail sales in 2005 were 3.0 percent higher than in 2004.

The distribution revenue tracking components increased $570 million primarily due to higher TSO related revenues ($299 million), an increase in revenues associated with the recovery of FMCC charges ($235 million), and higher wholesale revenues ($51 million) primarily due to higher market prices for the sales of IPP contract related power, partially offset by lower revenues as a result of lower retail rates for the recovery of conservation and load management and system benefit costs ($9 million).

Transmission revenues increased $19 million primarily due to higher rate base and operating expenses which are recovered under the NU schedule 21 tariff and revenues resulting from the additional recovery of 2004 expenses.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expense increased $447 million in 2005, primarily due to higher TSO supply costs as a result of the higher retail sales and a higher cost per kWh in 2005.

Other Operation

Other operation expenses increased $113 million in 2005 primarily due to higher RMR costs ($73 million) which are tracked and recovered through the FMCC, and higher administrative expenses ($36 million) mainly as a result of higher pension and other benefit costs ($18 million) and employee termination and benefit plan curtailment charges ($16 million).

Maintenance

Maintenance expense increased $14 million in 2005 primarily due to higher expenses related to distribution lines maintenance ($11 million) in part due to heat related and storm activity, higher expenses for substation maintenance ($1 million) and higher transmission system maintenance expenses ($1 million).

Depreciation

Depreciation expense increased $14 million in 2005 due to higher utility plant balances resulting from plant additions.

Amortization of Regulatory Assets, Net

Amortization of regulatory assets, net increased $35 million in 2005 primarily due to higher amortization related to the recovery of transition charges as a result of higher wholesale revenues.

Amortization of Rate Reduction Bonds

Amortization of rate reduction bonds increased $8 million in 2005 due to the repayment of additional principal.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $12 million in 2005 primarily due to higher Connecticut GET (gross earnings tax) resulting from higher revenue ($13 million) and higher property taxes ($4 million), partially offset by lower taxes paid in 2005 to the town of Waterford for lost property tax revenue as a result of the sale of Millstone ($3 million).

Interest Expense, Net

Interest expense, net increased $10 million in 2005 primarily due to higher interest on long-term debt ($16 million) mainly as a result of $280 million of new debt issued in September 2004 ($11 million) and $200 million of new debt issued in April 2005 ($7 million), and higher other interest related to the final decision on the streetlight docket ($3 million), partially offset by lower rate reduction bond interest resulting from lower principal balances outstanding ($8 million).

Other Income, Net

Other income, net increased $13 million in 2005 primarily due to a higher TSO procurement fee ($6 million) and a higher AFUDC ($6 million), as a result of increased eligible CWIP for transmission and lower short term debt resulting in a greater component of CWIP being subject to the higher equity rate.

Income Taxes

Income tax expense decreased $13 million in 2005 primarily due to lower pre-tax income, greater favorable flow through adjustments for plant related items and lower state tax due to lower rates and higher credits.  For further information regarding income tax expense, see Note 1H, "Summary of Significant Accounting Policies - Income Taxes," to the consolidated financial statements.

Comparison of the Year 2004 to the Year 2003

Operating Revenues

Operating revenues increased $128 million in 2004, compared with the same period in 2003, due to higher distribution revenues ($112 million) and higher transmission revenues ($16 million).

The distribution revenue increase of $112 million is primarily due to non-earnings components of retail rates ($89 million).  The distribution and retail transmission components of CL&P’s rates which flows through to earnings increased $31 million, primarily due to the retail transmission rate increase effective in January of 2004.  The non-earnings components increase of $89 million is primarily due to the pass through of energy supply costs ($168 million) and FMCC ($151 million), partially offset by the resolution of  Standard Market Design (SMD) cost recovery which was being collected from CL&P customers in 2003 and early 2004 and also partially refunded in late 2004 ($71 million), lower wholesale revenues due in part to the expiration of long-term contracts ($46 million), lower CL&P EAC revenue as a result of the end of EAC billings in 2003 ($44 million), lower system benefit cost recoveries ($31 million), lower transi tion cost recoveries ($21 million), and lower revenue to fund Conservation and Load Management (C&LM) initiatives ($16 million).  Retail sales in 2004 were 0.1 percent higher than 2003.  

Transmission revenues were higher due to the October 2003 implementation of the transmission rate case approved at the FERC.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expense increased $96 million in 2004, primarily due to an increase in the standard offer service supply costs ($152 million), partially offset by lower deferrals of fuel expense as a result of the lower levels of fuel and congestion costs ($53 million).

Other Operation

Other operation expenses increased $53 million in 2004, primarily due to higher RMR costs ($60 million) and other power pool related expenses recovered through the FMCC charge ($11 million), partially offset by lower C&LM expense ($22 million).

Maintenance

Maintenance expenses increased $8 million in 2004 primarily due to the 2003 positive resolution of the CL&P Millstone use of proceeds docket ($4 million) and higher distribution maintenance expenses ($4 million).

Depreciation

Depreciation expense increased $15 million in 2004, primarily due to higher utility plant balances in 2004 resulting from plant additions and higher depreciation rates resulting from the distribution rate case decision effective in January of 2004.

Amortization of Regulatory Assets, Net

Amortization expense decreased $82 million in 2004 primarily due to the lower amortization related to the recovery of system benefit and transition charges ($54 million), primarily due to the lower recovery of stranded costs resulting from the decrease in the system benefit and transition charge component of retail rates, and a decrease in amortization expense resulting from the amortization of GSC over-recoveries allowed in the distribution rate case decision effective in January of 2004 ($29 million).

Amortization of Rate Reduction Bonds

Amortization of rate reduction bonds increased $7 million in 2004, due to the repayment of a higher principal amount.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $1 million in 2004, primarily due to higher property taxes.

Other Income/(Loss), Net

Other income, net increased $16 million in 2004, primarily due to the recognition beginning in 2004 of a procurement fee approved in the TSO docket ($12 million), higher interest and dividend income ($3 million) and higher C&LM incentive income ($2 million).

Income Taxes

Income tax expense increased $27 million in 2004 due to higher income before tax expense, higher reversals of flow through depreciation and adjustments to tax expense as a result of the actual 2003 tax return amounts compared to the 2003 year end tax provision estimates.

Company Report on Internal Controls

Management is responsible for the preparation, integrity, and fair presentation of the accompanying consolidated financial statements of The Connecticut Light and Power Company and subsidiaries and other sections of this annual report.  These financial statements, which were audited by Deloitte & Touche LLP, have been prepared in conformity with accounting principles generally accepted in the United States of America using estimates and judgments, where required, and giving consideration to materiality.

The company has endeavored to establish a control environment that encourages the maintenance of high standards of conduct in all of its business activities.  Management is responsible for maintaining a system of internal controls over financial reporting, that is designed to provide reasonable assurance, at an appropriate cost-benefit relationship, to the company’s management and Board of Trustees of Northeast Utilities regarding the preparation of reliable, published financial statements.  The system is supported by an organization of trained management personnel, policies and procedures, and a comprehensive program of internal audits.  Through established programs, the company regularly communicates to its management employees their internal control responsibilities and obtains information regarding compliance with policies prohibiting conflicts of interest and policies segregating information between regulated and unregulated subs idiary companies.  The company has standards of business conduct for all employees, as well as a code of ethics for senior financial officers.

The Audit Committee of the Board of Trustees of Northeast Utilities is composed entirely of independent trustees and includes two members that the Board of Trustees considers "audit committee financial experts."  The Audit Committee meets regularly with management, the internal auditors, and the independent auditors to review the activities of each and to discuss audit matters, financial reporting matters, and the system of internal controls over financial reporting.  The Audit Committee also meets periodically with the internal auditors and the independent auditors without management present.

Because of inherent limitations in any system of internal controls, errors or irregularities may occur and not be detected.  The company believes, however, that its system of internal controls over financial reporting and control environment provide reasonable assurance that its assets are safeguarded from loss or unauthorized use and that its financial records, which are the basis for the preparation of all financial statements, are reliable.  Additionally, management believes that its disclosure controls and procedures are in place and operating effectively.  Disclosure controls and procedures are designed to ensure that information included in reports such as this annual report is recorded, processed, summarized, and reported within the time periods required and that the information disclosed is accumulated and reviewed by management for discussion and approval.

March 7, 2006

Report of Independent Registered Public Accounting Firm    

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, 2005 and 2004, 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, 2005.  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 the standards of the Public Company Accounting Oversight Board (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.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting.  Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.  An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of The Connecticut Light and Power Company and subsidiaries as of December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.

/s/  Deloitte & Touche LLP

      Deloitte & Touche LLP

Hartford, Connecticut

March 7, 2006

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
At December 31,	2005	2004
	(Thousands of Dollars)
ASSETS
Current Assets:
Cash	$                2,301	$                5,608
Investments in securitizable assets	252,801	139,391
Receivables, less provision for uncollectible
accounts of $1,982 in 2005 and $2,010 in 2004	80,883	69,892
Accounts receivable from affiliated companies	17,214	66,386
Unbilled revenues	7,888	8,189
Taxes receivable	-	766
Materials and supplies	32,929	33,213
Derivative assets - current	82,578	24,243
Prepayments and other	18,003	16,187
	494,597	363,875
Property, Plant and Equipment:
Electric utility	3,997,652	3,671,767
Less: Accumulated depreciation	1,175,164	1,089,872
	2,822,488	2,581,895
Construction work in progress	344,204	242,982
	3,166,692	2,824,877
Deferred Debits and Other Assets:
Regulatory assets	1,357,985	1,526,359
Prepaid pension	315,532	318,559
Derivative assets - long-term	308,648	167,122
Other	121,618	106,121
	2,103,783	2,118,161
Total Assets	$         5,765,072	$         5,306,913
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,	2005	2004
	(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION
Current Liabilities:
Notes payable to banks	$                        -	$             15,000
Notes payable to affiliated companies	26,825	90,025
Accounts payable	253,974	166,520
Accounts payable to affiliated companies	39,755	89,242
Accrued taxes	60,531	-
Accrued interest	16,947	14,203
Derivative liabilities – current	477	4,408
Other	70,025	56,606
	468,534	436,004
Rate Reduction Bonds	856,479	995,233
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	774,190	761,036
Accumulated deferred investment tax credits	85,970	88,540
Deferred contractual obligations	243,279	281,633
Regulatory liabilities	742,993	614,770
Derivative liabilities - long-term	31,774	42,809
Other	131,253	95,505
	2,009,459	1,884,293
Capitalization:
Long-Term Debt	1,258,883	1,052,891
Preferred Stock - Non-Redeemable	116,200	116,200
Common Stockholder's Equity:
Common stock, $10 par value - authorized
24,500,000 shares; 6,035,205 shares outstanding
in 2005 and 2004	60,352	60,352
Capital surplus, paid in	612,815	415,140
Retained earnings	382,628	347,176
Accumulated other comprehensive loss	(278)	(376)
Common Stockholder's Equity	1,055,517	822,292
Total Capitalization	2,430,600	1,991,383
Commitments and Contingencies (Note 5)
Total Liabilities and Capitalization	$          5,765,072	$        5,306,913
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,	2005	2004		2003
	(Thousands of Dollars)
Operating Revenues	$        3,466,420	$         2,832,924	$         2,704,524
Operating Expenses:
Operation -
Fuel, purchased and net interchange power	2,145,834	1,698,335	1,602,240
Other	550,100	437,502	384,443
Maintenance	95,076	81,064	73,066
Depreciation	133,120	119,295	104,513
Amortization of regulatory assets, net	59,632	24,294	105,956
Amortization of rate reduction bonds	118,488	110,625	103,285
Taxes other than income taxes	154,619	142,919	142,339
Total operating expenses	3,256,869	2,614,034	2,515,842
Operating Income	209,551	218,890	188,682
Interest Expense:
Interest on long-term debt	59,019	43,308	39,815
Interest on rate reduction bonds	55,796	63,667	70,284
Other interest	5,220	3,072	508
Interest expense, net	120,035	110,047	110,607
Other Income, Net	37,503	24,712	8,968
Income Before Income Tax Expense	127,019	133,555	87,043
Income Tax Expense	32,174	45,539	18,135
Net Income	$             94,845	$              88,016	$              68,908
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Net Income	$             94,845	$              88,016	$              68,908
Other comprehensive income/(loss), net of tax:
Unrealized (losses)/gains on securities	(22)	37	152
Minimum supplemental executive retirement
pension liability adjustments	120	(66)	(136)
Other comprehensive income/(loss), net of tax	98	(29)	16
Comprehensive Income	$             94,943	$             87,987	$              68,924
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
	Common Stock		Capital Surplus,	Retained	Accumulated Other Comprehensive
	Shares	Amount	Paid In	Earnings	(Loss)/Income	Total
	(Thousands of Dollars, except share information)
Balance at January 1, 2003	6,035,205	$        60,352	$         327,299	$       308,554	$               (363)	$         695,842
Net income for 2003				68,908		68,908
Cash dividends on preferred stock				(5,559)		(5,559)
Cash dividends on common stock				(60,110)		(60,110)
Capital stock expenses, net			186			186
Allocation of benefits - ESOP			(856)			(856)
Other comprehensive income					16	16
Balance at December 31, 2003	6,035,205	60,352	326,629	311,793	(347)	698,427
Net income for 2004				88,016		88,016
Cash dividends on preferred stock				(5,559)		(5,559)
Cash dividends on common stock				(47,074)		(47,074)
Capital contribution from NU parent			88,000			88,000
Tax deduction for stock options exercised and Employee Stock
Purchase Plan disqualifying dispositions			823			823
Capital stock expenses, net			186			186
Allocation of benefits – ESOP			(498)			(498)
Other comprehensive loss					(29)	(29)
Balance at December 31, 2004	6,035,205	60,352	415,140	347,176	(376)	822,292
Net income for 2005				94,845		94,845
Cash dividends on preferred stock				(5,559)		(5,559)
Cash dividends on common stock				(53,834)		(53,834)
Capital contribution from NU parent			197,794			197,794
Tax deduction for stock options exercised and Employee Stock
Purchase Plan disqualifying dispositions			171			171
Capital stock expenses, net			186			186
Allocation of benefits - ESOP			(476)			(476)
Other comprehensive income					98	98
Balance at December 31, 2005	6,035,205	$        60,352	$         612,815	$       382,628	$               (278)	$      1,055,517
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,	2005	2004	2003
	(Thousands of Dollars)
Operating Activities:
Net income	$                    94,845	$                 88,016	$            68,908
Adjustments to reconcile to net cash flows
provided by operating activities:
Bad debt expense	12,834	1,440	5,164
Depreciation	133,120	119,295	104,513
Deferred income taxes	(16,585)	102,394	(125,711)
Amortization of regulatory assets, net	59,632	24,294	105,956
Amortization of rate reduction bonds	118,488	110,625	103,285
Amortization/(deferral) of recoverable energy costs	36,090	(13,242)	19,191
Pension expense/(income)	1,491	(6,763)	(14,047)
Regulatory (refunds)/overrecoveries	(73,442)	(137,537)	267,729
Deferred contractual obligations	(60,444)	(35,764)	(34,554)
Other non-cash adjustments	(8,730)	(19,556)	(60,857)
Other sources of cash	717	18,499	2,283
Other uses of cash	(14,192)	(18,594)	(14,691)
Changes in current assets and liabilities:
Receivables and unbilled revenues, net	25,648	(4,201)	(2,008)
Materials and supplies	284	(1,630)	796
Investments in securitizable assets	(113,410)	27,074	12,443
Other current assets	(1,779)	(3,249)	6,886
Accounts payable	25,312	(40,893)	17,692
Accrued taxes	61,297	(65,587)	31,237
Other current liabilities	16,097	9,327	11,564
Net cash flows provided by operating activities	297,273	153,948	505,779
Investing Activities:
Investments in plant	(444,384)	(389,266)	(318,497)
Restricted cash - LMP costs	-	93,630	(93,630)
Net proceeds from sale of property	21,993	-	-
Proceeds from sales of investment securities	1,883	1,773	1,176
Purchases of investment securities	(1,993)	(2,316)	(2,184)
Other investing activities	1,078	2,090	7,224
Net cash flows used in investing activities	(421,423)	(294,089)	(405,911)
Financing Activities:
Issuance of long-term debt	200,000	280,000	-
Reacquisitions and retirements of long-term debt	-	(59,000)	-
Retirement of rate reduction bonds	(138,754)	(129,546)	(120,949)
Capital contribution from Northeast Utilities	197,794	88,000	-
(Decrease)/increase in short-term debt	(15,000)	15,000	-
NU Money Pool (lending)/borrowing	(63,200)	(1,100)	93,025
Cash dividends on preferred stock	(5,559)	(5,559)	(5,559)
Cash dividends on common stock	(53,834)	(47,074)	(60,110)
Other financing activities	(604)	(786)	(620)
Net cash flows provided by/(used in) financing activities	120,843	139,935	(94,213)
Net (decrease)/increase in cash	(3,307)	(206)	5,655
Cash - beginning of year	5,608	5,814	159
Cash - end of year	$                      2,301	$                   5,608	$              5,814
Supplemental Cash Flow Information:
Cash paid/(received) during the year for:
Interest, net of amounts capitalized	$                  125,249	$               109,890	$          112,258
Income taxes	$                  (12,761)	$                 24,915	$          105,167
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 Company

The Connecticut Light and Power Company (CL&P or the company) is a wholly owned subsidiary of Northeast Utilities (NU).  CL&P is a reporting company under the Securities Exchange Act of 1934.  Until February 8, 2006, NU was registered with the Securities and Exchange Commission (SEC) as a holding company under the Public Utility Holding Company Act of 1935 (PUHCA).  On February 8, 2006, PUHCA was repealed.  Arrangements among CL&P, other NU companies, outside agencies, and other utilities covering interconnections, interchange of electric power and sales of utility property, are subject to regulation by the Federal Energy Regulatory Commission (FERC) and/or the SEC.  CL&P is subject to further regulation for rates, accounting and other matters by the FERC and the Connecticut Department of Public Utility Control (DPUC).  CL&P furnishes franchised retail electric service in Connecticut.  CL&P’s results include the operations of its distribution and transmission segments.  

Several wholly owned subsidiaries of NU provide support services for NU’s companies, including CL&P.  Northeast Utilities Service Company (NUSCO) provides centralized accounting, administrative, engineering, financial, information technology, legal, operational, planning, purchasing, and other services to NU’s companies.

Included in the consolidated balance sheet at December 31, 2005, are accounts receivable from affiliated companies and accounts payable to affiliated companies totaling $17.2 million and $39.8 million, respectively, relating to transactions between CL&P and other subsidiaries that are wholly owned by NU.  At December 31, 2004, these amounts totaled $66.4 million and $89.2 million, respectively.

Total CL&P purchases from affiliate Select Energy, Inc. (Select Energy), another NU subsidiary, for CL&P's standard offer load and for other transactions with Select Energy represented approximately $53 million, $611 million and $688 million for the years ended December 31, 2005, 2004 and 2003, respectively.

B.

Presentation

The consolidated financial statements of CL&P include the accounts of its subsidiaries, CL&P Receivables Corporation (CRC) and CL&P Funding LLC.  Intercompany transactions have been eliminated in consolidation.

The preparation of consolidated 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 consolidated 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 period data included in the accompanying consolidated financial statements have been made to conform with the current years' presentation.  

In the company's consolidated balance sheet at December 31, 2004, the company changed the classification of certain deposit amounts totaling $9.3 million related to its rate reduction bonds.  The company previously presented these amounts on a gross basis in deferred debits and other assets - other with an equal and offsetting amount in other current liabilities.  For the current year presentation, these amounts are presented on a net basis in the company's accompanying consolidated balance sheet.

In the company’s consolidated statements of income for the years ended December 31, 2004 and 2003, the company changed the classification of certain costs that were not recoverable from regulated customers totaling $3.2 million and $4.4 million, respectively.  The company previously presented these amounts in other income, net.  For the current year presentation, these amounts are presented in other operation expenses in the consolidated statements of income for the years ended December 31, 2004 and 2003.

In the company's consolidated statements of cash flows for the years ended December 31, 2004 and 2003, the company changed the classification of the change in restricted cash – locational marginal pricing (LMP) costs balances to present that change as an investing activity.  The company previously presented that change as an operating activity which resulted in a $93.6 million decrease in net cash flows used in investing activities and a corresponding decrease in operating cash flows from the amounts previously reported for the year ended December 31, 2004 and a $93.6 million increase in net cash flows used in investing activities and a corresponding increase in operating cash flows from amounts previously reported for the year ended December 31, 2003.  

The consolidated statements of cash flows for the years ended December 31, 2004 and 2003 have also been reclassified to exclude from cash flows from operations the change in accounts payable related to capital projects as well as excluding these amounts from investments in plant in investing activities.  These amounts totaled sources of cash of $18.4 million and uses of cash of $4.6 million for the years ended December 31, 2004 and 2003, respectively.  

C.

Accounting Standards Issued But Not Yet Adopted

Accounting Changes and Error Corrections:  In May of 2005, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 154, "Accounting Changes and Error Corrections."  SFAS No. 154 is effective beginning on January 1, 2006 for CL&P and requires retrospective application to prior periods’ financial statements of voluntary changes in accounting principle.  It also applies to accounting changes required by a new accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions.  SFAS No. 154 does not change previous guidance for reporting the correction of an error in previously issued financial statements or a change in accounting estimate.  Implementation of SFAS No. 154 on January 1, 2006 is not expected to affect CL&P’s consolidated financial statements un til such time that its provisions are required to be applied as described above.

D.

Guarantees

NU provides credit assurances on behalf of subsidiaries in the form of guarantees and letters of credit (LOCs) in the normal course of business.  At December 31, 2005, the maximum level of exposure in accordance with FASB Interpretation No. (FIN) 45, "Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others," under guarantees by NU, on behalf of CL&P, totaled $1.2 million.  A majority of these guarantees do not have established expiration dates, and some guarantees have unlimited exposure to commodity price movements.  Additionally, NU had $40 million of LOCs issued on behalf of CL&P at December 31, 2005.  CL&P has no guarantees of the performance of third parties.  

Several underlying contracts that NU guarantees, as well as certain surety bonds, contain credit ratings triggers that would require NU to post collateral in the event that NU’s credit ratings are downgraded below investment grade.

Until the repeal of PUHCA on February 8, 2006, NU was authorized by the SEC to provide up to $50 million of guarantees to the Utility Group, including CL&P, through June 30, 2007.  The amount of guarantees on behalf of CL&P outstanding for compliance with this limit at December 31, 2005 is $0.1 million.  These amounts are calculated using different, more probabilistic and fair-value based criteria than the maximum level of exposure required to be disclosed under FIN 45.  FIN 45 includes all exposures even though they are not reasonably likely to result in exposure to NU on behalf of CL&P.

With the repeal of PUHCA, there are no regulatory limits on NU's ability to guarantee the obligation of its subsidiaries, including CL&P.  

E.

Revenues

CL&P retail revenues are based on rates approved by the DPUC.  These regulated rates are applied to customers' use of energy to calculate a bill.  In general, rates can only be changed through formal proceedings with the DPUC.  However, CL&P utilizes a regulatory commission-approved tracking mechanism to track the recovery of certain incurred costs.  The tracking mechanism allows for rates to be changed periodically, with overcollections refunded to customers or undercollections collected from customers in future periods.

Unbilled Revenues:  Unbilled revenues represent an estimate of electricity delivered to customers that has not yet been billed.  Unbilled revenues are included in revenue on the statement of income and are assets on the balance sheet that are reclassified to accounts receivable in the following month as customers are billed.  Such estimates are subject to adjustment when actual meter readings become available, when changes in estimating methodology occur and under other circumstances.

Through December 31, 2004, CL&P estimated unbilled revenues monthly using the requirements method.  The requirements method utilized the total monthly volume of electricity delivered to the system and applied a delivery efficiency (DE) factor to reduce the total monthly volume by an estimate of delivery losses in order to calculate total estimated monthly sales to customers.  The total estimated monthly sales amount less the total monthly billed sales amount resulted in a monthly estimate of unbilled sales.  Unbilled revenues were estimated by first allocating sales to the respective rate classes, then applying an average rate to the estimate of unbilled sales.  The estimated DE factor had a significant impact on estimated unbilled revenue amounts.

In the first quarter of 2005, management adopted a new method to estimate unbilled revenues for CL&P.  The new method allocates billed sales to the current calendar month based on the daily load for each billing cycle (DLC method).  The billed sales are subtracted from total calendar month sales to estimate unbilled sales.  The impact of adopting the new method was not material.  This new method replaces the requirements method described above.  

Transmission Revenues - Wholesale Rates:  Wholesale transmission revenues are based on rates and formulas that are approved by the FERC.  Most of CL&P’s wholesale transmission revenues are collected through a combination of the New England Regional Network Service (RNS) tariff and CL&P’s Local Network Service (LNS) tariff.  The RNS tariff, which is administered by the New England Independent System Operator (ISO-NE), recovers the revenue requirements associated with transmission facilities that are deemed by the FERC to be regional facilities.  This regional rate is reset on June 1 of each year.  The LNS tariff provides for the recovery of CL&P's total transmission revenue requirements, net of revenues received from other sources, including those revenues received under RNS rates.  CL&P's LNS tariff is reset on January 1 and June 1 of each year.  Additionally, CL&P’s LNS tariff provides for a true-up to actual costs, which ensures that CL&P recovers its total transmission revenue requirements, including an allowed return on equity (ROE).  At December 31, 2005, this true-up has resulted in the recognition of a $1.3 million regulatory liability.  

Transmission Revenues - Retail Rates:  A significant portion of CL&P’s transmission business revenue comes from ISO-NE charges to CL&P’s distribution business.  CL&P recovers these costs through the retail rates that are charged to its retail customers.  Any difference between the revenues received from retail customers and the retail transmission expenses charged to the distribution business has historically impacted the distribution business earnings.  In July of 2005, CL&P began a process of tracking its retail transmission revenues and expenses and adjusting its retail transmission rates on a regular basis, thereby recovering all of its retail transmission expenses on a timely basis.  This ratemaking change resulted from the enactment of the legislation passed by the Connecticut legislature in 2005.   

F.

Derivative Instruments

The accounting treatment for energy contracts entered into varies and depends on the intended use of the particular contract and on whether or not the contract is a derivative.  Non-derivative contracts are recorded at the time of delivery or settlement under accrual accounting.  

Certain CL&P contracts for the purchase or sale of energy or energy-related products are derivatives.  Derivative contracts that are elected as and meet the requirements of a normal purchase or sale are recognized in revenues or expenses, as applicable, as when the quantity of the contract is delivered.  Election of the normal purchases and sales exception (and resulting accrual accounting) for derivatives requires the conclusions that it is probable at the inception of the contract and throughout its term that it will result in physical delivery and that the quantities will be used or sold by the business over a reasonable period in the normal course of business.  

Certain CL&P contracts that do not meet the normal purchases and sales criteria are recorded at fair value as derivative assets and liabilities with offsetting amounts recorded as regulatory liabilities, and assets because the contracts are part of providing regulated electric service and because management believes that these amounts will be recovered or refunded in rates.

For further information regarding these contracts and their accounting, see Note 3, "Derivative Instruments," to the consolidated financial statements.

G.

Regulatory Accounting

The accounting policies of CL&P conform to accounting principles generally accepted in the United States of America applicable to rate-regulated enterprises and historically reflect the effects of the rate-making process in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation."

The transmission and distribution businesses of CL&P continue to be cost-of-service rate regulated and management believes that the application of SFAS No. 71 to 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 net regulatory assets are earning an equity return, except for securitized regulatory assets, which are not supported by equity and substantial portions of the unrecovered contractual obligations regulatory assets.  

Regulatory Assets:  The components of CL&P's regulatory assets are as follows:

	At December 31,
(Millions of Dollars)	2005	2004
Securitized assets	$  855.6	$  994.3
Income taxes, net	227.6	207.5
Unrecovered contractual obligations	197.7	213.4
Recoverable energy costs	7.3	43.4
Other	69.8	67.8
Totals	$1,358.0	$1,526.4

Included in other regulatory assets above of $69.8 million at December 31, 2005 are the regulatory assets recorded associated with the implementation of FIN 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143," totaling $25.1 million.  These regulatory assets have not been approved for deferred accounting treatment.  At this time, management believes that the regulatory assets related to FIN 47 are probable of recovery.  

Additionally, CL&P had $10.7 million and $11.4 million of regulatory costs at December 31, 2005 and 2004, respectively, that are included in deferred debits and other assets - other on the accompanying consolidated balance sheets.  These amounts represent regulatory costs that have not yet been approved by the DPUC.  Management believes these costs are recoverable in future regulated rates.

Securitized Assets:  In March of 2001, CL&P issued $1.4 billion in rate reduction certificates.  CL&P used $1.1 billion of the proceeds from that issuance to buyout or buydown certain contracts with independent power producers (IPP).  The unamortized CL&P securitized asset balance is $731.4 million and $850 million at December 31, 2005 and 2004, respectively.  CL&P used the remaining proceeds from the issuance of the rate reduction certificates to securitize a portion of its SFAS No. 109, "Accounting for Income Taxes," regulatory asset.  The securitized SFAS No. 109 regulatory asset had an unamortized balance of $124.2 million and $144.3 million at December 31, 2005 and 2004, respectively.

Securitized assets are being recovered over the amortization period of their associated rate reduction certificates.  All outstanding rate reduction certificates of CL&P are scheduled to fully amortize by December 30, 2010.

Income Taxes, Net:  The tax effect of temporary differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of taxable income) is accounted for in accordance with the rate-making treatment of the applicable regulatory commissions and SFAS No. 109.  Differences in income taxes between SFAS No. 109 and the

rate-making treatment of the applicable regulatory commissions are recorded as regulatory assets which totaled $227.6 million and $207.5 million at December 31, 2005 and 2004, respectively.  For further information regarding income taxes, see Note 1H, "Summary of Significant Accounting Policies - Income Taxes" to the consolidated financial statements.  

Unrecovered Contractual Obligations:  CL&P, under the terms of contracts with Connecticut Yankee Atomic Power Company (CYAPC), Yankee Atomic Energy Company (YAEC) and Maine Yankee Atomic Power Company (MYAPC) (Yankee Companies), is responsible for its proportionate share of the remaining costs of the units, including decommissioning.  These amounts which totaled $197.7 million and $213.4 million at December 31, 2005 and 2004, respectively, are recorded as unrecovered contractual obligations.  A portion of these obligations for CL&P was securitized in 2001 and is included in securitized regulatory assets.  As discussed in Note 5E, "Commitments and Contingencies - Deferred Contractual Obligations," substantial portions of the unrecovered contractual obligations regulatory assets have not yet been approved for recovery.  At this time management believes that these regulatory assets are probable of recov ery.

Recoverable Energy Costs:  Under the Energy Policy Act of 1992 (Energy Act), CL&P was assessed for its proportionate share of the costs of decontaminating and decommissioning uranium enrichment plants owned by the United States Department of Energy (DOE) (D&D Assessment).  The Energy Act requires that regulators treat D&D Assessments as a reasonable and necessary current cost of fuel, to be fully recovered in rates like any other fuel cost.  CL&P no longer owns nuclear generation assets but continues to recover these costs through rates.  At December 31, 2005 and 2004, CL&P’s total D&D Assessment deferrals were $7.3 million and $10.9 million, respectively, and have been recorded as recoverable energy costs.  Also included in recoverable energy costs at December 31, 2004 is $32.5 million related to Federally Mandated Congestion Costs (FMCC).  

The majority of the recoverable energy costs are currently recovered in rates from CL&P's customers.

Regulatory Liabilities:  CL&P had $743 million and $614.8 million of regulatory liabilities at December 31, 2005 and 2004, respectively, including revenues subject to refund.  These amounts are comprised of the following:

	At December 31,
(Millions of Dollars)	2005	2004
Cost of removal	$139.4	$144.3
CTA, GSC, and SBC overcollections	154.0	200.0
Regulatory liabilities offsetting  derivative assets	391.2	191.4
Other regulatory liabilities	58.4	79.1
Totals	$743.0	$614.8

Cost of Removal:  Under SFAS No. 71, CL&P currently recovers amounts in rates for future costs of removal of plant assets.  These amounts which totaled $139.4 million and $144.3 million at December 31, 2005 and 2004, respectively, are classified as regulatory liabilities on the accompanying consolidated balance sheets.  

CTA, GSC and SBC Overcollections:  The Competitive Transition Assessment (CTA) allows CL&P to recover stranded costs, such as securitization costs associated with the rate reduction bonds, amortization of regulatory assets, and IPP over market costs.  The Generation Service Charge (GSC) allows CL&P to recover the costs of the procurement of energy for standard offer service.  The System Benefits Charge (SBC) allows CL&P to recover certain regulatory and energy public policy costs, such as public education outreach costs, hardship protection costs, transition period property taxes, and displaced workers protection costs.  CL&P CTA, GSC and SBC overcollections totaled $154 million and $200 million at December 31, 2005 and 2004, respectively.  

Regulatory Liabilities Offsetting Derivative Assets:  The regulatory liabilities offsetting derivative assets relate to the fair value of CL&P IPP contracts used to purchase power that will benefit ratepayers in the future.  These amounts totaled $391.2 million and $191.4 million at December 31, 2005 and 2004, 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 DPUC and SFAS No. 109.

Details of income tax expense are as follows:  

	For the Years  Ended December 31,
	2005	2004	2003
	(Millions of Dollars)
The components of the federal    and state income tax provisions are:
Current income taxes:
Federal	$44.7	$(50.6)	$ 115.0
State	4.1	(6.2)	28.8
Total current	48.8	(56.8)	143.8
Deferred income taxes, net:
Federal	(1.8)	99.6	(88.7)
State	(12.2)	5.3	(34.5)
Total deferred	(14.0)	104.9	(123.2)
Investment tax credits, net	(2.6)	(2.6)	(2.5)
Total income tax expense	$32.2	$ 45.5	$   18.1

A reconciliation between income tax expense and the expected tax expense at the statutory rate is as follows:

	For the Years Ended December 31,
	2005	2004	2003
	(Millions of Dollars)
Expected federal income tax expense	$44.5	$46.7	$30.5
Tax effect of differences:
Depreciation	(3.9)	2.0	(0.3)
Investment tax credit        amortization	(2.6)	(2.6)	(2.5)
State income taxes,     net of federal benefit	(5.3)	(0.2)	(3.7)
Tax asset valuation     reserve adjustment	-	-	(5.5)
Medicare subsidy	(2.4)	(0.5)	-
Property taxes	(1.9)	(1.0)	(0.3)
Allowance for doubtful accounts	1.7	(1.0)	1.7
Other, net	2.1	2.1	(1.8)
Total income tax expense	$32.2	$45.5	$18.1

NU and its subsidiaries, including CL&P, file a consolidated federal income tax return.  NU and its subsidiaries, including CL&P, are parties to a tax allocation agreement under which taxable subsidiaries pay no more taxes than they would have otherwise paid had they filed a stand-alone tax return.  Subsidiaries generating tax losses are similarly paid for their losses when utilized.

The tax effects of temporary differences that give rise to the current and long-term net accumulated deferred tax obligations are as follows:

	At December 31,
(Millions of Dollars)	2005	2004
Deferred tax liabilities – current:
Property tax accruals	$ 23.8	$  20.0
Total deferred tax liabilities – current	23.8	20.0
Deferred tax assets – current:
Allowance for uncollectible accounts	8.0	3.7
Total deferred tax assets – current	8.0	3.7
Net deferred tax liabilities – current	15.8	16.3
Deferred tax liabilities – long-term:
Accelerated depreciation and other     plant related differences	633.6	621.4
Securitized costs	44.5	51.8
Income tax gross-up	168.6	166.2
Employee benefits	139.0	126.2
Other	20.4	17.3
Total deferred tax liabilities -  long-term	1,006.1	982.9
Deferred tax assets – long-term:
Regulatory deferrals	158.0	174.3
Employee benefits	15.6	10.8
Income tax gross-up	28.2	25.9
Other	30.1	10.9
Total deferred tax assets – long-term	231.9	221.9
Net deferred tax liabilities – long-term	774.2	761.0
Net deferred tax liabilities	$790.0	$777.3

At December 31, 2005, CL&P had state tax credit carry forwards of $14.9 million that expire between 2009 and 2010.  At December 31, 2004, CL&P had state tax credit carry forwards of $6.8 million that expire on December 31, 2009.

In 2000, NU requested from the Internal Revenue Service (IRS) a Private Letter Ruling (PLR) regarding the treatment of unamortized investment tax credits (ITC) and excess deferred income taxes (EDIT) related to generation assets that have been sold.  EDIT are temporary differences between book and taxable income that were recorded when the federal statutory tax rate was higher than it is now or when those differences were expected to be resolved.  The PLR addresses whether or not EDIT and ITC can be returned to customers, which without a PLR management believes would represent a violation of current tax law.  The IRS declared a moratorium on issuing PLRs until final regulations on the return of EDIT and ITC to regulated customers are issued by the Treasury Department.  Proposed regulations were issued in December of 2005 withdrawing proposed regulations issued in March of 2003.  The new proposed regulations would generally allow EDIT and ITC generated by property that is no longer regulated to be returned to regulated customers without violating the tax law.  The new proposed regulations would only apply to property that ceases to be regulated public utility property after December of 2005.  As such, the EDIT and ITC cannot be used to reduce customer rates.  The ultimate results of this contingency could have a positive impact on CL&P’s earnings.

I.

Depreciation

The provision for depreciation on utility assets is calculated using the straight-line method based on the estimated remaining useful lives of depreciable plant-in-service, which range primarily from 3 years to 50 years, adjusted for salvage value and removal costs, as approved by the appropriate regulatory agency where applicable.  Depreciation rates are applied to plant-in-service from the time it is placed in service.  When plant is retired from service, the original cost of the plant, including costs of removal less salvage, is charged to the accumulated provision for depreciation.  Cost of removal is classified as a regulatory liability.  The depreciation rates for the several classes of electric utility plant-in-service are equivalent to a composite rate of 3.5 percent in 2005, 3.4 percent in 2004 and 3.3 percent in 2003.

J.

Jointly Owned Electric Utility Plant

At December 31, 2005, CL&P owns common stock in the Yankee Companies.  Each of the Yankee Companies owns a single nuclear generating plant which is being decommissioned.  CL&P’s ownership interests in the Yankee Companies at December 31, 2005, which are accounted for on the equity method are 34.5 percent of CYAPC, 24.5 percent of YAEC and 12 percent of MYAPC.  The total carrying value of CYAPC, MYAPC and YAEC, which is included in deferred debits and other assets - other on the accompanying consolidated balance sheets and the electric distribution reportable segment, totaled $19.5 million and $19.4 million at December 31, 2005 and 2004, respectively.  Earnings related to these equity investments are included in other income, net on the accompanying consolidated statements of income.  For further information, see Note 1Q, "Summary of Significant Accounting Policies - Other Income, Net ," to the consolidated financial statements.  

CYAPC filed with the FERC to recover the increased estimate of decommissioning and plant closure costs.  The FERC proceeding is ongoing.  Management believes that the FERC proceeding has not impaired the value of its investment in CYAPC totaling $16 million at December 31, 2005 but will continue to evaluate the impacts that the FERC proceeding has on CL&P's investment.  For further information, see Note 5E, "Commitments and Contingencies - Deferred Contractual Obligations," to the consolidated financial statements.  

K.

Allowance for Funds Used During Construction

The allowance for funds used during construction (AFUDC) is a non-cash item that is included in the cost of CL&P plant and represents the cost of borrowed and equity funds used to finance construction.  The portion of AFUDC attributable to borrowed funds is recorded as a reduction of other interest expense and the cost of equity funds is recorded as other income on the consolidated statements of income as follows:  

	For the Years Ended December 31,
(Millions of Dollars,  except percentages)	2005		2004		2003
Borrowed funds	$  6.7		$3.1		$3.0
Equity funds	9.8		3.4		5.8
Totals	$16.5		$6.5		$8.8
Average AFUDC rate	7.0	%	4.1	%	7.9	%

The average AFUDC rate is based on a FERC-prescribed formula that develops an average rate using the cost of the company's short-term financings as well as the company's capitalization (preferred stock, long-term debt and common equity).  The average rate is applied to eligible construction work in progress amounts to calculate AFUDC.  The increase in the average AFUDC rate during 2005 is primarily due to increases in short-term and long-term debt interest rates.

L.

Sale of Customer Receivables

At December 31, 2005 and 2004, CL&P had sold an undivided interest in its accounts receivable of $80 million and $90 million, respectively, to a financial institution with limited recourse through CRC, a wholly owned subsidiary of CL&P. CRC can sell up to $100 million of an undivided interest in its accounts receivable and unbilled revenues.  At December 31, 2005 and 2004, the reserve requirements calculated in accordance with the Receivables Purchase and Sale Agreement were $21 million and $18.8 million, respectively.  These reserve amounts are deducted from the amount of receivables eligible for sale.  At their present levels, these reserve amounts do not limit CL&P’s ability to access the full amount of the facility.  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.

At December 31, 2005 and 2004, amounts sold to CRC by CL&P but not sold to the financial institution totaling $252.8 million and $139.4 million, respectively, are included as investments in securitizable assets on the accompanying consolidated balance sheets.  These amounts

would be excluded from CL&P’s assets in the event of CL&P’s bankruptcy.  On July 6, 2005, CRC renewed its Receivables Purchase and Sale Agreement with CL&P and the financial institution through July 5, 2006.  CL&P’s continuing involvement with the receivables that are sold to CRC and the financial institution is limited to the servicing of those receivables.

The transfer of receivables to the financial institution under this arrangement qualifies for sale treatment under SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities - A Replacement of SFAS No. 125."

M.

Asset Retirement Obligations

On January 1, 2003, CL&P implemented SFAS No. 143, "Accounting for Asset Retirement Obligations," requiring legal obligations associated with the retirement of property, plant and equipment to 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.  Management concluded that there were no asset retirement obligations (AROs) to be recorded upon implementation of SFAS No. 143.  

In March of 2005, the FASB issued FIN 47, required to be implemented by December 31, 2005.  FIN 47 requires an entity to recognize a liability for the fair value of an ARO even if it is conditional on a future event when the liability’s fair value can be reasonably estimated.  FIN 47 provides that settlement dates and future costs should be reasonably estimated when sufficient information becomes available, and provides guidance on the definition and timing of sufficient information in determining expected cash flows and fair values.  Management has completed its identification of conditional AROs and has identified various categories of AROs, primarily certain assets containing asbestos and hazardous contamination.  A fair value calculation, reflecting expected probabilities for settlement scenarios, and a data consistency review across operating companies have been performed.  

CL&P utilized regulatory accounting in accordance with SFAS No. 71 and the impact of this implementation is included in other regulatory assets at December 31, 2005.  The fair value of the AROs is included in property, plant and equipment and related accretion is recorded as a regulatory asset, with corresponding credits reflecting the ARO liabilities in deferred credits and other liabilities - other, on the accompanying consolidated balance sheet at December 31, 2005.  Depreciation of the ARO asset is also included as a regulatory asset with an offsetting amount in accumulated depreciation.  The following table presents the fair value of the ARO, the related accumulated depreciation, the regulatory asset, and the ARO liabilities:

	At December 31, 2005
(Millions of Dollars)	Fair Value of ARO Asset	Accumulated Depreciation of ARO Asset	Regulatory Asset	ARO Liabilities
Asbestos	$  2.2	$(1.2)	$10.9	$(11.9)
Hazardous   contamination	5.4	(1.2)	9.5	(13.7)
Other AROs	9.2	(3.6)	4.7	(10.3)
Total  AROs	$16.8	$(6.0)	$25.1	$(35.9)

The ARO liabilities as of December 31, 2005, 2004 and January 1, 2004, as if FIN 47 had been applied for all periods affected, were $35.9 million, $29.5 million and $29.1 million, respectively.

N.

Materials and Supplies

Materials and supplies include materials purchased primarily for construction, operation and maintenance (O&M) purposes.  Materials and supplies are valued at the lower of average cost or market.

O.

Restricted Cash – LMP Costs

Restricted cash - LMP costs represents incremental LMP cost amounts that were collected by CL&P and deposited into an escrow account.  

P.

Excise Taxes

Certain excise taxes levied by state or local governments are collected by CL&P from its customers.  These excise taxes are accounted for on a gross basis with collections in revenues and payments in expenses.  For the years ended December 31, 2005, 2004 and 2003, gross receipts taxes, franchise taxes and other excise taxes of $88.2 million, $75.8 million and $76.3 million, respectively, are included in operating revenues and taxes other than income taxes on the accompanying consolidatedstatements of income.  

Q.

Other Income, Net

The pre-tax components of CL&P's other income/(loss) items are as follows:

	For the Years Ended December 31,
(Millions of Dollars)	2005	2004	2003
Other Income:
Investment income	$10.8	$ 7.7	$ 3.0
Equity in earnings of     regional nuclear     generating companies	1.2	0.6	1.8
CL&P procurement fee	17.8	11.7	-
AFUDC - equity funds	9.8	3.4	5.8
Conservation load     management incentive	4.4	4.0	1.5
Return on regulatory      deferrals	1.4	1.8	5.8
Other	4.3	3.6	1.8
Total Other Income	49.7	32.8	19.7
Other Loss:
Charitable donations	(3.5)	(3.4)	(5.2)
Advertising	(1.4)	(0.5)	(0.6)
Loss on investments in     securitizable assets	(1.8)	(0.7)	(0.6)
Rate reduction bond     administrative fees	(1.6)	(1.6)	(1.6)
Lobbying costs	(1.5)	(1.2)	(1.2)
Other	(2.4)	(0.7)	(1.5)
Total Other Loss	(12.2)	(8.1)	(10.7)
Total Other Income, Net	$37.5	$24.7	$ 9.0

None of the amounts in either other income - other or other loss - other are individually significant, as defined by the SEC.    

R.

Provision for Uncollectible Accounts

CL&P maintains a provision for uncollectible accounts to record its receivables at an estimated net realizable value.  This provision is determined based upon a variety of factors, including applying an estimated uncollectible account percentage to each receivables aging category, historical collection and write-off experience and management's assessment of collectibility from individual customers.  Management reviews at least quarterly the collectibility of the receivables, and if circumstances change, collectibility estimates are adjusted accordingly.  Receivable balances are written-off against the provision for uncollectible accounts when these balances are deemed to be uncollectible.  

S.

Severance Benefits

As a result of NU’s decision to pursue a fundamentally different business strategy, and align the structure of the company to support this business strategy, CL&P recorded a $10.1 million severance benefits charge in other operating expenses on the accompanying consolidated statement of income for the year ended December 31, 2005.

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, the FERC, or by the DPUC.  On October 28, 2005, the SEC amended its June 30, 2004 order, granting authorization to allow CL&P to incur total short-term borrowings up to a maximum of $450 million through June 30, 2007.  The SEC also granted authorization for borrowing through the NU Money Pool (Pool) until June 30, 2007.   Although PUHCA was repealed on February 8, 2006, under FERC's transition rules, all of the existing orders under PUHCA relevant to FERC authority will continue to be in effect until December 31, 2007, except for those related to NU, which will have no borrowing limitations after February 8, 2006.  CL&P will be subject to FERC jurisdiction as to issuing short-term debt after February 8, 2006 and must renew any short-term autho rity after the PUHCA order expires on December 31, 2007.  

The charter of CL&P contains preferred stock provisions restricting the amount of unsecured debt that CL&P may incur.  In November of 2003, CL&P obtained authorization from its stockholders to issue unsecured indebtedness with a maturity of less than 10 years in excess of the 10 percent of total capitalization limitation in CL&P's charter, provided that all unsecured indebtedness would not exceed 20 percent of total capitalization for a ten-year period expiring in March of 2014.  On March 18, 2004, the SEC approved this change in CL&P's charter.  As of December 31, 2005, CL&P is permitted to incur $531.9 million of additional unsecured debt.

Credit Agreement:  On December 9, 2005, CL&P amended its 5-year unsecured revolving credit facility by extending the expiration date by one year to November 6, 2010.  The company can borrow up to $200 million on a short-term basis, or subject to regulatory approvals, on a long-term basis.  At December 31, 2005, CL&P had no borrowings outstanding under this facility.  At December 31, 2004, there were $15 million in borrowings under this credit facility.  The weighted-average interest rate on CL&P’s notes payable to banks outstanding on December 31, 2004 was 5.25 percent.

Under this credit agreement, CL&P may borrow at variable rates plus an applicable margin based upon certain debt ratings, as rated by the higher of Standard and Poor’s (S&P) or Moody’s Investors Service (Moody's).   

Under this credit agreement, CL&P must comply with certain financial and non-financial covenants, including but not limited to, a consolidated debt to capitalization ratio.  CL&P currently is and expects to remain in compliance with these covenants.  

Amounts outstanding under this credit facility are classified as current liabilities as notes payable to banks on the accompanying consolidated balance sheets as management anticipates that all borrowings under this credit facility will be outstanding for no more than 364 days at one time.

Pool:  CL&P is a member of the Pool.  The Pool provides a more efficient use of 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, 2005 and 2004, CL&P had borrowings of $26.8 million and $90 million from the Pool, respectively.  The interes t rate on borrowings from the Pool at December 31, 2005 and 2004 was 4.09 percent and 2.24 percent, respectively.

3.  Derivative Instruments  

CL&P has two IPP contracts to purchase power that contain pricing provisions that are not clearly and closely related to the price of power and therefore do not qualify for the normal purchases and sales exception.  The fair values of these IPP non-trading derivatives at December 31, 2005 include derivative assets with a fair value of $391.2 million, of which $82.6 million and $308.6 million are classified as current and long-term derivative assets on the accompanying consolidated balance sheets, respectively, and  derivative liabilities with a fair value of $32.3 million, of which $0.5 million and $31.8 million are classified as current and long-term derivative liabilities on the accompanying consolidated balance sheets, respectively.  An offsetting regulatory liability and an offsetting regulatory asset were recorded as management believes that these costs will continue to be recovered or refunded in rate s.  At December 31, 2004, the fair values of these IPP non-trading derivatives included derivative assets with a fair value of $191.3 million, of which $24.2 million and $167.1 million are classified as current and long-term derivative assets on the accompanying consolidated balance sheets, respectively, and derivative liabilities with a fair value of $47.2 million, of which $4.4 million and $42.8 million are classified as current and long-term derivative liabilities on the accompanying consolidated balance sheets, respectively.

4.  Pension Benefits and Postretirement Benefits Other Than Pensions  

Pension Benefits:  CL&P participates in a uniform noncontributory defined benefit retirement plan (Pension Plan) covering substantially all regular NU employees.  Benefits are based on years of service and the employees’ highest eligible compensation during 60 consecutive months of employment.  CL&P uses a December 31^st measurement date for the Pension Plan.  Pension expense/(income) attributable to earnings is as follows:

	For the Years Ended December 31,
(Millions of Dollars)	2005	2004	2003
Total pension expense/(income)	$3.0	$(13.2)	$(29.1)
Amount capitalized as utility plant	(1.5)	6.4	15.1
Total pension expense/(income),   net of amounts capitalized	$ 1.5	$(6.8)	$(14.0)

Amounts above include pension curtailments and termination benefits expenses of $3.6 million in 2005 and $1.1 million in 2004.  

Not included in the pension expense/(income) amount above are pension related intercompany allocations totaling $8.8 million, $2.5 million and $(1) million for the years ended December 31, 2005, 2004 and 2003, respectively, including pension curtailment and termination benefits expense of $2.4 million and $0.5 million for the years ended December 31, 2005 and 2004.  These amounts are included in other operating expenses on the accompanying consolidated financial statements.  

Pension Curtailments and Termination Benefits:  As a result of the decision to pursue a fundamentally different business strategy, and align the structure of the company to support this business strategy, CL&P recorded a $1 million pre-tax curtailment expense in 2005.  CL&P also accrued certain related termination benefits and recorded a $1.3 million pre-tax charge in 2005.

On December 15, 2005, the NU Board of Trustees approved a benefit for new non-union employees hired on and after January 1, 2006 to receive retirement benefits under a new 401(k) benefit rather than under the Pension Plan.  Non-union employees actively employed on December 31, 2005 will be given the choice in 2006 to elect to continue participation in the Pension Plan or instead receive a new employer contribution under the 401(k) Savings Plan effective January 1, 2007.  If the new benefit is elected, their accrued pension liability in the Pension Plan will be frozen as of December 31, 2006.  Non-union employees will make this election in the second half of 2006.  This decision resulted in CL&P recording an estimated pre-tax curtailment expense of $1.3 million in 2005, as a certain number of employees are expected to elect the new 401(k) benefit, resulting in a reduction in aggregate estimated future years of service under th e Pension Plan.  Management estimated the amount of the curtailment expense associated with this change based upon actuarial calculations and certain assumptions, including the expected level of transfers to the new 401(k) benefit.

In April of 2004, as a result of litigation with nineteen former employees, NU was ordered by the court to modify its Pension Plan to include special retirement benefits for fifteen of these former employees retroactive to the dates of their retirement and provide increased future monthly benefit payments.  CL&P recorded $1.1 million in termination benefits related to this litigation in 2004 and made a lump sum benefit payment totaling $0.8 million to these former employees.

There were no curtailments or termination benefits in 2003 that impacted earnings.

Market-Related Value of Pension Plan Assets:  CL&P bases the actuarial determination of pension plan income or expense on a market-related valuation of assets, which reduces year-to-year volatility.  This market-related valuation calculation recognizes investment gains or losses over a four-year period from the year in which they occur.  Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the fair value of assets.  Since the market-related valuation calculation recognizes gains or losses over a four-year period, the future value of the market-related assets will be impacted as previously deferred gains or losses are recognized.

Postretirement Benefits Other Than Pensions:  CL&P also provides certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired employees (PBOP Plan).  These benefits are available for employees retiring from CL&P who have met specified service requirements.  For current employees and certain retirees, the total benefit is limited to two times the 1993 per retiree health care cost.  These costs are charged to expense over the estimated work life of the employee.  CL&P uses a December 31^st measurement date for the PBOP Plan.  

CL&P annually funds postretirement costs through external trusts with amounts that have been and will continue to be recovered in rates and which also are tax deductible.  Currently, there are no pending regulatory actions regarding postretirement benefit costs and there are no postretirement benefit costs that are deferred as regulatory assets.

Impact of New Medicare Changes on PBOP:  On December 8, 2003, the President signed into law a bill that expands Medicare, primarily by adding a prescription drug benefit starting in 2006 for Medicare-eligible retirees as well as a federal subsidy to plan sponsors of retiree health care benefit plans who provide a prescription drug benefit at least actuarially equivalent to the new Medicare benefit.

Based on the current PBOP Plan provisions, CL&P qualifies for this federal subsidy because the actuarial value of CL&P’s PBOP Plan exceeds the threshold required for the subsidy.  The Medicare changes decreased the PBOP benefit obligation by $13 million.  The total $13 million decrease is currently being amortized as a reduction to PBOP expense over approximately 13 years.  For the years ended December 31, 2005 and 2004, this reduction in PBOP expense totaled approximately $1.7 million, including amortization of the actuarial gain of $0.9 million and a reduction in interest cost and service cost based on a lower PBOP benefit obligation of $0.8 million.

PBOP Curtailments and Termination Benefits:  CL&P recorded an estimated $2.5 million pre-tax curtailment expense at December 31, 2005 relating to NU's change in business strategy.  CL&P also accrued a $0.2 million pre-tax termination benefit at December 31, 2005 relating to certain benefits provided under the terms of the PBOP Plan.  

There were no curtailments or termination benefits in 2004 or 2003.

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)	2005	2004	2005	2004
Change in benefit obligation
Benefit obligation at beginning of year	$(800.0)	$(731.3)	$(192.4)	$(169.3)
Service cost	(17.2)	(14.7)	(2.8)	(2.1)
Interest cost	(46.8)	(44.8)	(10.2)	(10.5)
Transfers	0.2	(2.0)	-	(0.8)
Actuarial loss	(53.3)	(52.0)	(11.3)	(24.8)
Benefits paid - excluding lump sum payments	47.3	45.1	15.9	15.1
Benefits paid - lump sum payments	-	0.8	-	-
Curtailment/impact of plan changes	11.8	-	0.3	-
Termination benefits	(1.3)	(1.1)	(0.2)	-
Benefit obligation at end of year	$(859.3)	$(800.0)	$(200.7)	$(192.4)
Change in plan assets
Fair value of plan assets at beginning of year	$965.4	$ 899.3	$    74.9	$    64.3
Actual return on plan assets	72.8	110.0	4.6	6.3
Employer contribution	-	-	21.5	18.6
Transfers	(0.2)	2.0	-	0.8
Benefits paid - excluding lump sum payments	(47.3)	(45.1)	(15.9)	(15.1)
Benefits paid - lump sum payments	-	(0.8)	-	-
Fair value of plan assets at end of year	$ 990.7	$ 965.4	$    85.1	$    74.9
Funded status at December 31st	$ 131.4	$ 165.4	$(115.6)	$(117.5)
Unrecognized transition obligation	-	-	41.4	50.3
Unrecognized prior service cost	16.7	23.2	-	-
Unrecognized net loss	167.4	130.0	$   70.7	66.5
Prepaid/(accrued) benefit cost	$ 315.5	$ 318.6	$   (3.5)	$    (0.7)

The $11.8 million reduction in the plan's obligation that is included in the curtailment/impact of plan changes relates to the reduction in the future years of service expected to be rendered by plan participants.  This reduction is the result of the transition of employees into the new 401(k) benefit and the company's decision to pursue a fundamentally different business strategy, and align the structure of the company to support this business strategy.  This overall reduction in plan obligation serves to reduce the previously unrecognized actuarial losses.

The company amortizes its unrecognized transition obligation over the remaining service lives of its employees as calculated for CL&P on an individual operating company basis.  The company amortizes the unrecognized prior service cost and unrecognized net loss over the remaining service lives of its employees as calculated on a NU consolidated basis.  

The accumulated benefit obligation for the Pension Plan was $769.6 million and $696.8 million at December 31, 2005 and 2004, respectively.

The following actuarial assumptions were used in calculating the plans’ year end funded status:

	At December 31,
	Pension Benefits				Postretirement Benefits
Balance Sheets	2005		2004		2005		2004
Discount rate	5.80	%	6.00	%	5.65	%	5.50	%
Compensation/progression rate	4.00	%	4.00	%	N/A		N/A
Health care cost trend rate	N/A		N/A		7.00	%	8.00	%

The components of net periodic expense/(income) are as follows:

	For the Years Ended December 31,
	Pension Benefits			Postretirement Benefits
(Millions of Dollars)	2005	2004	2003	2005	2004	2003
Service cost	$17.1	$ 14.7	$ 12.8	$ 2.8	$  2.1	$  2.0
Interest cost	46.8	44.8	44.4	10.2	10.5	11.3
Expected return on plan assets	(80.1)	(81.3)	(84.1)	(4.9)	(4.6)	(5.1)
Amortization of unrecognized net   transition (asset)/obligation	- -	(0.9)	(0.9)	6.3	6.3	6.3
Amortization of prior service cost	3.0	3.0	3.0	-	-	-
Amortization of actuarial loss/(gain)	12.6	5.4	(4.3)	-	-	-
Other amortization, net	-	-	-	7.1	4.3	2.1
Net periodic (income)/expense – before  curtailments and termination benefits	(0.6)	(14.3)	(29.1)	21.5	18.6	16.6
Curtailment expense	2.3	-	-	2.5	-	-
Termination benefits expense	1.3	1.1	-	0.2	-	-
Total curtailments and termination benefits	3.6	1.1	-	2.7	-	-
Total - net periodic expense/(income)	$  3.0	$(13.2)	$(29.1)	$24.2	$18.6	$16.6

For calculating pension and postretirement benefit expense and income amounts, the following assumptions were used:

	For the Years Ended December 31,
Statements of Income	Pension Benefits						Postretirement Benefits
	2005		2004		2003		2005		2004		2003
Discount rate	6.00	%	6.25	%	6.75	%	5.50	%	6.25	%	6.75	%
Expected long-term rate of return	8.75	%	8.75	%	8.75	%	N/A		N/A		N/A
Compensation/progression rate	4.00	%	3.75	%	4.00	%	N/A		N/A		N/A
Expected long-term rate of return -
Health assets, net of tax	N/A		N/A		N/A		6.85	%	6.85	%	6.85	%
Life assets and non-taxable     health assets	N/A		N/A		N/A		8.75	%	8.75	%	8.75	%

The following table represents the PBOP assumed health care cost trend rate for the next year and the assumed ultimate trend rate:

	Year Following December 31,
	2005		2004
Health care cost trend rate   assumed for next year	10.00	%	7.00	%
Rate to which health care   cost trend rate is assumed to   decline (the ultimate trend   rate)	5.00	%	5.00	%
Year that the rate reaches   the ultimate trend rate	2011		2007

At December 31, 2004, the health care cost trend assumption was assumed to decrease by one percentage point each year through 2007.  For December 31, 2005 disclosure purposes, the health care cost trend assumption was reset for 2006 at 10 percent, decreasing one percentage point per year to an ultimate rate of 5 percent in 2011.  

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:

(Millions of Dollars)	One Percentage Point Increase	One Percentage Point Decrease
Effect on total service and   interest cost components	$0.4	$(0.3)
Effect on postretirement   benefit obligation	$7.3	$(6.4)

CL&P's investment strategy for its Pension Plan and PBOP Plan is to maximize the long-term rate of return on those plans' assets within an acceptable level of risk.  The investment strategy establishes target allocations, which are routinely reviewed and periodically rebalanced.  CL&P's expected long-term rates of return on Pension Plan assets and PBOP Plan assets are based on these target asset allocation assumptions and related expected long-term rates of return.  In developing its expected long-term rate of return assumptions for the Pension Plan and the PBOP Plan, CL&P also evaluated input from actuaries and consultants as well as long-term inflation assumptions and CL&P's historical 20-year compounded return of approximately 11 percent.  The Pension Plan's and PBOP Plan's target asset allocation assumptions and expected long-term rate of return assumptions by asset category are as follows:

	At December 31,
	Pension Benefits		Postretirement Benefits
	2005 and 2004		2005 and 2004
Asset Category	Target Asset Allocation	Assumed Rate of Return	Target Asset Allocation	Assumed Rate of Return
Equity securities:
United States	45%	9.25%	55%	9.25%
Non-United States	14%	9.25%	11%	9.25%
Emerging markets	3%	10.25%	2%	10.25%
Private	8%	14.25%	-	-
Debt Securities:
Fixed income	20%	5.50%	27%	5.50%
High yield fixed     income	5%	7.50%	5%	7.50%
Real estate	5%	7.50%	-	-

The actual asset allocations at December 31, 2005 and 2004, approximated these target asset allocations.  The plans’ actual weighted-average asset allocations by asset category are as follows:  

	At December 31,
	Pension Benefits		Postretirement Benefits
Asset Category	2005	2004	2005	2004
Equity securities:
United States	46%	47%	54%	55%
Non-United States	16%	17%	14%	14%
Emerging markets	4%	3%	1%	1%
Private	5%	4%	-	-
Debt Securities:
Fixed income	19%	19%	29%	28%
High yield fixed     income	5%	5%	2%	2%
Real estate	5%	5%	-	-
Total	100%	100%	100%	100%

Estimated Future Benefit Payments:  The following benefit payments, which reflect expected future service, are expected to be paid for the Pension and PBOP Plans:

(Millions of Dollars)
Year	Pension Benefits	Postretirement Benefits	Government Subsidy
2006	$  48.9	$18.8	$ 2.0
2007	50.2	19.1	2.1
2008	51.2	18.9	2.2
2009	52.2	18.8	2.3
2010	53.2	18.6	2.4
2011-2015	280.6	89.1	13.8

Government subsidy represents amounts expected to be received from the federal government for the new Medicare prescription drug benefit under the PBOP Plan.

Contributions:  CL&P does not expect to make any contributions to the Pension Plan in 2006 and expects to make $21 million in contributions to the PBOP Plan in 2006.  

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.

Postretirement health plan assets for non-union employees are subject to federal income taxes.

5.  Commitments and Contingencies   

A.

Regulatory Developments and Rate Matters

CTA and SBC Reconciliation: The CTA allows CL&P to recover stranded costs, such as securitization costs associated with the rate reduction bonds, amortization of regulatory assets, and IPP over market costs, while the SBC allows CL&P to recover certain regulatory and energy public policy costs, such as public education outreach costs, hardship protection costs, transition period property taxes, and displaced worker protection costs.

A final decision in the 2004 CTA and SBC docket was issued on December 19, 2005 by the DPUC.  That decision ordered a refund to customers of $100.8 million over the twelve-month period beginning with January 2006 consumption.  In a subsequent decision in CL&P’s docket to establish the 2006 transitional standard offer (TSO) rates dated December 28, 2005, the DPUC ordered CL&P to issue a revised CTA refund of $108 million over the twelve-month period beginning with January 2006 consumption and an additional CTA refund of $40 million for the months of January, February and March of 2006.  

In the 2001 CTA and SBC reconciliation filing, and subsequently in a September 10, 2002 petition to reopen related proceedings, CL&P requested that a deferred intercompany tax liability associated with the intercompany sale of generation assets be excluded from the calculation of CTA revenue requirements. This liability is currently included as a reduction in the calculation CTA revenue requirements.  On September 10, 2003, the DPUC issued a final decision denying CL&P’s request, and on October 24, 2003, CL&P appealed the DPUC’s final decision to the Connecticut Superior Court.  The appeal has been fully briefed and argued.  If CL&P’s request is granted and upheld through these court proceedings, there would be additional amounts due to CL&P from its customers.  The amount due is contingent upon the findings of the court.  However, management believes that CL&P's pre-tax earnings would incre ase by a minimum of $15 million in 2006 if CL&P's position is adopted by the court.  

B.

Environmental Matters

General:  CL&P is subject to environmental laws and regulations intended to mitigate or remove the effect of past operations and improve or maintain the quality of the environment.  These laws and regulations require the removal or the remedy of the effect on the environment of the disposal or release of certain specified hazardous substances at current and former operating sites.  As such, CL&P has an active environmental auditing and training program and believes that it is substantially in compliance with all enacted laws and regulations.

Environmental reserves are accrued using a probabilistic model approach when assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated.  The probabilistic model approach estimates the liability based on the most likely action plan from a variety of available remediation options, including, no action is required or several different remedies ranging from establishing institutional controls to full site remediation and monitoring.  

These estimates are subjective in nature as they take into consideration several different remediation options at each specific site.  The reliability and precision of these estimates can be affected by several factors including new information concerning either the level of contamination at the site, recently enacted laws and regulations or a change in cost estimates due to certain economic factors.  

The amounts recorded as environmental liabilities on the consolidated balance sheets represent management’s best estimate of the liability for environmental costs and takes into consideration site assessment and remediation costs.  Based on currently available information for estimated site assessment and remediation costs at December 31, 2005 and 2004, CL&P had $2.7 million and $7.8 million, respectively, recorded as environmental reserves.  A reconciliation of the activity in these reserves at December 31, 2005 and 2004 is as follows:

	For the Years Ended December 31,
(Millions of Dollars)	2005	2004
Balance at beginning of year	$7.8	$7.9
Additions and adjustments	(5.0)	0.2
Payments	(0.1)	(0.3)
Balance at end of year	$2.7	$7.8

CL&P currently has 11 sites included in the environmental reserve.  Of those 11 sites, 4 sites are in the remediation or long-term monitoring phase, 6 sites have had some level of site assessment completed and the remaining site is in the preliminary stage of site assessment.

For 3 sites that are included in the company's liability for environmental costs, the information known and nature of the remediation options at those sites allows for an estimate of the range of losses to be made.  These sites primarily relate to manufactured gas plant (MGP) sites.  At December 31, 2005, $1.8 million has been accrued as a liability for these sites, which represents management's best estimate of the liability for environmental costs.  This amount differs from an estimated range of loss from $1.6 million to $6 million as management utilizes the probabilistic model approach to make its estimate of the liability for environmental costs.  

For the 8 remaining sites for which an estimate is based on the probabilistic model approach, determining a range of estimated losses is not possible.  These liabilities are estimated on an undiscounted basis and do not assume that any amounts are recoverable from insurance companies or other third parties.  The environmental reserve includes sites at different stages of discovery and remediation and does not include any unasserted claims.  

At December 31, 2005, there are 6 sites for which there are unasserted claims, however, any related remediation costs are not probable or estimable at this time.  CL&P's environmental liability also takes into account recurring costs of managing hazardous substances and pollutants, mandated expenditures to remediate previously contaminated sites and any other infrequent and non-recurring clean up costs.

It is possible that new information or future developments could require a reassessment of the potential exposure to related environmental matters.  As this information becomes available, management will continue to assess the potential exposure and adjust the reserves.

MGP Sites:  MGP sites comprise the largest portion of CL&P's environmental liability.  MGPs are sites that manufactured gas from coal which produced certain byproducts that may pose a risk to human health and the environment.  At December 31, 2005 and 2004, $1.5 million and $6.5 million, respectively, represents amounts for the site assessment and remediation of MGPs.  CL&P currently has 4 MGP sites included in its environmental liability.  Of the 4 MGP sites, 3 sites are currently in the site assessment stage and one site is in the preliminary stage of site assessment.

On January 19, 2005, the DPUC issued a final decision approving the sale proceeding of a former MGP site that was held for sale at December 31, 2004.  The final decision approved the price of $24 million for the sale of the land and also approved the deferral of the gain in the amount of $14.0 million ($8.4 million net of tax).  At December 31, 2004, CL&P had $7.9 million related to remediation efforts at the property and other sale costs recorded in other deferred debits and other assets – other on the accompanying consolidated balance sheets.  During 2005, the former MGP site was sold to an independent third party.  

CERCLA Matters:  The Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA) and its’ amendments or state equivalents impose joint and several strict liabilities, regardless of fault, upon generators of hazardous substances resulting in removal and remediation costs and environmental damages.  Liabilities under these laws can be material and in some instances may be imposed without regard to fault or for past acts that may have been lawful at the time they occurred.  CL&P has two superfund sites under CERCLA for which it has been notified that it is a potentially responsible party (PRP).  For sites where there are other PRPs and CL&P is not managing the site assessment and remediation, the liability accrued represents CL&P's estimate of what it will pay to settle its obligations with respect to the site.

It is possible that new information or future developments could require a reassessment of the potential exposure to related environmental matters.  As this information becomes available management will continue to assess the potential exposure and adjust the reserves.  

Rate Recovery:  CL&P recovers a certain level of environmental costs currently in rates but does not have an environmental cost recovery tracking mechanism.  Accordingly, changes in CL&P's environmental reserves impact CL&P's earnings.  

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, 2005 and 2004, fees due to the DOE for the disposal of Prior Period Fuel were $216.9 million and $210.4 million, respectively, including interest costs of $150.4 million and $143.9 million, respectively.

D.

Long-Term Contractual Arrangements

Vermont Yankee Nuclear Power Corporation (VYNPC):  Previously under the terms of its agreement, CL&P paid its ownership (or entitlement) share 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 Corporation for approximately $180 million.  CL&P has commitments to buy approximately 9.5 percent of the plant's output through March of 2012 at a range of fixed prices.  The total cost of purchases under contracts with VYNPC amounted to $15.3 million in 2005, $15.9 million in 2004 and $17.8 million in 2003.

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 $148 million in 2005, $200 million in 2004 and $157.8 million in 2003.  These amounts relate to IPP contracts and do not include contractual commitments related to CL&P's TSO or 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.  The total cost of this agreement amounted to $12 million in 2005, $13.5 million in 2004 and $14.4 million in 2003.

Transmission Business Project Commitments:  These amounts represent commitments for various services and materials associated with CL&P's Bethel, Connecticut to Norwalk, Connecticut and the Middletown, Connecticut to Norwalk, Connecticut projects and other projects.  

Yankee Companies FERC-Approved Billings, Subject to Refund:  CL&P has significant decommissioning and plant closure cost obligations to the Yankee Companies.  Each plant has been shut down and is undergoing decommissioning.  The Yankee Companies collect decommissioning and closure costs through wholesale, FERC-approved rates charged under power purchase agreements with several New England utilities, including CL&P.  CL&P in turn passes these costs on to its customers through DPUC-approved retail rates.  YAEC and MYAPC received FERC approval to collect all presently estimated decommissioning and closure costs.  On November 23, 2005, YAEC submitted an application to the FERC to increase YAEC's wholesale decommissioning charges.  On January 31, 2006, the FERC issued an order accepting the rate increase, effective February 1, 2006, subject to refund after hearings and settlement judge proceeding s.  CYAPC received an order on August 30, 2004 from the FERC allowing collection of its decommissioning and closure costs, subject to refund.  The table of estimated future annual costs below includes the decommissioning and closure costs for YAEC, MYAPC and CYAPC.

Estimated Future Annual Costs:  The estimated future annual costs of CL&P’s significant long-term contractual arrangements at December 31, 2005 are as follows:

(Millions of Dollars)	2006	2007	2008	2009	2010	Thereafter
VYNPC	$ 17.0	$ 16.3	$ 16.5	$ 18.0	$ 17.3	$ 22.0
Electricity procurement   contracts	211.5	212.5	200.5	170.6	148.9	745.5
Hydro-Quebec	13.3	12.8	12.7	12.5	12.5	124.1
Transmission business  project commitments	173.8	7.0	7.0	7.0	-	- -
Yankee Companies   FERC-approved   billings, subject    to refund	64.2	51.2	44.3	42.1	41.4	-
Totals	$479.8	$299.8	$281.0	$250.2	$220.1	$891.6

E.

Deferred Contractual Obligations

FERC Proceedings:  In 2003, CYAPC increased the estimated decommissioning and plant closure costs for the period 2000 through 2023 by approximately $395 million over the April 2000 estimate of $436 million approved by the FERC in a 2000 rate case settlement.  The revised estimate reflects the increases in the projected costs of spent fuel storage, increased security and liability and property insurance costs, and the fact that CYAPC is now self performing all work to complete the decommissioning of the plant due to the termination of the decommissioning contract with Bechtel Power Corporation (Bechtel) in July of 2003.  CL&P's share of CYAPC's increase in decommissioning and plant closure costs is approximately $136 million.  On July 1, 2004, CYAPC filed with the FERC for recovery seeking to increase its annual decommissioning collections from $16.7 million to $93 million for a six-year p eriod beginning on January 1, 2005.  On August 30, 2004, the FERC issued an order accepting the rates, with collection beginning on February 1, 2005, subject to refund.

Both the DPUC and Bechtel filed testimony in the FERC proceeding claiming that CYAPC was imprudent in its management of the decommissioning project.  In its testimony, the DPUC recommended a disallowance of $225 million to $234 million out of CYAPC's requested rate increase of approximately $395 million.  CL&P's share of the DPUC's recommended disallowance would be between $78 million to $81 million.  The FERC staff also filed testimony that recommended a $38 million decrease in the requested rate increase claiming that CYAPC should have used a different gross domestic product (GDP) escalator.  CL&P's share of this recommended decrease is $13.1 million.  

On November 22, 2005, a FERC ALJ issued an initial decision finding no imprudence on CYAPC's part.  However, the ALJ did agree with the FERC staff’s position that a lower GDP escalator should be used for calculating the rate increase and found that CYAPC should recalculate its decommissioning charges to reflect the lower escalator.  Briefs to the full FERC addressing these issues were filed in January and February of 2006, and a final order is expected later in 2006.  Management expects that if the FERC staff's position on the decommissioning GDP cost escalator is found by the FERC to be more appropriate than that used by CYAPC to develop its proposed rates, then CYAPC would review whether to reduce its estimated decommissioning obligation and reduce the customers' obligation, including CL&P.    

The company cannot at this time predict the timing or outcome of the FERC proceeding required for the collection of the increased CYAPC decommissioning costs.  The company believes that the costs have been prudently incurred and will ultimately be recovered from the customers of CL&P.  However, there is a risk that some portion of these increased costs may not be recovered, or will have to be refunded if recovered, as a result of the FERC proceedings.  

On June 10, 2004, the DPUC and the Connecticut OCC filed a petition seeking a declaratory order that CYAPC be allowed to recover all decommissioning costs from its wholesale purchasers, including CL&P, but that such purchasers may not be allowed to recover in their retail rates any costs that the FERC might determine to have been imprudently incurred.  On August 30, 2004, the FERC denied this petition.  On September 29, 2004, the DPUC and OCC asked the FERC to reconsider the petition and on October 20, 2005, the FERC denied the reconsideration, holding that the sponsor companies are only obligated to pay CYAPC for prudently incurred decommissioning costs and the FERC has no jurisdiction over the sponsors' rates to their retail customers.  On December 12, 2005, the DPUC sought review of these orders by the United States Court of Appeals for the D.C. Circuit.  The FERC and CYAPC have asked the court to dismiss the case and the DPUC has objected to a dismissal.  CL&P cannot predict the timing or the outcome of these proceedings.

Bechtel Litigation:  CYAPC and Bechtel commenced litigation in Connecticut Superior Court over CYAPC's termination of Bechtel's contract for the decommissioning of CYAPC's nuclear generating plant.  After CYAPC terminated the contract, responsibility for decommissioning was transitioned to CYAPC, which recommenced the decommissioning process.

On March 7, 2006, CYAPC and Bechtel executed a settlement agreement terminating this litigation.  Bechtel has agreed to pay CYAPC $15 million, and CYAPC will withdraw its termination of the contract for default and deem it terminated by agreement.

Spent Nuclear Fuel Litigation:  CYAPC, YAEC and MYAPC (Yankee Companies) also commenced litigation in 1998 charging that the federal government breached contracts it entered into with each company in 1983 under the Act.  Under the Act, the DOE was to begin removing spent nuclear fuel from the nuclear plants of the Yankee Companies no later than January 31, 1998 in return for payments by each company into the nuclear waste fund.  No fuel has been collected by the DOE, and spent nuclear fuel is stored on the sites of the Yankee Companies' plants.  The Yankee Companies collected the funds for payments into the nuclear waste fund from wholesale utility customers under FERC-approved contract rates.  The wholesale utility customers in turn collect these payments from their retail electric customers.  The Yankee Companies' individual damage claims attributed to the government's breach ranging between $523 million and $543 mi llion are specific to each plant and include incremental storage, security, construction and other costs through 2010.  The CYAPC damage claim

ranges from $186 million to $198 million, the YAEC damage claim ranges from $177 million to $185 million and the MYAPC damage claim is $160 million.  The DOE trial ended on August 31, 2004 and a verdict has not been reached.  Post-trial findings of facts and final briefs were filed by the parties in January of 2005.  The Yankee Companies' current rates do not include an amount for recovery of damages in this matter.  Management can predict neither the outcome of this matter nor its ultimate impact on CL&P.

YAEC:   In November of 2005, YAEC established an updated estimate of the cost of completing the decommissioning of its plant resulting in an increase of approximately $85 million.  CL&P's share of the increase in estimated costs is $20.8 million.  This estimate reflects the cost of completing site closure activities from October of 2005 forward and storing spent nuclear fuel and other high level waste on site until 2020, when it is assumed to be removed by the DOE.  This estimate projects a cost of $192.1 million for the completion of decommissioning and long-term fuel storage.  To fund these costs, on November 23, 2005, YAEC submitted an application to the FERC to increase YAEC’s wholesale decommissioning charges.  The DPUC and the Massachusetts attorney general protested these increases.  On January 31, 2006, the FERC issued an order accepting the rate increase, effective February 1, 2006, su bject to refund after hearings and settlement judge proceedings.  The hearings have been suspended pending settlement discussions between YAEC, the FERC and other intervenors in the case.  CL&P has a 24.5 percent ownership interest in YAEC and can predict neither the outcome of this matter nor its ultimate impact on CL&P.

F.

NRG Energy, Inc. Exposures

CL&P has entered into transactions with NRG Energy, Inc. (NRG) and certain of its subsidiaries.  On May 14, 2003, NRG and certain of its subsidiaries filed voluntary bankruptcy petitions and on December 5, 2003, NRG emerged from bankruptcy.  CL&P's NRG-related exposures as a result of these transactions relate to 1) the recovery of congestion charges incurred by NRG prior to the implementation of standard market design (SMD) on March 1, 2003, which is still pending before the court, 2) the recovery of CL&P's station service billings from NRG, which is currently subject of an arbitration, and 3) the recovery of CL&P’s expenditures that were incurred related to an NRG subsidiary’s generating plant construction project has ceased.  While it is unable to determine the ultimate outcome of these issues, management does not expect their resolution will have a material adverse effect on CL&P's consolidated financial condition or results of operations.

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:

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, 2005
(Millions of Dollars)	Carrying Amount	Fair Value
Preferred stock not subject   to mandatory redemption	$116.2	$ 98.5
Long-term debt -
First mortgage bonds	619.8	649.2
Other long-term debt	640.8	655.7
Rate reduction bonds	856.5	912.9

	At December 31, 2004
(Millions of Dollars)	Carrying Amount	Fair Value
Preferred stock not subject   to mandatory redemption	$116.2	$   101.4
Long-term debt -
First mortgage bonds	419.8	470.1
Other long-term debt	634.3	652.6
Rate reduction bonds	995.2	1,074.9

Other long-term debt includes $216.9 million and $210.4 million of fees and interest due for spent nuclear fuel disposal costs at December 31, 2005 and 2004, respectively.  

Other Financial Instruments:  The carrying value of financial instruments included in current assets and current liabilities, including investments in securitizable assets, approximates their fair value.

7.  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.  Certain lease agreements contain contingent lease payments.  The contingent lease payments are based on various factors, such as, the commercial paper rate plus a credit spread or the consumer price index.

Capital lease rental payments were $3 million in both 2005 and 2004 and $3.1 million in 2003.  Interest included in capital lease rental payments was $1.8 million in both 2005 and 2004 and $2 million in 2003.  Capital lease asset amortization was $1.2 million in both 2005 and 2004 and $1.1 million in 2003.  

Operating lease rental payments charged to expense were $20 million in 2005, $14.7 million in 2004 and $11.9 million in 2003. The capitalized portion of operating lease payments was approximately $6.2 million, $4.2 million, and $3.7 million for the years ended December 31, 2005, 2004, and 2003, respectively.  

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, 2005 are as follows:

	Capital Leases	Operating Leases
2006	$ 2.4	$   19.5
2007	2.4	18.4
2008	2.1	15.5
2009	2.0	11.0
2010	1.5	9.2
Thereafter	16.6	26.5
Future minimum lease payments	27.0	$100.1
Less amount representing interest	13.5
Present value of future minimum    lease payments	$13.5

8.  Dividend Restrictions

The Federal Power Act and certain state statutes limit the payment of dividends by CL&P to its retained earnings balance.  At December 31, 2005, retained earnings available for payment of dividends is restricted to $382.6 million.

9.  Accumulated Other Comprehensive Income/(Loss)

The accumulated balance for each other comprehensive income/(loss) item is as follows:

(Millions of Dollars)	December 31, 2004	Current Period Change	December 31, 2005
Unrealized gains   on securities	$   0.1	$   -	$ 0.1
Minimum supplemental   executive retirement   pension liability   adjustments	(0.5)	0.1	(0.4)
Accumulated other   comprehensive   (loss)/income	$(0.4)	$0.1	$(0.3)

(Millions of Dollars)	December 31, 2003	Current Period Change	December 31, 2004
Unrealized gains   on securities	$ 0.1	$     -	$   0.1
Minimum supplemental   executive retirement   pension liability   adjustments	(0.4)	(0.1)	(0.5)
Accumulated other   comprehensive loss	$(0.3)	$(0.1)	$(0.4)

The changes in the components of other comprehensive income/(loss) are reported net of the following income tax effects:

(Millions of Dollars)	2005	2004	2003
Unrealized gains   on securities	$     -	$    -	$(0.1)
Minimum supplemental   executive retirement   pension liability   adjustments	(0.1)	0.1	0.3
Accumulated other   comprehensive   (loss)/income	$(0.1)	$ 0.1	$ 0.2

The unrealized gains on securities above relate to $2 million and $1.9 million of Supplemental Executive Retirement Plan (SERP) securities at December 31, 2005 and 2004, respectively, that are included in prepayments and other on the accompanying consolidated balance sheets.

10. Preferred Stock Not Subject to Mandatory Redemption  

Details of preferred stock not subject to mandatory redemption are as follows (in millions except in redemption price and shares):   

Description	December 31, 2005 Redemption Price	Shares Outstanding at December 31, 2005 and 2004	December 31,
			2005	2004
$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		2,324,000	$116.2	$116.2

11. Long-Term Debt 

Details of long-term debt outstanding are as follows:

At December 31,	2005	2004
	(Millions of Dollars)
First Mortgage Bonds:
7.875% Series D due 2024	$   139.8	$   139.8
4.800% Series A due 2014	150.0	150.0
5.750% Series B due 2034	130.0	130.0
5.000% Series A due 2015	100.0	-
5.625% Series B due 2035	100.0	-
Total First Mortgage Bonds	619.8	419.8
Pollution Control Notes:
5.85%-5.90%, fixed rate,     due 2016-2022	46.4	46.4
5.85%-5.95%, fixed rate tax     exempt, due 2028	315.5	315.5
Variable rate, tax exempt, due 2031	62.0	62.0
Total Pollution Control Notes	423.9	423.9
Total First Mortgage Bonds and   Pollution Control Notes	1,043.7	843.7
Fees and interest due for spent   nuclear fuel disposal costs	216.9	210.4
Less amounts due within one year	-	-
Unamortized premium and   discount, net	(1.7)	(1.2)
Long-term debt	$1,258.9	$1,052.9

There are no cash sinking fund requirements or debt maturities for the years 2006 through 2010.

Essentially, all utility plant of CL&P is subject to the liens of the company's first mortgage bond indenture.

CL&P has $315.5 million of tax-exempt Pollution Control Revenue Bonds (PCRBs) 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 PCRBs with bond insurance secured by the first mortgage bonds.  For financial reporting purposes, these first mortgage bonds would not be considered outstanding unless CL&P failed to meet its obligations under the PCRBs.  

CL&P’s long-term debt agreements provide that it must comply with certain financial and non-financial covenants as are customarily included in such agreements.  CL&P currently is and expects to remain in compliance with these covenants.  

On April 7, 2005, CL&P issued $100 million of First Mortgage Bonds (the Series A Bonds) with a fixed coupon of 5.00 percent and a maturity of April 1, 2015.  The company also issued $100 million of First Mortgage Bonds (the Series B Bonds) with a fixed coupon of 5.625 percent and a maturity of April 1, 2035.  The proceeds of both issuances were used to refinance the company's short-term borrowings, which were previously incurred to fund transmission and distribution capital expenditures.

12.  Segment Information  

Segment information related to the distribution and transmission businesses for CL&P for the years ended December 31, 2005, 2004, and 2003 is as follows (in millions of dollars):

	For the Year Ended December 31, 2005
	Distribution	Transmission	Totals
Operating revenues	$3,353.7	$112.7	$3,466.4
Depreciation and   amortization	(293.5)	(17.7)	(311.2)
Other operating expenses	(2,899.9)	(45.7)	(2,945.6)
Operating income	160.3	49.3	209.6
Interest expense,   net of AFUDC	(108.5)	(11.5)	(120.0)
Interest income	2.9	0.4	3.3
Other income/(loss), net	35.6	(1.5)	34.1
Income tax expense	(26.2)	(6.0)	(32.2)
Net income	64.1	30.7	94.8
Total assets  (1)	$5,765.1	$        -	$5,765.1
Cash flows for total   investments in plant	$   236.6	$207.8	$   444.4

	For the Year Ended December 31, 2004
	Distribution	Transmission	Totals
Operating revenues	$2,738.8	$  94.1	$2,832.9
Depreciation and   amortization	(238.8)	(15.4)	(254.2)
Other operating expenses	(2,314.7)	(45.1)	(2,359.8)
Operating income	185.3	33.6	218.9
Interest expense,   net of AFUDC	(101.1)	(8.9)	(110.0)
Interest income	3.9	0.2	4.1
Other income/(loss), net	21.1	(0.6)	20.5
Income tax expense	(41.0)	(4.5)	(45.5)
Net income	$      68.2	$    19.8	$     88.0
Total assets  (1)	$ 5,306.9	$         -	$5,306.9
Cash flows for total   investments in plant	$    254.7	$ 134.6	$  389.3

	For the Year Ended December 31, 2003
	Distribution	Transmission	Totals
Operating revenues	$2,627.0	$77.5	$2,704.5
Depreciation and   amortization	(299.8)	(13.9)	(313.7)
Other operating   expenses	(2,166.8)	(35.3)	(2,202.1)
Operating income	160.4	28.3	188.7
Interest expense, net of    AFUDC	(108.1)	(2.5)	(110.6)
Interest income	1.9	0.1	2.0
Other income/(loss), net	7.6	(0.7)	6.9
Income tax expense	(10.0)	(8.1)	(18.1)
Net income	$     51.8	$17.1	$     68.9
Total assets (1)	$5,206.9	$     -	$5,206.9
Cash flows for total  investments in plant	$  255.9	$62.6	$  318.5

(1) Information for segmenting total assets between distribution and transmission is not available at December 31, 2005 or 2004.  These distribution and transmission assets are disclosed in the distribution columns above.

Consolidated Quarterly Financial Data (Unaudited)
	Quarter Ended (a) (b)
(Thousands of Dollars)	March 31,	June 30,	September 30,	December 31,
2005
Operating Revenues	$838,901	$797,568	$952,444	$877,507
Operating Income	$  62,280	$  45,057	$  60,195	$  42,019
Net Income	$  25,143	$  11,053	$  26,073	$  32,576
2004
Operating Revenues	$748,690	$679,080	$725,532	$679,622
Operating Income	$  63,584	$  48,279	$  63,747	$  43,280
Net Income	$  26,223	$  17,255	$  21,684	$  22,854

Selected Consolidated Financial Data (Unaudited)
(Thousands of Dollars)	2005	2004	2003	2002	2001
Operating Revenues	$3,466,420	$2,832,924	$2,704,524	$2,507,036	$2,646,123
Net Income	94,845	88,016	68,908	85,612	109,803
Cash Dividends on Common Stock	53,834	47,074	60,110	60,145	60,072
Property, Plant and Equipment, net (c)	3,166,692	2,824,877	2,561,898	2,332,693	2,029,173
Total Assets (d)	5,765,072	5,306,913	5,206,894	4,786,083	4,727,727
Rate Reduction Bonds	856,479	995,233	1,124,779	1,245,728	1,358,653
Long-Term Debt (e)	1,258,883	1,052,891	830,149	827,866	824,349
Preferred Stock Not Subject to Mandatory Redemption	116,200	116,200	116,200	116,200	116,200
Obligations Under Capital Leases (e)	13,488	14,093	14,879	15,499	16,040

(a)

Certain reclassifications of prior years' data have been made to conform with the current year's presentation.

(b)

Quarterly operating income amounts differ from those previously reported as a result of the change in classification of certain costs that were not recoverable from regulated customers.  These amounts, previously presented in other income, net, have been reclassified to other operation expenses and are summarized as follows (thousands of dollars):  

Quarter Ended	2005	2004
March 31,	$157	$697
June 30,	873	887
September 30,	851	1,191

(c)

Amount includes construction work in progress.

(d)

Total assets were not adjusted for cost of removal prior to 2002.

(e)

Includes portions due within one year.

Consolidated Statistics (Unaudited)
	2005	2004	2003	2002	2001
Revenues:  (Thousands)
Residential	$1,440,142	$1,155,492	$1,151,707	$1,028,425	$   991,946
Commercial	1,170,038	939,579	960,678	874,713	855,348
Industrial	327,598	275,730	290,526	274,228	285,479
Other Utilities	344,650	295,833	322,955	271,484	420,664
Streetlighting and Railroads	37,054	31,897	35,358	33,788	33,356
Miscellaneous	146,938	134,393	(56,700)	24,398	59,330
Total	$3,466,420	$2,832,924	$2,704,524	$2,507,036	$2,646,123
Sales:  (kWh - Millions)
Residential	10,760	10,305	10,359	9,699	9,340
Commercial	10,307	9,922	9,829	9,644	9,460
Industrial	3,501	3,623	3,630	3,707	3,850
Other Utilities	4,179	5,375	5,885	6,281	9,709
Streetlighting and Railroads	298	298	298	292	286
Total	29,045	29,523	30,001	29,623	32,645
Customers:  (Average)
Residential	1,078,723	1,071,249	1,058,247	1,048,096	1,050,633
Commercial	108,558	108,865	104,750	103,408	95,782
Industrial	3,976	4,078	3,989	4,035	4,028
Other	2,630	2,694	2,643	2,768	2,791
Total	1,193,887	1,186,886	1,169,629	1,158,307	1,153,234
Average Annual Use Per  Residential Customer (kWh)	9,974	9,620	9,790	9,244	8,884
Average Annual Bill Per Residential Customer	$1,335.02	$1,078.40	$1,089.63	$979.86	$943.48
Average Revenue Per kWh:
Residential	13.38¢	11.21¢	11.13¢	10.60¢	10.62¢
Commercial	11.35	9.47	9.77	9.07	9.04
Industrial	9.36	7.61	8.00	7.40	7.42

EX-13.2

Exhibit 13.2

Management’s Discussion and Analysis

Financial Condition and Business Analysis

Executive Summary

The following items in this executive summary are explained in more detail in this annual report.

Results:

·

Western Massachusetts Electric Company (WMECO or the company) reported earnings of $15.1 million in 2005 compared to $12.4 million in 2004 and $16.2 million in 2003.  Included in earnings were transmission earnings of $4 million, $3 million and $3.8 million, in 2005, 2004 and 2003, respectively, and distribution earnings of $11.1 million, $9.4 million and $12.4 million in 2005, 2004 and 2003, respectively.  

Legislative Items:

·

On August 8, 2005, President Bush signed into law comprehensive federal energy legislation with several provisions affecting WMECO.  As part of this legislation, the Public Utility Holding Company Act of 1935 (PUHCA) was repealed.  Some but not all of the Securities and Exchange Commission's (SEC) responsibilities under PUHCA were transferred to the Federal Energy Regulatory Commission (FERC).  

Regulatory Items:

·

WMECO has received regulatory approval to recover the increased cost of energy being supplied to its customers in 2006.  This increased cost is primarily the result of increased fuel and purchased power costs.

·

On December 1, 2005, WMECO made its 2006 annual rate change filing implementing the $3 million distribution revenue increase allowed under its rate case settlement agreement.  WMECO requested that this change become effective on January 1, 2006.  On December 29, 2005, the Massachusetts Department of Telecommunications and Energy (DTE) approved rates reflecting the $3 million distribution revenue increase as well as increases for new basic service supply.

·

On March 6, 2006, the New England Independent System Operator (ISO-NE) and a broad cross-section of critical stakeholders from around the region filed a comprehensive settlement agreement at the FERC implementing a Forward Capacity Market (FCM) in place of Locational Installed Capacity (LICAP).  The settlement agreement must be approved by the FERC, and the parties have asked for a decision by June 30, 2006.

Liquidity:

·

On August 11, 2005, WMECO closed on the sale of $50 million of 10-year senior notes.

·

In 2005, WMECO's capital expenditures totaled $44.7 million compared with $39.3 million in 2004 and $32.6 million in 2003.

·

Cash flows from operations decreased by $20.5 million to $30 million in 2005 from $50.5 million in 2004.  

Overview

WMECO is a wholly owned subsidiary of NU.  NU’s other regulated electric subsidiaries include Public Service Company of New Hampshire (PSNH) and The Connecticut Light and Power Company (CL&P).

WMECO earned $15.1 million in 2005, compared with $12.4 million in 2004 and $16.2 million in 2003.  Included in earnings were transmission earnings of $4 million, $3 million and $3.8 million, in 2005, 2004 and 2003, respectively, and distribution earnings of $11.1 million, $9.4 million and $12.4 million in 2005, 2004 and 2003, respectively.  WMECO’s 2005 earnings were higher primarily due to higher distribution revenues.  Improved 2005 distribution results were due to a $6 million distribution rate increase that took effect on January 1, 2005, a 1.4 percent increase in retail electric sales and higher rate base earnings as a result of WMECO refinancing its prior spent nuclear fuel obligation.

WMECO’s retail electric sales were positively impacted by weather in 2005, particularly by an unseasonably hotter than average third quarter of 2005, which increased electricity consumption.  Retail electric sales increased 1.4 percent over 2004, however, retail electric sales decreased by 0.8 percent on a weather adjusted basis.  

With a commodity-driven rate increase taking effect early in 2006 and the weather being much milder to date in 2006, management is concerned that actual sales could be lower in 2006 than in 2005.  While sales volume does not affect transmission business earnings positively or negatively, lower electric sales do negatively affect distribution company earnings.

Liquidity

Cash flows from operations decreased by $20.5 million to $30 million in 2005 from $50.5 million in 2004.  The decrease in cash flows is primarily due to a decrease in regulatory overrecoveries from customers.  

1

Cash flows from operations decreased by $8.8 million from $59.3 million in 2003 to $50.5 million in 2004.  The decrease in cash flows from operations was primarily the result of a decrease in amortization of regulatory assets offset by the related deferred income tax impact.

On August 11, 2005, WMECO closed on the sale of $50 million of 10-year senior notes with an interest rate of 5.24 percent.  Proceeds from this issuance were used to repay short-term borrowings used to finance capital expenditures.

On December 9, 2005, WMECO amended its 5-year unsecured revolving credit facility by extending the termination date by one year to November 6, 2010.  The company can borrow up to $100 million on a short-term basis, or subject to regulatory approvals, on a long-term basis.  At December 31, 2005, there were no borrowings outstanding under this facility.  At December 31, 2004, WMECO had $25 million in borrowings under this credit facility.

WMECO's senior unsecured debt is rated Baa2, BBB and BBB+ with a stable outlook by Moody's Investors Service (Moody's), Standard and Poor's (S&P), and Fitch Ratings, respectively.  

In 2005, WMECO paid approximately $7.7 million to NU in the form of common dividends.  

Capital expenditures described herein are cash capital expenditures and do not include cost of removal, allowance for funds used during construction (AFUDC), and the capitalized portion of pension expense or income.  WMECO’s capital expenditures totaled $44.7 million in 2005, compared with $39.3 million in 2004 and $32.6 million in 2003.  The increase in WMECO's capital expenditures was primarily the result of higher transmission capital expenditures, which increased approximately $6 million from 2004.

Business Development and Capital Expenditures

In 2005, WMECO's capital expenditures totaled $44.7 million.  In 2004 and 2003, capital expenditures totaled $39.3 million and $32.6 million, respectively.  

Capital expenditures of $44.7 million include $32.4 million in its electric distribution system and other capital expenditures and $12.3 million in its electric transmission system.  As part of WMECO’s rate settlement approved by the DTE on December 29, 2004, WMECO agreed to invest not less than $24 million in capital expenditures in 2005 and 2006 related to reliability improvements.  

WMECO currently forecasts distribution expenditures of approximately $200 million from 2006 through 2010.  In addition, approximately $50 million of transmission projects is currently forecasted from 2006 to 2010, totaling approximately $250 million in total capital projects.  WMECO estimates total annual capital expenditures of approximately $50 million from 2006 through 2010.

Transmission Access and FERC Regulatory Changes

In January of 2005, the New England transmission owners approved activation of the New England Regional Transmission Organization (RTO) which occurred on February 1, 2005.  WMECO is now a member of the New England RTO and provides regional open access transmission service over its transmission system under the ISO-NE Transmission, Markets and Services Tariff, FERC Electric Tariff No. 3 and local open access transmission service under the ISO-NE Transmission, Markets and Services Tariff, FERC Electric No. 3, Schedule 21 - NU.

As a result of the RTO start-up on February 1, 2005, the return on equity (ROE) in the local network service (LNS) tariff was increased to 12.8 percent.  The ROE being utilized in the calculation of the current New England Regional Network Service (RNS) rates is the sum of the 12.8 percent "base" ROE, plus a 50 basis point incentive adder for joining the RTO, or a total of 13.3 percent.  An initial decision by a FERC administrative law judge (ALJ) has set the base ROE at 10.72 percent as compared with the 12.8 percent requested by the New England RTO.  One of the adjustments made by the ALJ was to modify the underlying proxy group used to determine the ROE, resulting in a reduction in the base ROE of approximately 50 basis points.  The ALJ deferred to the FERC for final resolution on the 100 basis point incentive adder for new transmission investments but reaffirmed the 50 basis point incentive for joining the RTO.  The New England transmission owners have challenged the ALJ’s findings and recommendations through written exceptions filed on June 27, 2005 and a final order from the FERC is expected in 2006.  The result of this order, if upheld by the FERC, would be an ROE for LNS of 10.72 percent and an ROE for RNS of 11.22 percent.  When blended, the resulting "all in" ROE would be approximately 11.15 percent for the NU transmission business.  Management cannot at this time predict what ROE will ultimately be established by the FERC in these proceedings but for purposes of current earnings accruals and estimates, the transmission business is assuming an ROE of 11.5 percent.

In November of 2005, the FERC announced that it was considering a number of proposals to provide financial incentives for the construction of high-voltage electric transmission in the United States.  Those proposals included reflecting in rate base 100 percent of the cost of construction work in progress (CWIP); accelerated recovery of depreciation; imputing hypothetical capital structures in ratemaking; establishing ROEs for transmission owners that join RTOs and other incentives that could improve the earnings and/or cash flows associated with WMECO's transmission capital expenditures.  Comments on the FERC proposals were submitted in January of 2006, and final rules are expected by the summer of 2006.    

Legislative Matters

On August 8, 2005, President Bush signed into law comprehensive energy legislation.  Among provisions potentially affecting WMECO are the repeal PUHCA, FERC backstop siting authority for transmission, transmission pricing and rate reform, renewable production tax credits, and accelerated depreciation for certain new electric and gas facilities.  The accelerated depreciation provision, assuming timely rate recovery, is expected to increase WMECO’s cash flows by more than $0.1 million annually.  As part of this legislation, some but not all of the SEC responsibilities were transferred to the FERC.

2

Regulatory Issues and Rate Matters

Transmission - Wholesale Rates:  Wholesale transmission revenues are based on rates and formulas that are approved by the FERC.  Most of WMECO’s wholesale transmission revenues are collected through a combination of the RNS tariff and WMECO’s LNS tariff.  WMECO’s LNS rate is reset on January 1 and June 1 of each year.  On January 1, 2006, WMECO’s LNS rates increased wholesale revenues by approximately $1.6 million on an annualized basis.  WMECO's RNS rate is reset on June 1 of each year.  The LNS and RNS rates to be effective on June 1, 2006 have not yet been determined.  Additionally, WMECO’s LNS tariff provides for a true-up to actual costs, which ensures that WMECO's transmission business recovers its total transmission revenue requirements, including the allowed ROE.  At December 31, 2005, this true-up resulted in the recognitio n of a $0.2 million regulatory liability.  

Transmission - Retail Rates:  A significant portion of WMECO's transmission business revenue comes from ISO-NE charges to WMECO's electric distribution business.  WMECO's distribution business recovers these costs through the retail rates that are charged to its retail customers.  WMECO has a rate tracking mechanism to track its retail transmission costs charged in distribution rates to the actual amount of transmission charges incurred.  

LICAP:  In March of 2004, ISO-NE proposed at the FERC an administratively determined electric generation capacity pricing mechanism known as LICAP, intended to provide a revenue stream sufficient to maintain existing generation assets and encourage the construction of new generation assets at levels sufficient to serve peak load, plus fixed reserve and contingency margins.

After opposition from state regulators, utilities and various Congressional delegations, the FERC ordered settlement negotiations before an ALJ to determine whether there was an acceptable alternative to LICAP.  On March 6, 2006, ISO-NE and a broad cross-section of critical stakeholders from around the region filed a comprehensive settlement agreement at the FERC implementing a FCM in place of LICAP.  The settlement agreement provides for a fixed level of compensation to generators from December 1, 2006 through May 31, 2010 without regard to location in New England, and annual forward capacity auctions, beginning in 2008, for the 1-year period ending on May 31, 2011, and annually thereafter.  The settlement agreement must be approved by the FERC, and the parties have asked for a decision by June 30, 2006.  According to preliminary estimates, FCM would require WMECO to pay approximately $100 million during the 3½-year transition p eriod.  WMECO will incur charges and would be able to recover these costs from its customers.  

Transition Cost Reconciliation:  On March 31, 2005, WMECO filed its 2004 transition cost reconciliation with the DTE.  The DTE has combined the 2003 transition cost reconciliation filing, standard offer service and default service reconciliation, the transmission cost adjustment filing, and the 2004 transition cost reconciliation filing into a single proceeding.  The timing of a decision in the combined proceeding is uncertain, but management does not expect the outcome to have a material adverse impact on WMECO's net income or financial position.  

Distribution Rate Case Settlement Agreement:  On December 29, 2004, the DTE approved a rate case settlement agreement submitted by WMECO, the Massachusetts Attorney General's Office, the Associated Industries of Massachusetts, and the Low-Income Energy Affordability Network.  The settlement agreement provides for a $6 million increase in WMECO’s distribution rate effective on January 1, 2005 and an additional $3 million increase in WMECO's distribution rate effective on January 1, 2006 and for a decrease in WMECO’s transition charge by approximately $13 million annually. The lower transition charge will delay recovery of transition costs and will reduce WMECO’s cash flows but not its earnings as part of the rate case settlement agreement.  WMECO agreed not to file for a distribution rate increase to be effective prior to January 1, 2007.

Annual Rate Change Filing:  On December 1, 2005, WMECO made its 2006 annual rate change filing implementing the $3 million distribution revenue increase allowed under its rate case settlement agreement.  WMECO requested that this change become effective on January 1, 2006.  On December 29, 2005, the DTE approved rates reflecting the $3 million distribution revenue increase as well as increases for new basic service supply.  

Basic Service:  WMECO owns no generation and seeks bids at regular intervals to provide full requirements service for its customers who do not contract directly with competitive retail suppliers for their energy.  As a result of higher energy prices, the prices for 2006 are significantly higher than 2005.  

Deferred Contractual Obligations

FERC Proceedings:  In 2003, the Connecticut Yankee Atomic Power Company (CYAPC) increased the estimated decommissioning and plant closure costs for the period 2000 through 2023 by approximately $395 million over the April 2000 estimate of $436 million approved by the FERC in a 2000 rate case settlement.  The revised estimate reflects the increases in the projected costs of spent fuel storage, increased security and liability and property insurance costs, and the fact that CYAPC is now self performing all work to complete the decommissioning of the plant due to the termination of the decommissioning contract with Bechtel Power Corporation (Bechtel) in July of 2003.  WMECO's share of CYAPC's increase in decommissioning and plant closure costs is approximately $38 million.  On July 1, 2004, CYAPC filed with the FERC for recovery seeking to increase its annual decommissioning collections from $16 .7 million to $93 million for a six-year period beginning on January 1, 2005.  On August 30, 2004, the FERC issued an order accepting the rates, with collection beginning on February 1, 2005, subject to refund.

Both the Connecticut Department of Public Utility Control (DPUC) and Bechtel filed testimony in the FERC proceeding claiming that CYAPC was imprudent in its management of the decommissioning project.  In its testimony, the DPUC recommended a disallowance of $225 million to $234 million out of CYAPC's requested rate increase of approximately $395 million.  WMECO's share of the DPUC's recommended disallowance would be between $21 million to $22 million.  The FERC staff also filed testimony that recommended a $38 million decrease in the requested rate increase claiming that CYAPC should have used a different gross domestic product (GDP) escalator.  WMECO's share of this recommended decrease is $3.6 million.  

On November 22, 2005, a FERC ALJ issued an initial decision finding no imprudence on CYAPC's part.  However, the ALJ did agree with the FERC staff’s position that a lower GDP escalator should be used for calculating the rate increase and found that CYAPC should recalculate its decommissioning charges to reflect the lower escalator.  Briefs to the full FERC addressing these issues were filed in January and February of 2006, and a final order is expected later in 2006.  Management expects that if the FERC staff's position on the decommissioning GDP cost escalator is found by the FERC to be more appropriate than that used by CYAPC to develop its proposed rates, then CYAPC would review whether to reduce its estimated decommissioning obligation and reduce the customers' obligation, including WMECO.  

The company cannot at this time predict the timing or outcome of the FERC proceeding required for the collection of the increased CYAPC decommissioning costs.  The company believes that the costs have been prudently incurred and will ultimately be recovered from the customers of WMECO.  However, there is a risk that some portion of these increased costs may not be recovered, or will have to be refunded if recovered, as a result of the FERC proceedings.  

On June 10, 2004, the DPUC and the Connecticut Office of Consumer Counsel (OCC) filed a petition seeking a declaratory order that CYAPC be allowed to recover all decommissioning costs from its wholesale purchasers, including WMECO, but that such purchasers may not be allowed to recover in their retail rates any costs that the FERC might determine to have been imprudently incurred.  On August 30, 2004, the FERC denied this petition.  On September 29, 2004, the DPUC and OCC asked the FERC to reconsider the petition and on October 20, 2005, the FERC denied the reconsideration, holding that the sponsor companies are only obligated to pay CYAPC for prudently incurred decommissioning costs and the FERC has no jurisdiction over the sponsors' rates to their retail customers.  On December 12, 2005, the DPUC sought review of these orders by the United States Court of Appeals for the D.C. Circuit.  The FERC and CYAPC have asked the court to dism iss the case and the DPUC has objected to the dismissal.  WMECO cannot predict the timing or outcome of these proceedings.

Bechtel Litigation:  CYAPC and Bechtel commenced litigation in Connecticut Superior Court over CYAPC's termination of Bechtel's contract for the decommissioning of CYAPC's nuclear generating plant.  After CYAPC terminated the contract, responsibility for decommissioning was transitioned to CYAPC, which recommenced the decommissioning process.

On March 7, 2006, CYAPC and Bechtel executed a settlement agreement terminating this litigation.  Bechtel has agreed to pay CYAPC $15 million, and CYAPC will withdraw its termination of the contract for default and deem it terminated by agreement.

Spent Nuclear Fuel Litigation:  CYAPC, Yankee Atomic Electric Company (YAEC) and Maine Yankee Atomic Power Company (MYAPC) also commenced litigation in 1998 charging that the federal government breached contracts it entered into with each company in 1983 under the Act.  Under the Act, the DOE was to begin removing spent nuclear fuel from the nuclear plants of the Yankee Companies no later than January 31, 1998 in return for payments by each company into the nuclear waste fund.  No fuel has been collected by the DOE, and spent nuclear fuel is stored on the sites of the Yankee Companies' plants.  The Yankee Companies collected the funds for payments into the nuclear waste fund from wholesale utility customers under FERC-approved contract rates.  The wholesale utility customers in turn collect these payments from their retail electric customers.  The Yankee Companies' individual damage claims attributed to the government 's breach ranging between $523 million and $543 million are specific to each plant and include incremental storage, security, construction and other costs through 2010.  The CYAPC damage claim ranges from $186 million to $198 million, the YAEC damage claim ranges from $177 million to $185 million and the MYAPC damage claim is $160 million.  The DOE trial ended on August 31, 2004 and a verdict has not been reached.  Post-trial findings of facts and final briefs were filed by the parties in January of 2005.  The Yankee Companies' current rates do not include an amount for recovery of damages in this matter.  Management can predict neither the outcome of this matter nor its ultimate impact on WMECO.

YAEC:  In November of 2005, YAEC established an updated estimate of the cost of completing the decommissioning of its plant resulting in an increase of approximately $85 million.  WMECO's share of the increase in estimated costs is $6 million.  This estimate reflects the cost of completing site closure activities from October of 2005 forward and storing spent nuclear fuel and other high level waste on site until 2020.  This estimate projects a total cost of $192.1 million for the completion of decommissioning and long-term fuel storage.  To fund these costs, on November 23, 2005, YAEC submitted an application to the FERC to increase YAEC’s wholesale decommissioning charges.  The DPUC and the Massachusetts attorney general protested these increases.  On January 31, 2006, the FERC issued an order accepting the rate increase, effective February 1, 2006, subject to refund after hearings and settlement judge proceedings.  The hearings have been suspended pending settlement discussions between YAEC, the FERC and other intervenors in the case.  WMECO has a 7 percent ownership interest in YAEC and can predict neither the outcome of this matter nor its ultimate impact on WMECO.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates, assumptions and at times difficult, subjective or complex judgments.  Changes in these estimates, assumptions and judgments, in and of themselves, could materially impact the financial statements of WMECO.  Management communicates to and discusses with NU’s Audit Committee of the Board of Trustees all critical accounting policies and estimates.  The following are the accounting policies and estimates that management believes are the most critical in nature.

Revenue Recognition:  WMECO's retail revenues are based on rates approved by the DTE.  These regulated rates are applied to customers’ use of energy to calculate a bill.  In general, rates can only be changed through formal proceedings with the DTE.  

The determination of the energy sales to individual customers is based on the reading of meters, which occurs on a systematic basis throughout the month.  Billed revenues are based on these meter readings.  At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and an estimated amount of unbilled revenues is recorded.  WMECO utilizes regulatory commission-approved tracking mechanisms to track the recovery of certain incurred costs.  The tracking mechanisms allow for rates to be changed periodically, with overcollections refunded to customers or undercollections collected from customers in future periods.

Wholesale transmission revenues are based on rates and formulas that are approved by the FERC.  Most of WMECO’s wholesale transmission revenues are collected through a combination of the RNS tariff and WMECO's LNS tariff.  The RNS tariff, which is administered by the ISO-NE, recovers the revenue requirements associated with transmission facilities that are deemed by the FERC to be Pool Transmission Facilities.  The LNS tariff, which was accepted by the FERC, provides for the recovery of WMECO's total transmission revenue requirements, net of revenue credits received from various rate components, including revenues received under the RNS rates.  At December 31, 2005, this true-up resulted in the recognition of a $0.2 million regulatory liability.  

A significant portion of WMECO's transmission business revenue comes from ISO-NE charges to WMECO's electric distribution business.  WMECO's distribution business recovers these costs through the retail rates that are charged to its retail customers.  WMECO implemented its retail transmission tracker and rate adjustment mechanism in January of 2002 as part of its 2002 rate change filing.  

Unbilled Revenues:  Unbilled revenues represent an estimate of electricity delivered to customers that has not yet been billed.  Unbilled revenues are included in revenue on the accompanying consolidated statements of income and are assets on the accompanying consolidated balance sheets that are reclassified to accounts receivable in the following month as customers are billed.

The estimate of unbilled revenues is sensitive to numerous factors that can significantly impact the amount of revenues recorded.  Estimating the impact of these factors is complex and requires management’s judgment.  The estimate of unbilled revenues is important to WMECO’s consolidated financial statements as adjustments to that estimate could significantly impact operating revenues and earnings.

Through December 31, 2004, WMECO estimated unbilled revenues monthly using the requirements method.  The requirements method utilized the total monthly volume of electricity delivered to the system and applied a delivery efficiency (DE) factor to reduce the total monthly volume by an estimate of delivery losses in order to calculate total estimated monthly sales to customers.  The total estimated monthly sales amount less the total monthly billed sales amount resulted in a monthly estimate of unbilled sales.  Unbilled revenues were estimated by first allocating sales to the respective rate classes, then applying an average rate to the estimate of unbilled sales.  The estimated DE factor had a significant impact on estimated unbilled revenue amounts.

In the first quarter of 2005, management adopted a new method to estimate unbilled revenues for WMECO.  The new method allocates billed sales to the current calendar month based on the daily load for each billing cycle (DLC method).  The billed sales are subtracted from total calendar month sales to estimate unbilled sales.  The impact of adopting the new method was not material.  This new method replaces the requirements method described previously.  

Regulatory Accounting:  The accounting policies of WMECO historically reflect the effects of the rate-making process in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation."  The transmission and distribution businesses of WMECO continue to be cost-of-service rate regulated, and management believes the application of SFAS No. 71 to those businesses continues to be appropriate.  Management must reaffirm this conclusion at each balance sheet date.  If, as a result of a change in circumstances, it is determined that any portion of the company no longer meets the criteria of regulatory accounting under SFAS No. 71, that portion of the company will have to discontinue regulatory accounting and write-off the respective regulatory assets and liabilities.  Such a write-off could have a material impact on WMECO’s consolidated financial statements.

The application of SFAS No. 71 results in recording regulatory assets and liabilities.  Regulatory assets represent the deferral of incurred costs that are probable of future recovery in customer rates.  In some cases, WMECO records regulatory assets before approval for recovery has been received from the applicable regulatory commission.  Management must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery.  Management bases its conclusion on certain factors, including changes in the regulatory environment, recent rate orders issued by the applicable regulatory agencies and the status of any potential new legislation.  Regulatory liabilities represent revenues received from customers to fund expected costs that have not yet been incurred or are probable future refunds to customers.

Management uses its best judgment when recording regulatory assets and liabilities; however, regulatory commissions can reach different conclusions about the recovery of costs, and those conclusions could have a material impact on WMECO’s consolidated financial statements.  Management believes it is probable that WMECO will recover the regulatory assets that have been recorded.

Presentation:  In accordance with current accounting pronouncements, WMECO's consolidated financial statements include all subsidiaries upon which control is maintained and all variable interest entities (VIE).  Determining whether the company is the primary beneficiary of a VIE is subjective and requires management's judgment.  There are certain variables taken into consideration to determine whether the company is considered the primary beneficiary to the VIE.  A change in any one of these variables could require the company to reconsider whether or not it is the primary beneficiary of the VIE.  All intercompany transactions between these subsidiaries are eliminated as part of the consolidation process.  

WMECO has less than 50 percent ownership in CYAPC, YAEC, and MYAPC.  WMECO does not control these companies and does not consolidate them in its financial statements.  WMECO accounts for the investments in these companies using the equity method.  Under the equity method, WMECO records its ownership share of the earnings or losses at these companies.  Determining whether or not WMECO should apply the equity method of accounting for an investment requires management judgment.  

In December of 2003, the Financial Accounting Standards Board (FASB) issued a revised version of FASB Interpretation No. (FIN) 46, "Consolidation of Variable Interest Entities," (FIN 46R).  FIN 46R was effective for WMECO for the first quarter of 2004 and did not have an impact on WMECO's consolidated financial statements.  

Pension and Postretirement Benefits Other Than Pensions (PBOP):  WMECO participates in a uniform noncontributory defined benefit retirement plan (Pension Plan) covering substantially all regular WMECO employees.  WMECO also participates in a postretirement benefit plan (PBOP Plan) to provide certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired employees.  For each of these plans, the development of the benefit obligation, fair value of plan assets, funded status and net periodic benefit credit or cost is based on several significant assumptions.  If these assumptions were changed, the resulting change in benefit obligations, fair values of plan assets, funded status and net periodic benefit credits or costs could have a material impact on WMECO’s consolidated financial statements.

Pre-tax periodic pension income for the Pension Plan totaled $1.6 million, $4.6 million and $7.9 million for the years ended December 31, 2005, 2004 and 2003, respectively.  The pension income amounts exclude one-time items recorded under SFAS No. 88, "Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits."

Not included in the pension income amount are pension amounts related to intercompany allocations totaling $1.7 million, $0.6 million and $(0.2) million for the years ended December 31, 2005, 2004 and 2003, respectively, including pension curtailment and termination benefits expense of $0.4 million and $0.1 million for the years ended December 31, 2005 and 2004, respectively.  These amounts are included in other operating expenses on the accompanying consolidated financial statements.

The pre-tax net PBOP Plan cost, excluding curtailments and termination benefits, totaled $4.2 million, $3.7 million and $3.5 million for the years ended December 31, 2005, 2004 and 2003, respectively.

As a result of NU's decision to pursue a fundamentally different business strategy, and align the structure of the company to support this business strategy, WMECO recorded a $0.2 million pre-tax curtailment expense in 2005 for the Pension Plan.  WMECO also accrued certain related termination benefits and recorded a $0.3 million pre-tax charge in 2005 for the Pension Plan.  

On December 15, 2005, the NU Board of Trustees approved a benefit for new non-union employees hired on and after January 1, 2006 to receive retirement benefits under a new 401(k) benefit rather than under the Pension Plan.  Non-union employees actively employed on December 31, 2005 will be given the choice in 2006 to elect to continue participation in the Pension Plan or instead receive a new employer contribution under the 401(k) Savings Plan effective January 1, 2007.  If the new benefit is elected, their accrued pension liability in the Pension Plan will be frozen as of December 31, 2006.  Non-union employees will make this election in the second half of 2006.  This decision resulted in the recording of an estimated pre-tax curtailment expense of $0.2 million in 2005, as a certain number of employees are expected to elect the new 401(k) benefit, resulting in a reduction in aggregate estimated future years of service under the Pension Plan.  Management estimated the amount of the curtailment expense associated with this change based upon actuarial calculations and certain assumptions, including the expected level of transfers to the new 401(k) benefit.  Any adjustments to this estimate resulting from actual employee elections will be recorded in 2006.

In April of 2004, as a result of litigation with nineteen former employees, NU was ordered by the court to modify its Pension Plan to include special retirement benefits for fifteen of these former employees retroactive to the dates of their retirement and provide increased future monthly benefit payments.  WMECO recorded $0.3 million in termination benefits related to this litigation in 2004 and made a lump sum benefit payment totaling $0.2 million to these former employees.

For the PBOP Plan, WMECO recorded an estimated $0.6 million pre-tax curtailment expense at December 31, 2005 relating to NU's change in business strategy.  WMECO also accrued a $0.1 million pre-tax termination benefit at December 31, 2005 relating to certain benefits provided under the terms of the PBOP Plan.  Additional termination benefits may be recorded in 2006.

There were no curtailments or termination benefits recorded for the Pension Plan in 2003 or PBOP Plan in 2004 and 2003.

Long-Term Rate of Return Assumptions:  In developing the expected long-term rate of return assumptions, WMECO evaluated input from actuaries and consultants, as well as long-term inflation assumptions and WMECO's historical 20-year compounded return of approximately 11 percent.  WMECO's expected long-term rates of return on assets is based on certain target asset allocation assumptions and expected long-term rates of return.  WMECO believes that 8.75 percent is a reasonable long-term rate of return on Pension Plan and PBOP Plan assets (life assets and non-taxable health assets) and 6.85 percent for PBOP health assets, net of tax for 2005.  WMECO will continue to evaluate these actuarial assumptions, including the expected rate of return, at least annually, and will adjust the appropriate assumptions as necessary.  The Pension Plan's and PBOP Plan's target asset allocation assumptions and expected long-term rates of return assumptions by asset category are as follows:

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	At December 31,
	Pension Benefits		Postretirement Benefits
	2005 and 2004		2005 and 2004
Asset Category	Target Asset Allocation	Assumed Rate of Return	Target Asset Allocation	Assumed Rate of Return
Equity securities:
United States	45%	9.25%	55%	9.25%
Non-United States	14%	9.25%	11%	9.25%
Emerging markets	3%	10.25%	2%	10.25%
Private	8%	14.25%	-	-
Debt Securities:
Fixed income	20%	5.50%	27%	5.50%
High yield fixed income	5%	7.50%	5%	7.50%
Real estate	5%	7.50%	-	-

The actual asset allocations at December 31, 2005 and 2004 approximated these target asset allocations.  WMECO routinely reviews the actual asset allocations and periodically rebalances the investments to the targeted asset allocations when appropriate.  For information regarding actual asset allocations, see Note 3, "Pension Benefits and Postretirement Benefits Other Than Pensions," to the consolidated financial statements.  

Actuarial Determination of Income and Expense:  WMECO bases the actuarial determination of Pension Plan and PBOP Plan income/expense on a market-related valuation of assets, which reduces year-to-year volatility.  This market-related valuation calculation recognizes investment gains or losses over a four-year period from the year in which they occur.  Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the fair value of assets.  Since the market-related valuation calculation recognizes gains or losses over a four-year period, the future value of the market-related assets will be impacted as previously deferred gains or losses are recognized.  There will be no impact on the fair value of Pension Plan and PBOP Plan assets in the trust funds of these plans.

At December 31, 2005, the Pension Plan had cumulative unrecognized investment gains of $7.9 million, which will decrease pension expense over the next four years.  At December 31, 2005, the Pension Plan had cumulative unrecognized actuarial losses of $40.5 million, which will increase pension expense over the expected future working lifetime of active Pension Plan participants, or approximately 13 years.  The combined total of unrecognized investment gains and actuarial losses at December 31, 2005 is a net unrecognized loss of $32.6 million.  These gains and losses impact the determination of pension expense and the actuarially determined prepaid pension amount recorded on the consolidated balance sheets but have no impact on expected Pension Plan funding.

At December 31, 2005, the PBOP Plan had cumulative unrecognized investment gains of $4.1 million, which will decrease PBOP Plan expense over the next four years.  At December 31, 2005, the PBOP Plan also had cumulative unrecognized actuarial losses of $15 million, which will increase PBOP Plan expense over the expected future working lifetime of active PBOP Plan participants, or approximately 13 years.  The combined total of unrecognized investment gains and actuarial losses at December 31, 2005 is a net unrecognized loss of $10.9 million.  These gains and losses impact the determination of PBOP Plan cost and the actuarially determined accrued PBOP Plan cost recorded on the consolidated balance sheets.

Discount Rate:  The discount rate that is utilized in determining future pension and PBOP obligations is based on a yield-curve approach where each cash flow related to the Pension or PBOP liability stream is discounted at an interest rate specifically applicable to the timing of the cash flow.  The yield-curve is developed from the top quartile of AA rated Moody's and S&P's bonds without callable features outstanding at December 31, 2005.  This process calculates the present values of these cash flows and calculates the equivalent single discount rate that produces the same present value for future cash flows.  The discount rates determined on this basis are 5.80 percent for the Pension Plan and 5.65 percent for the PBOP Plan at December 31, 2005.  Discount rates used at December 31, 2004 were 6.00 for the Pension Plan and 5.50 percent for the PBOP Plan.

Expected Contribution and Forecasted Expense:  Due to the effect of the unrecognized actuarial losses and based on an expected rate of return on Pension Plan assets of 8.75 percent, a discount rate of 6.00 percent and an expected rate of return on PBOP assets of 6.85 percent for health assets, net of tax and 8.75 percent for life assets and non-taxable health assets, a discount rate of 5.50 percent and various other assumptions, WMECO estimates that expected contributions to and forecasted income/expense for the Pension Plan and PBOP Plan will be as follows (in millions):

	Pension Plan		Postretirement Plan
Year	Expected Contributions	Forecasted Income	Expected Contributions	Forecasted Expense
2006	$0.0	$0.9	$4.2	$4.2
2007	$0.0	$3.0	$3.5	$3.5
2008	$0.0	$3.8	$3.3	$3.3

Future actual pension and postretirement expense will depend on future investment performance, changes in future discount rates and various other factors related to the populations participating in the plans and amounts capitalized.

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Sensitivity Analysis:  The following represents the increase/(decrease) to the Pension Plan's and PBOP Plan's reported cost as a result of a change in the following assumptions by 50 basis points (in millions):

	At December 31,
	Pension Plan		Postretirement Plan
Assumption Change	2005	2004	2005	2004
Lower long-term rate   of return	$  1.0	$  1.0	$0.1	$  0.1
Lower discount rate	$  1.1	$  1.0	$0.1	$  0.1
Lower compensation  increase	$(0.5)	$(0.4)	N/A	N/A

Plan Assets:  The market-related value of the Pension Plan assets has increased by $6.9 million to $216.2 million at December 31, 2005.  The projected benefit obligation (PBO) for the Pension Plan has increased by $14.1 million to $171.7 million at December 31, 2005.  These changes have decreased the funded status of the Pension Plan on a PBO basis from an overfunded position of $51.7 million at December 31, 2004 to an overfunded position of $44.5 million at December 31, 2005.  The PBO includes expectations of future employee compensation increases.  The accumulated benefit obligation (ABO) of the Pension Plan was approximately $63 million less than Pension Plan assets at December 31, 2005 and approximately $72 million less than Pension Plan assets at December 31, 2004.  The ABO for the entire NU plan is the obligation for employee service and compensation provided through December 31, 2005.  Under current accounting rules, if the ABO for the entire NU plan exceeds the entire NU plan assets at a future plan measurement date, WMECO will record its share of an additional minimum liability.  WMECO has not made employer contributions to the Pension Plan since 1991.

The value of PBOP Plan assets has increased from $19.9 million at December 31, 2004 to $22.2 million at December 31, 2005.  The benefit obligation for the PBOP Plan has increased from $41.2 million at December 31, 2004 to $42.9 million at December 31, 2005.  These changes have decreased the underfunded status of the PBOP Plan on an accumulated projected benefit obligation basis from $21.3 million at December 31, 2004 to $20.7 million at December 31, 2005.  WMECO has made a contribution each year equal to the PBOP Plan’s postretirement benefit cost, excluding curtailment and termination benefits.

Health Care Cost:  The health care cost trend assumption used to project increases in medical costs was 7 percent for 2005 and 8 percent for 2004, decreasing one percentage point per year to an ultimate rate of 5 percent in 2007.  For December 31, 2005 disclosure purposes, the health care cost trend assumption was reset for 2006 at 10 percent, decreasing one percentage point per year to an ultimate rate of 5 percent in 2011.  The effect of increasing the health care cost trend by one percentage point would have increased service and interest cost components of the PBOP Plan cost by $0.1 million in 2005 and 2004.   

Income Taxes:  Income tax expense is calculated each year in each of the jurisdictions in which WMECO operates.  This process involves estimating WMECO's actual current tax exposures as well as assessing temporary differences resulting from differing treatment of items, such as timing of the deduction and expenses for tax and book accounting purposes.  These differences result in deferred tax assets and liabilities, which are included in WMECO's consolidated balance sheets.  Adjustments made to income taxes could significantly affect WMECO's consolidated financial statements.  Management must also assess the likelihood that deferred tax assets will be recovered from future taxable income, and to the extent that recovery is not likely, a valuation allowance must be established.  Significant management judgment is required in determining income tax expenses, deferred tax assets and liabilities and valuation allowances.< /P>

WMECO accounts for deferred taxes under SFAS No. 109, "Accounting for Income Taxes."  For temporary differences recorded as deferred tax liabilities that will be recovered in rates in the future, WMECO has established a regulatory asset.  The regulatory asset amounted to $51.6 million and $56.7 million at December 31, 2005 and 2004, respectively.  Regulatory agencies in the jurisdiction in which WMECO operates requires the tax effect of specific temporary differences to be "flowed through" to utility customers.  Flow through treatment means that deferred tax expense is not recorded in the consolidated statements of income.  Instead, the tax effect of the temporary difference impacts both amounts for income tax expense currently included in customers’ rates and the company’s net income.  Flow through treatment can result in effective income tax rates that are significantly different than e xpected income tax rates.  Recording deferred taxes on flow through items is required by SFAS No. 109, and the offset to the deferred tax amounts is the regulatory asset referred to above.  

A reconciliation from expected tax expense at the statutory federal income tax rate to actual tax expense recorded is included in Note 1H, "Summary of Significant Accounting Policies-Income Taxes," to the consolidated financial statements.

The estimates that are made by management in order to record income tax expense, accrued taxes and deferred taxes are compared each year to the actual tax amounts filed on WMECO’s income tax returns.  The income tax returns were filed in the fall of 2005 for the 2004 tax year, and WMECO recorded differences between income tax expense, accrued taxes and deferred taxes on its consolidated financial statements and the amounts that were on its income tax returns.  

Depreciation:  Depreciation expense is calculated based on an asset’s useful life, and judgment is involved when estimating the useful lives of certain assets.  A change in the estimated useful lives of these assets could have a material impact on WMECO's consolidated financial statements absent timely rate relief for WMECO’s assets.  

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Accounting for Environmental Reserves:  Environmental reserves are accrued using a probabilistic model approach when assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated.  Adjustments made to environmental liabilities could have a significant effect on earnings.  The probabilistic model approach estimates the liability based on the most likely action plan from a variety of available remediation options, ranging from no action to remedies ranging from establishing institutional controls to full site remediation and long-term monitoring.  The probabilistic model approach estimates the liabilities associated with each possible action plan based on findings through various phases of site assessments.  

These estimates are subjective in nature partly because there are usually several different remediation options from which to choose when working on a specific site.  These estimates are subject to revisions in future periods based on actual costs or new information concerning either the level of contamination at the site or newly enacted laws and regulations.  The amounts recorded as environmental liabilities on the consolidated balance sheets represent management’s best estimate of the liability for environmental costs based on current site information from site assessments and remediation estimates.  These liabilities are estimated on an undiscounted basis.

WMECO does not have a recovery mechanism for environmental costs, and changes in WMECO's environmental reserves impact WMECO's earnings.

Asset Retirement Obligations:  On March 30, 2005, the FASB issued FIN 47, "Accounting for Conditional Asset Retirement Obligations - an Interpretation of FASB Statement No. 143."  FIN 47 requires an entity to recognize a liability for the fair value of an asset retirement obligation (ARO) that is conditional on a future event if the liability’s fair value can be reasonably estimated.  WMECO adopted FIN 47 on December 31, 2005.  Upon adoption, management identified several conditional removal obligations that have been accounted for as AROs.  For further information regarding the adoption of FIN 47, see Note 1L, "Summary of Significant Accounting Policies – Asset Retirement Obligations," to the consolidated financial statements.

Under SFAS No. 71, regulated utilities, including WMECO, currently recover amounts in rates for future costs of removal of plant assets.  At December 31, 2005 and 2004, these amounts totaling $23.6 million and $24.1 million, respectively, are classified as regulatory liabilities on the accompanying consolidated balance sheets.

Special Purpose Entity:  During 2001, to facilitate the issuance of rate reduction certificates (RRCs) intended to finance certain stranded costs, WMECO established WMECO Funding LLC.  WMECO Funding LLC was created as part of a state-sponsored securitization program.  WMECO Funding LLC is restricted from engaging in non-related activities and is required to operate in a manner intended to reduce the likelihood that it would be included in WMECO's bankruptcy estate if it ever became involved in a bankruptcy proceeding.  WMECO Funding LLC and the securitization amounts are consolidated in the accompanying consolidated financial statements.

For further information regarding the matters in this "Critical Accounting Policies and Estimates," section, see Note 1, "Summary of Significant Accounting Policies," Note 3, "Pension Benefits and Postretirement Benefits Other Than Pensions," and Note 4B, "Commitments and Contingencies - Environmental Matters," to the consolidated financial statements.

Other Matters

Commitments and Contingencies:  For further information regarding other commitments and contingencies, see Note 4, "Commitments and Contingencies," to the consolidated financial statements.

Accounting Standards Issued But Not Yet Adopted:

Accounting Changes and Error Corrections:  In May of 2005, the FASB issued SFAS No. 154, "Accounting Changes and Error Corrections."  SFAS No. 154 is effective beginning on January 1, 2006 for WMECO and requires retrospective application to prior periods’ financial statements of voluntary changes in accounting principle.  It also applies to accounting changes required by a new accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions.  SFAS No. 154 does not change previous guidance for reporting the correction of an error in previously issued financial statements or a change in accounting estimate.  Implementation of SFAS No. 154 on January 1, 2006 is not expected to affect WMECO’s consolidated financial statements until such time that its provisions are required to be applied as described above.

Contractual Obligations and Commercial Commitments:  Information regarding WMECO’s contractual obligations and commercial commitments at December 31, 2005 is summarized through 2010 and thereafter as follows:

(Millions of Dollars)	2006	2007	2008	2009	2010	Thereafter
Long-term debt (a) (b)	$      -	$      -	$      -	$      -	$      -	$208.8
Estimated interest  payments on existing   long-term debt	11.5	11.5	11.5	11.5	11.5	148.8
Operating  leases  (c) (d)	5.2	4.9	4.5	3.8	3.4	10.1
Required funding   of other post-  retirement benefit  obligations (d)	4.2	3.5	3.3	3.1	3.0	N/A
Long-term contractual   arrangements (c) (d)	27.1	23.2	21.3	21.0	20.8	31.0
Totals	$48.0	$43.1	$40.6	$39.4	$38.7	$398.7

^(a)  Included in WMECO's debt agreements are usual and customary positive, negative and financial covenants.  Non-compliance with certain covenants, for example the timely payment of principal and interest, may constitute an event of default, which could cause an acceleration of principal in the absence of receipt by the company of a waiver or amendment.  Such acceleration would change the obligations outlined in the table of contractual obligations and commercial commitments.

^(b)  Long-term debt excludes $51.1 million of fees and interest due for spent nuclear fuel disposal costs and $0.4 million of net unamortized discounts.

^(c)  WMECO has no provisions in its operating lease agreements or agreements related to its long-term contractual arrangements that could trigger a change in terms and conditions, such as acceleration of payment obligations.

^(d)  Amounts are not included on WMECO’s consolidated balance sheets.

Rate reduction bond amounts are non-recourse to WMECO, have no required payments over the next five years and are not included in this table.  WMECO's basic service contracts and default service contracts also are not included in this table.  For further information regarding WMECO’s contractual obligations and commercial commitments, see Note 2, "Short-Term Debt," Note 4D, "Commitments and Contingencies - Long-Term Contractual Arrangements," Note 7, "Leases," and Note 10, "Long-Term Debt," to the consolidated financial statements.

Forward Looking Statements:  This discussion and analysis includes statements concerning WMECO's expectations, plans, objectives, future financial performance and other statements that are not historical facts.  These statements are "forward looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995.  In some cases the reader can identify these forward looking statements by words such as "estimate," "expect," "anticipate," "intend," "plan," "believe," "forecast," "should," "could," and similar expressions.  Forward looking statements involve risks and uncertainties that may cause actual results or outcomes to differ materially from those included in the forward looking statements.  Factors that may cause actual results to differ materially from those included in the forward looking stateme nts include, but are not limited to, actions by state and federal regulatory bodies, competition and industry restructuring, changes in economic conditions, changes in weather patterns, changes in laws, regulations or regulatory policy, expiration or initiation of significant energy supply contracts, changes in levels of capital expenditures, developments in legal or public policy doctrines, technological developments, volatility in electric and natural gas commodity markets, effectiveness of our risk management policies and procedures, changes in accounting standards and financial reporting regulations, fluctuations in the value of electricity positions, actions of rating agencies, terrorist attacks on domestic energy facilities and other presently unknown or unforeseen factors. Other risk factors are detailed from time to time in our reports to the SEC.  Management undertakes no obligation to update the information contained in any forward looking statements to reflect developments or circumstances oc curring after the statement is made.

Web site:  Additional financial information is available through WMECO's web site at www.wmeco.com.

6

RESULTS OF OPERATIONS

The following table provides the variances in income statement line items for the consolidated statements of income included in this annual report for the past two years.  

Income Statement Variances	2005 over/(under) 2004			2004 over/(under) 2003
(Millions of Dollars)	Amount	Percent		Amount	Percent
Operating Revenues	$30	8	%	$(12)	(3)	%
Operating Expenses:
Fuel, purchased and net interchange power	31	14		16	8
Other operation	11	17		1	1
Maintenance	1	6		-	-
Depreciation	1	8		1	7
Amortization of regulatory (liabilities)/assets, net	(19)	(a)		(28)	(65)
Amortization of rate reduction bonds	1	7		1	7
Taxes other than income taxes	(1)	(4)		-	-
Total operating expenses	25	7		(9)	(3)
Operating Income	5	16		(3)	(7)
Interest expense, net	2	15		2	14
Other income, net	2	(a)		(4)	(91)
Income before income tax expense	5	25		(9)	(30)
Income tax expense	2	29		(5)	(39)
Net income	$ 3	22	%	$ (4)	(24)	%

(a) Percent greater than 100.

Comparison of the Year 2005 to the Year 2004

Operating Revenues

Operating revenues increased $30 million in 2005, as compared to 2004, primarily due to higher distribution revenue ($28 million) and higher transmission revenue ($2 million).  The distribution revenue increase of $28 million is primarily due to the components of revenues which are included in regulatory commission approved tracking mechanisms that track the recovery of certain incurred costs ($20 million).  The tracking mechanisms allow for rates to be changed periodically with over collections refunded to customers or under collections collected from customers in future periods.  The distribution revenue tracking components increase of $20 million is primarily due to the pass through of higher energy supply costs ($26 million) and higher retail transmission revenues ($6 million), partially offset by lower transition cost recoveries ($13 million).  The distribution component of WMECO’s retail rates w hich impacts earnings increased $7 million primarily due to an increase in retail rates ($6 million) and an increase in retail sales volume.  Retail sales increased 1.4 percent in 2005 compared to 2004.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expense increased $31 million primarily due to higher default service supply costs ($24 million) and higher current year purchased power costs ($6 million).

Other Operation

Other operation expenses increased $11 million in 2005 primarily due to higher administrative expenses ($7 million) as a result of higher pension and other benefit costs ($3 million) and employee termination and benefit plan curtailment charges ($3 million), and higher retail transmission expenses ($3 million).

Maintenance

Maintenance expense increased $1 million in 2005 primarily due to higher substation maintenance.

Depreciation

Depreciation expense increased $1 million in 2005 primarily due to higher utility plant balances.

Amortization of Regulatory (Liabilities)/Assets, Net

Amortization of regulatory (liabilities) / assets, net decreased $19 million in 2005 primarily due to the lower recovery of stranded costs as a result of the decrease in the transition component of retail rates ($13 million) and the 2004 completion of the amortization of nuclear stranded costs ($6 million).

Amortization of Rate Reduction Bonds

Amortization of rate reduction bonds increased $1 million in 2005 due to the repayment of a higher principal amount as compared to 2004.

Taxes Other Than Income Taxes

Taxes other than income taxes decreased $1 million in 2005 primarily due to lower property taxes.

Interest Expense, Net

Interest expense, net increased $2 million in 2005 primarily due to higher long-term debt levels as a result of the issuance of $50 million of thirty-year senior notes in September 2004 ($2 million) and the issuance of $50 million ten-year senior notes in August 2005 ($1 million), partially offset by lower rate reduction bond interest resulting from lower principal balances outstanding ($1 million).

Other Income, Net

Other income, net increased $2 million in 2005 primarily due to higher interest and dividend income and a higher AFUDC.

Income Taxes

Income tax expense increased $2 million in 2005, primarily due to higher book taxable income.  

Comparison of the Year 2004 to the Year 2003

Operating Revenues

Operating revenues decreased $12 million in 2004, as compared to the same period in 2003, due to lower distribution revenues.  Distribution revenues were lower primarily due to a decrease in the retail transition charge and retail transmission rates ($26 million), which was partially offset by an increase in retail standard offer service revenues ($21 million).  Retail sales increased by 1.6 percent.  Wholesale revenues were $6 million lower primarily due to a lower number of wholesale transactions.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expense increased $16 million primarily due to higher standard offer / default service supply costs.

Other Operation

Other operation expenses increased $1 million in 2004 due to higher administrative and general expense ($3 million) primarily due to lower pension income and higher distribution expenses ($1 million), partially offset by lower transmission expenses ($3 million).

Depreciation

Depreciation expense increased $1 million in 2004 primarily due to higher utility plant balances.

Amortization of Regulatory (Liabilities)/Assets, Net

Amortization of regulatory (liabilities)/assets, net decreased $28 million in 2004 primarily due to the lower recovery of stranded costs as a result of the decrease in the transition component of retail rates.

Amortization of Rate Reduction Bonds

Amortization of rate reduction bonds increased $1 million in 2004 due to the repayment of a higher principal amount as compared to 2003.

Interest Expense, Net

Interest expense, net increased $2 million in 2004 primarily due to higher long-term debt levels as a result of the issuance of debt in September 2003 and September 2004.

Other Income/(Loss), Net

Other income / (loss), net decreased $4 million in 2004 primarily due to the absence of a gain on disposition of property that occurred in 2003 ($2 million) and a decrease in interest and dividend income ($1 million).

Income Taxes

Income tax expense decreased $5 million in 2004, primarily due to lower book taxable income.

7

Company Report on Internal Controls     

Management is responsible for the preparation, integrity, and fair presentation of the accompanying consolidated financial statements of Western Massachusetts Electric Company and subsidiary and other sections of this annual report.  These financial statements, which were audited by Deloitte & Touche LLP, 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 controls over financial reporting that is designed to provide reasonable assurance, at an appropriate cost-benefit relationship, to the company’s management and Board of Trustees of Northeast Utilities regarding the preparation of reliable, published financial statements.  The system is supported by an organization of trained management personnel, policies and procedures, and a comprehensive program of internal audits.  Through established programs, the company regularly communicates to its management employees their internal control responsibilities and obtains information regarding compliance with policies prohibiting conflicts of interest and policies segregating information between regulated and unregulated subsi diary companies.  The company has standards of business conduct for all employees, as well as a code of ethics for senior financial officers.

The Audit Committee of the Board of Trustees of Northeast Utilities is composed entirely of independent trustees and includes two members that the Board of Trustees considers "audit committee financial experts."  The Audit Committee meets regularly with management, the internal auditors, and the independent auditors to review the activities of each and to discuss audit matters, financial reporting matters, and the system of internal controls over financial reporting.  The Audit Committee also meets periodically with the internal auditors and the independent auditors without management present.

Because of inherent limitations in any system of internal controls, errors or irregularities may occur and not be detected.  The company believes, however, that its system of internal controls over financial reporting and control environment provide reasonable assurance that its assets are safeguarded from loss or unauthorized use and that its financial records, which are the basis for the preparation of all financial statements, are reliable.  Additionally, management believes that its disclosure controls and procedures are in place and operating effectively.  Disclosure controls and procedures are designed to ensure that information included in reports such as this annual report is recorded, processed, summarized, and reported within the time periods required and that the information disclosed is accumulated and reviewed by management for discussion and approval.

March 7, 2006

8

Report of Independent Registered Public Accounting Firm  

To the Board of Directors of
Western Massachusetts Electric Company:

We have audited the accompanying consolidated balance sheets of Western Massachusetts Electric Company and subsidiary (a Massachusetts corporation and a wholly owned subsidiary of Northeast Utilities) (the “Company”) as of December 31, 2005 and 2004, 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, 2005.  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 the standards of the Public Company Accounting Oversight Board (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.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting.  Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.  An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Western Massachusetts Electric Company and subsidiary as of December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.

/s/  Deloitte & Touche LLP

      Deloitte & Touche LLP

Hartford, Connecticut

March 7, 2006

9

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
At December 31,		2005	2004
	(Thousands of Dollars)
ASSETS
Current Assets:
Cash		$                        1	$                   1,678
Receivables, less provision for uncollectible
accounts of $3,653 in 2005 and $2,563 in 2004		43,490	37,909
Accounts receivable from affiliated companies		5,752	11,275
Unbilled revenues		16,411	15,057
Taxes receivable		-	4,824
Materials and supplies		1,414	1,488
Marketable securities		20,905	18,481
Prepayments and other		897	1,027
		88,870	91,739
Property, Plant and Equipment:
Electric utility		671,292	640,884
Less: Accumulated depreciation		193,151	183,361
		478,141	457,523
Construction work in progress		21,176	11,361
		499,317	468,884
Deferred Debits and Other Assets:
Regulatory assets		223,174	231,907
Prepaid pension		80,618	79,706
Marketable securities		30,434	31,342
Other		23,583	18,894
		357,809	361,849
Total Assets		$              945,996	$             922,472
The accompanying notes are an integral part of these consolidated financial statements.

10

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
At December 31,	2005	2004
	(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION
Current Liabilities:
Notes payable to banks	$                        -	$                 25,000
Notes payable to affiliated companies	14,900	15,900
Accounts payable	31,333	12,860
Accounts payable to affiliated companies	9,015	20,965
Accrued taxes	1,620	544
Accrued interest	4,517	3,515
Other	9,364	9,377
	70,749	88,161
Rate Reduction Bonds	111,331	122,489
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	219,992	220,705
Accumulated deferred investment tax credits	2,655	2,990
Deferred contractual obligations	66,633	76,965
Regulatory liabilities	23,836	25,160
Other	11,977	13,846
	325,093	339,666
Capitalization:
Long-Term Debt	259,487	207,684
Common Stockholder's Equity:
Common stock, $25 par value – authorized
1,072,471 shares; 434,653 shares outstanding
in 2005 and 2004	10,866	10,866
Capital surplus, paid in	82,811	76,103
Retained earnings	84,965	77,565
Accumulated other comprehensive income/(loss)	694	(62)
Common Stockholder's Equity	179,336	164,472
Total Capitalization	438,823	372,156
Commitments and Contingencies (Note 4)
Total Liabilities and Capitalization	$            945,996	$              922,472
The accompanying notes are an integral part of these consolidated financial statements.

11

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31,	2005	2004	2003
	(Thousands of Dollars)
Operating Revenues	$        409,393	$              379,229	$              391,178
Operating Expenses:
Operation -
Fuel, purchased and net interchange power	245,763	214,966	198,985
Other	71,184	60,727	59,937
Maintenance	16,271	15,375	15,289
Depreciation	16,273	15,066	14,104
Amortization of regulatory (liabilities)/assets, net	(3,518)	15,421	43,538
Amortization of rate reduction bonds	11,220	10,526	9,847
Taxes other than income taxes	11,661	12,195	11,844
Total operating expenses	368,854	344,276	353,544
Operating Income	40,539	34,953	37,634
Interest Expense:
Interest on long-term debt	9,535	6,655	3,860
Interest on rate reduction bonds	7,570	8,332	8,994
Other interest	1,041	782	965
Interest expense, net	18,146	15,769	13,819
Other Income, Net	1,986	376	4,084
Income Before Income Tax Expense	24,379	19,560	27,899
Income Tax Expense	9,294	7,187	11,687
Net Income	$          15,085	$                12,373	$                16,212
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Net Income	$          15,085	$                12,373	$                16,212
Other comprehensive income, net of tax:
Qualified cash flow hedging instruments	951	-	-
Unrealized (losses)/gains on securities	(244)	41	37
Minimum supplemental executive retirement
pension liability adjustments	49	(19)	(27)
Other comprehensive income, net of tax	756	22	10
Comprehensive Income	$          15,841	$                12,395	$               16,222
The accompanying notes are an integral part of these consolidated financial statements.

12

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
	Common Stock		Capital		Accumulated Other
			Surplus,	Retained	Comprehensive
	Shares	Amount	Paid In	Earnings	(Loss))/Income	Total
		(Thousands of Dollars, except share information)
Balance at January 1, 2003	434,653	$        10,866	$           69,712	$           77,476	$             (94)	$            157,960
Net income for 2003				16,212		16,212
Cash dividends on common stock				(22,011)		(22,011)
Allocation of benefits - ESOP			(168)			(168)
Other comprehensive income					10	10
Balance at December 31, 2003	434,653	10,866	69,544	71,677	(84)	152,003
Net income for 2004				12,373		12,373
Cash dividends on common stock				(6,485)		(6,485)
Capital contribution from NU parent			6,500			6,500
Tax deduction for stock options exercised and Employee
Stock Purchase Plan disqualifying dispositions			155			155
Allocation of benefits - ESOP			(96)			(96)
Other comprehensive income					22	22
Balance at December 31, 2004	434,653	10,866	76,103	77,565	(62)	164,472
Net income for 2005				15,085		15,085
Cash dividends on common stock				(7,685)		(7,685)
Capital contribution from NU parent			6,773			6,773
Tax deduction for stock options exercised and Employee
Stock Purchase Plan disqualifying dispositions			28			28
Allocation of benefits - ESOP			(93)			(93)
Other comprehensive income					756	756
Balance at December 31, 2005	434,653	$        10,866	$           82,811	$           84,965	$             694	$            179,336
The accompanying notes are an integral part of these consolidated financial statements.

13

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31,	2005	2004	2003
	(Thousands of Dollars)
Operating Activities:
Net income	$                15,085	$                12,373	$                16,212
Adjustments to reconcile to net cash flows
provided by operating activities:
Bad debt expense	3,857	4,246	4,107
Depreciation	16,273	15,066	14,104
Deferred income taxes	(1,884)	4,211	(16,158)
Amortization of regulatory (liabilities)/assets, net	(3,518)	15,421	43,538
Amortization of rate reduction bonds	11,220	10,526	9,847
Amortization of recoverable energy costs	1,858	597	598
Pension income	(647)	(2,662)	(4,770)
Regulatory overrecoveries	3,502	6,907	4,422
Deferred contractual obligations	(16,557)	(9,766)	(9,380)
Other non-cash adjustments	1,955	1,091	(7,868)
Other sources of cash	-	6,047	9,516
Other uses of cash	(6,029)	(2,402)	(6,695)
Changes in current assets and liabilities:
Receivables and unbilled revenues, net	(5,269)	(9,552)	(5,541)
Materials and supplies	74	96	237
Other current assets	130	(4,712)	331
Accounts payable	5,231	2,008	7,880
Accrued taxes	5,900	(221)	(3,569)
Other current liabilities	(1,150)	1,228	2,461
Net cash flows provided by operating activities	30,031	50,502	59,272
Investing Activities:
Investments in plant	(44,739)	(39,250)	(32,649)
Net proceeds from sale of property	1,599	-	-
Proceeds from sales of investment securities	82,937	55,224	327
Purchases of investment securities	(84,939)	(104,883)	(599)
Other investing activities	1,504	1,097	1,850
Net cash flows used in investing activities	(43,638)	(87,812)	(31,071)
Financing Activities:
Issuance of long-term debt	50,000	50,000	55,000
Retirement of rate reduction bonds	(11,158)	(10,471)	(9,782)
(Decrease)/increase in short-term debt	(25,000)	15,000	3,000
NU Money Pool lending	(1,000)	(15,500)	(54,500)
Capital contribution from Northeast Utilities	6,773	6,500	-
Cash dividends on common stock	(7,685)	(6,485)	(22,011)
Other financing activities	-	(57)	(30)
Net cash flows provided by/(used in) financing activities	11,930	38,987	(28,323)
Net (decrease)/increase in cash	(1,677)	1,677	(122)
Cash - beginning of year	1,678	1	123
Cash - end of year	$                         1	$                 1,678	$                         1
Supplemental Cash Flow Information:
Cash paid during the year for:
Interest, net of amounts capitalized	$                17,900	$               15,020	$                13,560
Income taxes	$                  5,084	$               13,523	$                31,807
The accompanying notes are an integral part of these consolidated financial statements.

14

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) is a wholly owned subsidiary of Northeast Utilities (NU).  WMECO is a reporting company under the Securities Exchange Act of 1934.  Until February 8, 2006, NU was registered with the Securities and Exchange Commission (SEC) as a holding company under the Public Utility Holding Company Act of 1935 (PUHCA).  On February 8, 2006, PUHCA was repealed.  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 furnishes franchised retail electric service in Massachusetts.  WMECO’s results include the operations of its distribution and transmission segments.

Several wholly owned subsidiaries of NU provide support services for NU’s companies, including WMECO.  Northeast Utilities Service Company (NUSCO) provides centralized accounting, administrative, engineering, financial, information technology, legal, operational, planning, purchasing, and other services to NU’s companies.

Included in the consolidated balance sheet at December 31, 2005 are accounts receivable from affiliated companies and accounts payable to affiliated companies totaling $5.8 million and $9 million, respectively, relating to transactions between WMECO and other subsidiaries that are wholly owned by NU.  At December 31, 2004, these amounts totaled $11.3 million and $21 million, respectively.

Total WMECO purchases from affiliate Select Energy, Inc. (Select Energy), another NU subsidiary, for standard offer and default service and for other transactions with Select Energy represented $36.3 million, $108.5 million, and $143 million for the years ended December 31, 2005, 2004 and 2003, respectively.

B.

Presentation

The consolidated financial statements of WMECO include the accounts of its subsidiary WMECO Funding LLC.  Intercompany transactions have been eliminated in consolidation.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent liabilities at the date of the consolidated 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 period data included in the accompanying consolidated financial statements have been made to conform with the current year's presentation.

In the company's consolidated balance sheet at December 31, 2004, the company changed the classification of certain deposit amounts totaling $1.1 million related to its rate reduction bonds.  The company previously presented these amounts on a gross basis in deferred debits and other assets - other with an equal and offsetting amount in other current liabilities.  For the current year presentation, these amounts are presented on a net basis in the company's accompanying consolidated balance sheet.

In the company’s consolidated statements of income for the years ended December 31, 2004 and 2003, the company changed the classification of certain costs that were not recoverable from regulated customers totaling $0.6 million and $0.9 million, respectively.  The company previously presented these amounts in other income, net.  For the current year presentation, these amounts are presented in other operation expenses in the consolidated statements of income for the years ended December 31, 2004 and 2003.  

The consolidated statements of cash flows for the years ended December 31, 2004 and 2003 have also been reclassified to exclude from cash flows from operations the change in accounts payable related to capital projects as well as excluding these amounts from investments in plant in investing activities.  These amounts totaled a source of cash of $0.7 million and a use of cash of $0.6 million for the years ended December 31, 2004 and 2003, respectively.  

C.

Accounting Standards Issued But Not Yet Adopted

Accounting Changes and Error Corrections:  In May of 2005, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 154, "Accounting Changes and Error Corrections."  SFAS No. 154 is effective beginning on January 1, 2006 for WMECO and requires retrospective application to prior periods’ financial statements of voluntary changes in accounting principles.  It also applies to accounting changes required by a new accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions.  SFAS No. 154 does not change previous guidance for reporting the correction of an error in previously issued financial statements or a change in accounting estimate.  Implementation of SFAS No. 154 on January 1, 2006 is not expected to affect WMECO’s consolidated financial statements until s uch time that its provisions are required to be applied as described above.

15

D.

Guarantees

NU provides credit assurances on behalf of subsidiaries, including WMECO, in the form of guarantees and letters of credit (LOCs) in the normal course of business.  At December 31, 2005, the maximum level of exposure in accordance with FASB Interpretation No. (FIN) 45, "Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others," under guarantees by NU on behalf of WMECO totaled $2.5 million.  A majority of these guarantees do not have established expiration dates, and some guarantees have unlimited exposure to commodity price movements.  WMECO has no guarantees of the performance of third parties.

Several underlying contracts that NU guarantees, as well as certain surety bonds, contain credit ratings triggers that would require NU to post collateral in the event that NU’s credit ratings are downgraded below investment grade.

Until the repeal of PUHCA on February 8, 2006, NU was authorized by the SEC to provide up to $50 million of guarantees to the Utility Group, including WMECO, through June 30, 2007.  The amount of guarantees on behalf of WMECO outstanding for compliance with this limit at December 31, 2005 is $0.1 million.  These amounts are calculated using different, more probabilistic and fair-value based criteria than the maximum level of exposure required to be disclosed under FIN 45.  FIN 45 includes all exposures even though they are not reasonably likely to result in exposure to NU, on behalf of WMECO.

With the repeal of PUHCA, there are no regulatory limits on NU's ability to guarantee the obligation of its subsidiaries, including WMECO.

E.

Revenues

WMECO retail revenues are based on rates approved by the Massachusetts Department of Telecommunications and Energy (DTE).  These regulated rates are applied to customers' use of energy to calculate a bill.  In general, rates can only be changed through formal proceedings with the DTE.  However, WMECO utilizes a regulatory commission-approved tracking mechanism to track the recovery of certain incurred costs.  The tracking mechanism allows for rates to be changed periodically, with overcollections refunded to customers or undercollections collected from customers in future periods.

Unbilled Revenues:  Unbilled revenues represent an estimate of electricity delivered to customers that has not yet been billed.  Unbilled revenues are included in revenue on the statement of income and are assets on the balance sheet that are reclassified to accounts receivable in the following month as customers are billed.  Such estimates are subject to adjustment when actual meter readings become available, when changes in estimating methodology occur and under other circumstances.

Through December 31, 2004, WMECO estimated unbilled revenues monthly using the requirements method.  The requirements method utilized the total monthly volume of electricity delivered to the system and applied a delivery efficiency (DE) factor to reduce the total monthly volume by an estimate of delivery losses in order to calculate total estimated monthly sales to customers.  The total estimated monthly sales amount less the total monthly billed sales amount resulted in a monthly estimate of unbilled sales.  Unbilled revenues were estimated by first allocating sales to the respective rate classes, then applying an average rate to the estimate of unbilled sales.  The estimated DE factor had a significant impact on estimated unbilled revenue amounts.

In the first quarter of 2005, management adopted a new method to estimate unbilled revenues for WMECO.  The new method allocates billed sales to the current calendar month based on the daily load for each billing cycle (DLC method).  The billed sales are subtracted from total calendar month sales to estimate unbilled sales.  The impact of adopting the new method was not material.  This new method replaces the requirements method described above.    

Transmission Revenues - Wholesale Rates:  Wholesale transmission revenues are based on rates and formulas that are approved by the FERC.  Most of WMECO’s wholesale transmission revenues are collected through a combination of the New England Regional Network Service (RNS) tariff and WMECO’s Local Network Service (LNS) tariff.  The RNS tariff, which is administered by the New England Independent System Operator (ISO-NE), recovers the revenue requirements associated with transmission facilities that are deemed by the FERC to be regional facilities.  This regional rate is reset on June 1 of each year.  The LNS tariff provides for the recovery of WMECO’s total transmission revenue requirements, net of revenues received from other sources, including those revenues received under RNS rates.  WMECO’s LNS tariff is reset on January 1 and June 1 of each year.  Additionally, WMECO’s LNS tariff provides for a true-up to actual costs, which ensures that WMECO recovers its total transmission revenue requirements, including an allowed return on equity (ROE).  At December 31, 2005, this true-up has resulted in the recognition of a $0.2 million regulatory liability.

Transmission Revenues - Retail Rates:  A significant portion of WMECO’s transmission business revenue comes from ISO-NE charges to WMECO’s distribution business.  WMECO's distribution business recovers these costs through the retail rates that are charged to its retail customers.  WMECO implemented its retail transmission tracker and rate adjustment mechanism in January of 2002 as part of its 2002 rate change filing.

F.

Derivative Instruments

The accounting treatment for energy contracts entered into varies and depends on the intended use of the particular contract and on whether or not the contract is a derivative.  WMECO has energy contracts that qualify for the normal purchases and sales exception.  Derivatives under the exception and non-derivative contracts are recorded at the time of delivery or settlement under accrual accounting.  

G.

Regulatory Accounting

The accounting policies of WMECO conform to accounting principles generally accepted in the United States of America applicable to rate-regulated enterprises and historically reflect the effects of the rate-making process in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation."

The transmission and distribution businesses of WMECO continue to be cost-of-service rate regulated and management believes that the application of SFAS No. 71 to those businesses continues to be appropriate.  Management also believes it is probable that WMECO will recover its investments in long-lived assets, including regulatory assets.  In addition, all material net regulatory assets are earning an equity return, except for securitized regulatory assets, which are not supported by equity and substantial portions of the unrecovered contractual obligations regulatory assets.  

Regulatory Assets:  The components of WMECO’s regulatory assets are as follows:

	At December 31,
(Millions of Dollars)	2005	2004
Recoverable nuclear costs	$ 18.0	$  22.3
Securitized assets	110.3	121.5
Income taxes, net	51.6	56.7
Unrecovered contractual   obligations	66.6	77.0
Recoverable energy costs	2.5	3.1
Rate cap deferral overcollections	(37.8)	(50.7)
Other	12.0	2.0
Totals	$223.2	$231.9

Included in other regulatory assets above of $12 million at December 31, 2005 are the regulatory assets recorded associated with the implementation of FIN 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143," totaling $2.4 million.  These regulatory assets have not been approved for deferred accounting treatment.  At this time, management believes that these remaining regulatory assets are probable of recovery.  

Additionally, WMECO had $0.1 million of regulatory costs at December 31, 2005 that are included in deferred debits and other assets - other on the accompanying consolidated balance sheets.  This amount represents regulatory costs that have not yet been approved by the applicable regulatory agency.  Management believes those costs are recoverable in future regulated rates.  WMECO had no such regulatory costs at December 31, 2004.

Recoverable Nuclear Costs:  Included in recoverable nuclear costs at December 31, 2005 and 2004 are $18 million and $22.3 million, respectively, primarily related to Millstone 1 recoverable nuclear costs associated with the undepreciated plant and related assets at the time Millstone 1 was shutdown.  

Securitized Assets:  In May 2001, WMECO issued $155 million in rate reduction certificates and used the majority of the proceeds from that issuance to buyout an Independent Power Producer (IPP) contract.  The unamortized WMECO securitized asset balance is $110.3 million and $121.5 million at December 31, 2005 and 2004, respectively.

Securitized assets are being recovered over the amortization period of their associated rate reduction certificates.  All outstanding rate reduction certificates of WMECO are scheduled to fully amortize by June 1, 2013.

Income Taxes, Net:  The tax effect of temporary differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of taxable income) is accounted for in accordance with the rate-making treatment of the DTE and SFAS No. 109, "Accounting for Income Taxes."  Differences in income taxes between SFAS No. 109 and the rate-making treatment of the DTE are recorded as regulatory assets, which totaled $51.6 million and $56.7 million at December 31, 2005 and 2004, respectively.  For further information regarding income taxes, see Note 1H, "Summary of Significant Accounting Policies - Income Taxes," to the consolidated financial statements.

Unrecovered Contractual Obligations:  Under the terms of contracts with the Connecticut Yankee Atomic Power Company (CYAPC), Maine Yankee Atomic Power Company (MYAPC) and Yankee Atomic Energy Company (YAEC), (Yankee Companies), WMECO is responsible for its proportionate share of the remaining costs of the units, including decommissioning.  These amounts, which totaled $66.6 million and $77 million at December 31, 2005 and 2004, respectively, are recorded as unrecovered contractual obligations.  WMECO amounts are being recovered along with other stranded costs.  As discussed in Note 4E, "Commitments and Contingencies - Deferred Contractual Obligations," substantial portions of the unrecovered contractual obligations regulatory assets have not yet been approved for recovery.  At this time management believes that these regulatory assets are probable of recovery.

Recoverable Energy Costs:  Under the Energy Policy Act of 1992 (Energy Act), WMECO was assessed for its proportionate share of the costs of decontaminating and decommissioning uranium enrichment plants owned by the United States Department of Energy (DOE) (D&D Assessment).  The Energy Act requires that regulators treat D&D Assessments as a reasonable and necessary current cost of fuel, to be fully recovered in rates like any other fuel cost.  WMECO no longer owns nuclear generation but continues to recover these costs through rates.  At December 31, 2005 and 2004, WMECO’s total D&D Assessment deferrals were $2.5 million and $3.1 million, respectively, and have been recorded as recoverable energy costs.  

The majority of the recoverable energy costs are currently recovered in rates from WMECO's customers.

Rate Cap Deferral Overcollections:  The rate cap deferral allows WMECO to recover stranded costs.  These amounts represent the cumulative excess of transition cost revenues over transition cost expenses, which totaled $37.8 million and $50.7 million at December 31, 2005 and 2004, respectively.

Regulatory Liabilities:  WMECO had $23.8 million and $25.2 million of regulatory liabilities at December 31, 2005 and 2004, respectively, including revenues subject to refund.  These amounts are comprised of the following:

	At December 31,
(Millions of Dollars)	2005	2004
Cost of removal	$23.6	$24.1
Other regulatory liabilities	0.2	1.1
Totals	$23.8	$25.2

Under SFAS No. 71, WMECO currently recovers amounts in rates for future costs of removal of plant assets.  These amounts, which totaled $23.6 million and $24.1 million at December 31, 2005 and 2004, respectively, are classified as regulatory liabilities on the accompanying consolidated balance sheets.  

H.

Income Taxes

The tax effect of temporary differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of taxable income) is accounted for in accordance with the rate-making treatment of the DTE and SFAS No. 109.

Details of income tax expense are as follows:

	For the Years Ended December 31,
		2005	2004	2003
		(Millions of Dollars)
The components of the federal and   state income tax provisions are:
Current income taxes:
Federal		$10.1	$1.4	$23.4
State		1.1	1.6	4.4
Total current		11.2	3.0	27.8
Deferred income taxes, net:
Federal		(2.0)	10.8	(13.5)
State		0.4	(6.2)	(2.3)
Total deferred		(1.6)	4.6	(15.8)
Investment tax credits, net		(0.3)	(0.4)	(0.3)
Total income tax expense		$9.3	$7.2	$11.7

A reconciliation between income tax expense and the expected tax expense at the statutory rate is as follows:

	For the Years Ended December 31,
		2005	2004	2003
		(Millions of Dollars)
Expected federal income tax   expense		$8.5	$6.8	$  9.8
Tax effect of differences:
Depreciation		0.4	0.8	0.6
Investment tax credit     amortization		(0.3)	(0.4)	(0.3)
State income taxes,     net of federal benefit		1.0	0.8	1.4
Medicare subsidy		(0.5)	(0.1)	-
Other, net		0.2	(0.7)	0.2
Total income tax expense		$9.3	$7.2	$11.7

NU and its subsidiaries, including WMECO, file a consolidated federal income tax return.  NU and its subsidiaries, including WMECO, are parties to a tax allocation agreement under which taxable subsidiaries pay no more taxes than they would have otherwise paid had they filed a stand-alone tax return.  Subsidiaries generating tax losses are similarly paid for their losses when utilized.

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The tax effects of temporary differences that give rise to the current and long-term net accumulated deferred tax obligations are as follows:

	At December 31,
(Millions of Dollars)	2005	2004
Deferred tax liabilities - current:
Property tax accruals	$   1.9	$   2.0
Total deferred tax liabilities - current	1.9	2.0
Deferred tax assets - current:
Allowance for uncollectible accounts	1.4	1.0
Total deferred tax assets - current	1.4	1.0
Net deferred tax liabilities - current	0.5	1.0
Deferred tax liabilities - long-term:
Accelerated depreciation and       other plant-related differences	110.3	105.8
Employee benefits	31.5	31.3
Securitized costs	42.0	46.2
Income tax gross-up	21.8	23.7
Other	45.4	53.1
Total deferred tax liabilities - long-term	251.0	260.1
Deferred tax assets – long-term:
Regulatory deferrals	25.2	35.1
Employee benefits	1.7	1.4
Income tax gross-up	1.6	1.4
Other	2.5	1.5
Total deferred tax assets - long-term	31.0	39.4
Net deferred tax liabilities - long-term	220.0	220.7
Net deferred tax liabilities	$220.5	$221.7

I.

Depreciation

The provision for depreciation on utility assets is calculated using the straight-line method based on estimated remaining useful lives of depreciable 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 plant-in-service from the time it is placed in service.  When plant is retired from service, the original cost of the plant, including costs of removal less salvage, is charged to the accumulated provision for depreciation.  Cost of removal is classified as a regulatory liability.  The depreciation rates for the several classes of electric utility plant-in-service are equivalent to a composite rate of 2.5 percent for both 2005 and 2004 and 2.4 percent in 2003.

J.

Jointly Owned Electric Utility Plant

At December 31, 2005, WMECO owns common stock in the Yankee Companies.  Each of the Yankee Companies owns a single nuclear generating plant which is being decommissioned.  WMECO’s ownership interests in the Yankee Companies at December 31, 2005 and 2004, which are accounted for on the equity method, are 9.5 percent of CYAPC, 7 percent of YAEC and 3 percent of MYAPC.  WMECO’s total carrying value of the Yankee companies, which is included in deferred debits and other assets - other on the accompanying consolidated balance sheets and the electric distribution reportable segment, at December 31, 2005 and 2004 was $5.3 million and $5.2 million, respectively.  Earnings related to these equity investments are included in other income, net on the accompanying consolidated statements of income.  For further information, see Note 1N, "Summary of Significant Accounting Policies - Other Incom e, Net," to the consolidated financial statements.   

CYAPC filed with the FERC to recover the increased estimate of decommissioning and plant closure costs.  The FERC proceeding is ongoing.  Management believes that the FERC proceeding has not impaired the value of its investment in CYAPC totaling $4.4 million at December 31, 2005 but will continue to evaluate the impacts that the FERC proceeding has on NU's investment.  For further information, see Note 4E, "Commitments and Contingencies - Deferred Contractual Obligations," to the consolidated financial statements.

K.

Allowance for Funds Used During Construction

The allowance for funds used during construction (AFUDC) is a non-cash item that is included in the cost of WMECO plant and represents the cost of borrowed and equity funds used to finance construction.  The portion of AFUDC attributable to borrowed funds is recorded as a reduction of other interest expense and the cost of equity funds is recorded as other income on the consolidated statements of income as follows:  

	For the Years Ended December 31,
(Millions of Dollars,  except percentages)	2005		2004		2003
Borrowed funds	$0.5		$0.2		$0.1
Equity funds	0.2		-		-
Totals	$0.7		$0.2		$0.1
Average AFUDC rate	5.0	%	2.2	%	1.7	%

The average AFUDC rate is based on a FERC-prescribed formula that develops an average rate using the cost of the company's short-term financings as well as the company's capitalization (long-term debt and common equity).  The average rate is applied to eligible CWIP amounts to calculate AFUDC.  The increase in the average AFUDC rate during 2005 is primarily due to increases in short-term and long-term debt interest rates.  

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L.

Asset Retirement Obligations

On January 1, 2003, WMECO implemented SFAS No. 143, "Accounting for Asset Retirement Obligations," requiring legal obligations associated with the retirement of property, plant and equipment to 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.  Management concluded that there were no asset retirement obligations (AROs) to be recorded upon implementation of SFAS No. 143.  

In March of 2005, the FASB issued FIN 47, required to be implemented by December 31, 2005.  FIN 47 requires an entity to recognize a liability for the fair value of an ARO even if it is conditional on a future event and the liability’s fair value can be reasonably estimated.  FIN 47 provides that settlement dates and future costs should be reasonably estimated when sufficient information becomes available, and provides guidance on the definition and timing of sufficient information in determining expected cash flows and fair values.  Management has completed its identification of conditional AROs, and has identified various categories of AROs primarily certain assets containing asbestos and hazardous contamination.  A fair value calculation, reflecting expected probabilities for settlement scenarios, and a data consistency review for WMECO has been performed.  

WMECO utilized regulatory accounting in accordance with SFAS No. 71 and the impact of this implementation is included in other regulatory assets at December 31, 2005.  The fair value of the AROs is included in property, plant and equipment and related accretion is recorded as a regulatory asset, with corresponding credits reflecting the ARO liabilities in deferred credits and other liabilities - other, on the accompanying consolidated balance sheet at December 31, 2005.  Depreciation of the ARO asset is also included as a regulatory asset with an offsetting amount in accumulated depreciation.

The following table presents the fair value of the ARO, the related accumulated depreciation, the regulatory asset, and the ARO liabilities:

	At December 31, 2005
(Millions of Dollars)	Fair Value of ARO Asset	Accumulated Depreciation of ARO Asset	Regulatory Asset	ARO Liabilities
Asbestos	$0.3	$(0.2)	$1.5	$(1.6)
Hazardous   contamination	-	-	-	-
Other AROs	0.8	(0.1)	0.9	(1.6)
Total AROs	$1.1	$(0.3)	$2.4	$(3.2)

The ARO liabilities as of December 31, 2005, 2004 and January 1, 2004, as if FIN 47 had been applied for all periods affected, were $3.2 million, $3.2 million and $3.1 million, respectively.

M.

Materials and Supplies

Materials and supplies include materials purchased primarily for construction, operation and maintenance (O&M) purposes.  Materials and supplies are valued at the lower of average cost or market.

N.

Other Income, Net

The pre-tax components of WMECO’s other income/(loss) items are as follows:

	For the Years Ended December 31,
(Millions of Dollars)	2005	2004	2003
Other Income:
Investment income	$0.7	$  0.6	$ 1.3
Equity in earnings of     regional nuclear     generating companies	0.3	0.1	0.5
Conservation load    management incentive	0.9	0.9	0.8
Gain on sale of property	0.2	0.2	2.0
Other	1.4	1.0	1.1
Total Other Income	3.5	2.8	5.7
Other Loss:
Charitable donations	(0.3)	(0.3)	(0.3)
Lobbying costs	(0.5)	(0.5)	(0.4)
Administrative fees -      rate reduction bonds	(0.3)	(0.3)	(0.3)
Other	(0.4)	(1.3)	(0.6)
Total Other Loss	(1.5)	(2.4)	(1.6)
Total Other Income, Net	$2.0	$ 0.4	$ 4.1

None of the other amounts in either other income - other or other loss - other are individually significant as defined by the SEC.

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O.

Marketable Securities

WMECO currently maintains a trust that holds marketable securities.  The trust is used to fund WMECO's prior spent nuclear fuel liability.  At December 31, 2005 and 2004, the spent nuclear fuel trust had a fair value of $50.8 million and $49.3 million, respectively.  Also included are marketable securities which are held to fund NU's Supplemental Executive Retirement Plan (SERP).  These amounts totaled $0.5 million at December 31, 2005 and December 31, 2004.  WMECO's marketable securities are classified as available-for-sale, as defined by SFAS No. 115, "Accounting for Certain Investments and Debt and Equity Securities."  Unrealized gains and losses are reported as a component of accumulated other comprehensive income in the consolidated statements of shareholders' equity.  Realized gains and losses are included in other income, net on the consolidated statements of income.  R ealized gains and losses associated with the WMECO spent nuclear fuel trust are included in fuel, purchased and net interchange power on the consolidated statements of income.  For further information regarding marketable securities, see Note 6, "Marketable Securities," to the consolidated financial statements.  

P.

Provision for Uncollectible Accounts

WMECO maintains a provision for uncollectible accounts to record its receivables at an estimated net realizable value.  This provision is determined based upon a variety of factors, including applying an estimated uncollectible account percentage to each receivables aging category, historical collection and write-off experience and management's assessment of collectibility from individual customers.  Management reviews at least quarterly the collectibility of the receivables, and if circumstances change, collectibility estimates are adjusted accordingly.  Receivable balances are written-off against the provision for uncollectible accounts when these balances are deemed to be uncollectible.  

Q.  Severance Benefits

As a result of NU’s decision to pursue a fundamentally different business strategy, and align the structure of the company to support this business strategy, WMECO recorded a $1.8 million severance benefits charge in other operating expenses on the accompanying consolidated statement of income for the year ended December 31, 2005.

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, the FERC, or by the DTE.  On October 28, 2005, the SEC amended its June 30, 2004 order, granting authorization to allow WMECO to incur total short-term borrowings up to a maximum of $200 million through June 30, 2007.  The SEC also granted authorization for borrowing through the NU Money Pool (Pool) until June 30, 2007.  Although PUHCA was repealed on February 8, 2006, under FERC's transition rules, all of the existing orders under PUHCA relevant to FERC authority will continue to be in effect until December 31, 2007, except for those related to NU, which will have no borrowing limitations after February 8, 2006.  WMECO will be subject to FERC jurisdiction as to issuing short-term debt after February 8, 2006 and must renew any short-term authority after the PUHCA order expires on December 31, 2007.

Credit Agreement:  On December 9, 2005, WMECO amended its 5-year unsecured revolving credit facility by extending the expiration date by one year to November 6, 2010.  The company can borrow up to $100 million on a short-term basis, or subject to regulatory approvals, on a long-term basis.  The weighted average interest rate of WMECO's notes payable to banks outstanding at December 31, 2004 was 4.3 percent.  At December 31, 2005, WMECO had no borrowings outstanding under this facility.  At December 31, 2004, there were $25 million in borrowings under this credit facility.

Under this credit agreement, WMECO may borrow at variable rates plus an applicable margin based upon certain debt ratings, as rated by the higher of Standard and Poor's (S&P) or Moody's Investors Service (Moody's).  

Under this credit agreement, WMECO must comply with certain financial and non-financial covenants, including but not limited to consolidated debt ratios.  WMECO currently is and expects to remain in compliance with these covenants.

Amounts outstanding under this credit facility are classified as current liabilities as notes payable to banks on the accompanying consolidated balance sheets as management anticipates that all borrowings under this credit facility will be outstanding for no more than 364 days at one time.

Pool:  WMECO is a member of the Pool.  The Pool provides a more efficient use of 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, 2005 and 2004, WMECO had borrowings of $14.9 million and $15.9 million from the Pool, respectively.  The interest ra te on borrowings from the Pool at December 31, 2005 and 2004 was 4.09 percent and 2.24 percent, respectively.  

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3.  Pension Benefits and Postretirement Benefits Other Than Pensions 

Pension Benefits:  WMECO participates in a uniform noncontributory defined benefit retirement plan (Pension Plan) covering substantially all regular NU employees.  Benefits are based on years of service and the employees’ highest eligible compensation during 60 consecutive months of employment.  WMECO uses a December 31^st measurement date for the Pension Plan.  Pension income attributable to earnings is as follows:

	For the Years Ended December 31,
(Millions of Dollars)	2005	2004	2003
Total pension income	$ 0.9	$4.3	$ 7.9
Amount capitalized as utility plant	(0.3)	(1.6)	(3.1)
Total pension income,   net of amounts capitalized	$ 0.6	$2.7	$ 4.8

Amounts above include pension curtailments and termination benefits expense of $0.7 million in 2005 and $0.3 million in 2004.  

Not included in the pension income amount above are pension related intercompany allocations totaling $1.7 million, $0.6 million and $(0.2) million for the years ended December 31, 2005, 2004 and 2003, respectively, including pension curtailment and termination benefits expense of $0.4 million and $0.1 million for the years ended December 31, 2005 and 2004, respectively.  These amounts are included in other operating expenses on the accompanying consolidated financial statements.  

Pension Curtailments and Termination Benefits:  As a result of NU's decision to pursue a fundamentally different business strategy, and align the structure of the company to support this business strategy, WMECO recorded a $0.2 million pre-tax curtailment expense in 2005.  WMECO also accrued certain related termination benefits and recorded a $0.3 million pre-tax charge in 2005.  

On December 15, 2005, the NU Board of Trustees approved a benefit for new non-union employees hired on and after January 1, 2006 to receive retirement benefits under a new 401(k) benefit rather than under the Pension Plan.  Non-union employees actively employed on December 31, 2005 will be given the choice in 2006 to elect to continue participation in the Pension Plan or instead receive a new employer contribution under the 401(k) Savings Plan effective January 1, 2007.  If the new benefit is elected, their accrued pension liability in the Pension Plan will be frozen as of December 31, 2006.  Non-union employees will make this election in the second half of 2006.  This decision resulted in the recording of an estimated pre-tax curtailment expense of $0.2 million in 2005, as a certain number of employees are expected to elect the new 401(k) benefit, resulting in a reduction in aggregate estimated future years of service under the Pension Plan.  Management estimated the amount of the curtailment expense associated with this change based upon actuarial calculations and certain assumptions, including the expected level of transfers to the new 401(k) benefit.  

In April of 2004, as a result of litigation with nineteen former employees, NU was ordered by the court to modify its Pension Plan to include special retirement benefits for fifteen of these former employees retroactive to the dates of their retirement and provide increased future monthly benefit payments.  WMECO recorded $0.3 million in termination benefits related to this litigation in 2004 and made a lump sum benefit payment totaling $0.2 million to these former employees.

There were no curtailments or termination benefits in 2003 that impacted earnings.

Market-Related Value of Pension Plan Assets:  WMECO bases the actuarial determination of pension plan income or expense on a market-related valuation of assets, which reduces year-to-year volatility.  This market-related valuation calculation recognizes investment gains or losses over a four-year period from the year in which they occur.  Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the fair value of assets.  Since the market-related valuation calculation recognizes gains or losses over a four-year period, the future value of the market-related assets will be impacted as previously deferred gains or losses are recognized.

Postretirement Benefits Other Than Pensions:  WMECO also provides 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 WMECO who have met specified service requirements.  For current employees and certain retirees, the total benefit is limited to two times the 1993 per retiree health care cost.  These costs are charged to expense over the estimated work life of the employee.  WMECO uses a December 31^st measurement date for the PBOP Plan.  

WMECO annually funds postretirement costs through external trusts with amounts that have been and will continue to be recovered in rates and which also are tax deductible.  Currently, there are no pending regulatory actions regarding postretirement benefit costs and there are no postretirement benefit costs that are deferred as regulatory assets.

20

Impact of New Medicare Changes on PBOP:  On December 8, 2003, the President signed into law a bill that expands Medicare, primarily by adding a prescription drug benefit starting in 2006 for Medicare-eligible retirees as well as a federal subsidy to plan sponsors of retiree health care benefit plans who provide a prescription drug benefit at least actuarially equivalent to the new Medicare benefit.

Based on the current PBOP Plan provisions, WMECO qualifies for this federal subsidy because the actuarial value of WMECO’s PBOP Plan exceeds the threshold required for the subsidy.  The Medicare changes decreased the PBOP benefit obligation by $2.8 million.  The total $2.8 million decrease is currently being amortized as a reduction to PBOP expense over approximately 13 years.  For the years ended December 31, 2005 and 2004, this reduction in PBOP expense totaled approximately $0.4 million, including amortization of the actuarial gain of $0.2 million and a reduction in interest cost and service cost based on a lower PBOP benefit obligation of $0.2 million.  

PBOP Curtailments and Termination Benefits:   WMECO recorded an estimated $0.6 million pre-tax curtailment expense at December 31, 2005 relating to NU's change in business strategy.  WMECO also accrued a $0.1 million pre-tax termination benefit at December 31, 2005 relating to certain benefits provided under the terms of the PBOP Plan.  

There were no curtailments or termination benefits in 2004 and 2003.  

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)	2005	2004	2005	2004
Change in benefit obligation
Benefit obligation at beginning of year	$(157.6)	$(143.8)	$(41.2)	$(35.9)
Service cost	(3.4)	(2.9)	(0.6)	(0.5)
Interest cost	(9.3)	(8.8)	(2.1)	(2.3)
Transfers	0.5	1.1	-	-
Actuarial loss	(12.5)	(11.5)	(2.2)	(5.4)
Benefits paid - excluding lump sum payments	8.4	8.4	3.2	2.9
Benefits paid - lump sum payments	-	0.2	-	-
Curtailment/impact of plan changes	2.4	-	0.1	-
Termination benefits	(0.2)	(0.3)	(0.1)	-
Benefit obligation at end of year	$(171.7)	$(157.6)	$(42.9)	$(41.2)
Change in plan assets
Fair value of plan assets at beginning of year	$  209.3	$ 195.3	$ 19.9	$ 17.4
Actual return on plan assets	15.8	23.7	1.2	1.7
Employer contribution	-	-	4.3	3.7
Transfers	(0.5)	(1.1)	-	-
Benefits paid - excluding lump sum payments	(8.4)	(8.4)	(3.2)	(2.9)
Benefits paid - lump sum payments	-	(0.2)	-	-
Fair value of plan assets at end of year	$ 216.2	$209.3	$  22.2	$  19.9
Funded status at December 31st	$   44.5	$  51.7	$(20.7)	$(21.3)
Unrecognized transition obligation	-	-	9.1	11.2
Unrecognized prior service cost	3.5	5.1	-	-
Unrecognized net loss	32.6	22.9	10.9	10.1
Prepaid/(accrued) benefit cost	$   80.6	$  79.7	$ (0.7)	$       -

The $2.4 million reduction in the plan's obligation that is included in the curtailment/impact of plan changes relates to the reduction in the future years of service expected to be rendered by plan participants.  This reduction is the result of the transition of employees into the new 401(k) benefit and the company's decision to pursue a fundamentally different business strategy, and align the structure of the company to support this business strategy.  This overall reduction in plan obligation serves to reduce the previously unrecognized actuarial losses.

The company amortizes its unrecognized transition obligation over the remaining service lives of its employees as calculated for WMECO on an individual operating company basis.  The company amortizes the unrecognized prior service cost and unrecognized net loss over the remaining service lives of its employees as calculated on a NU consolidated basis.

The accumulated benefit obligation (ABO) for the Pension Plan was $153.1 million and $137.7 million at December 31, 2005 and 2004, respectively.

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The following actuarial assumptions were used in calculating the plans’ year end funded status:

	At December 31,
	Pension Benefits				Postretirement Benefits
Balance Sheets	2005		2004		2005		2004
Discount rate	5.80	%	6.00	%	5.65	%	5.50	%
Compensation/progression rate	4.00	%	4.00	%	N/A		N/A
Health care cost trend rate	N/A		N/A		7.00	%	8.00	%

The components of net periodic (income)/expense are as follows:

	For the Years Ended December 31,
	Pension Benefits			Postretirement Benefits
(Millions of Dollars)	2005	2004	2003	2005	2004	2003
Service cost	$  3.4	$  2.9	$   2.5	$0.6	$0.5	$ 0.4
Interest cost	9.3	8.8	8.7	2.2	2.3	2.4
Expected return on plan assets	(17.4)	(17.6)	(18.2)	(1.3)	(1.3)	(1.3)
Amortization of unrecognized net   transition (asset)/obligation	-	(0.2)	(0.2)	1.4	1.4	1.4
Amortization of prior service cost	0.7	0.7	0.7	-	-	-
Amortization of actuarial loss/(gain)	2.4	0.8	(1.4)	-	-	-
Other amortization, net	-	-	-	1.3	0.8	0.6
Net periodic (income)/expense – before  curtailments and termination benefits	(1.6)	(4.6)	(7.9)	4.2	3.7	3.5
Curtailment expense	0.4	-	-	0.6	-	-
Termination benefits expense	0.3	0.3	-	0.1	-	-
Total - curtailments and termination benefits	0.7	0.3	-	0.7	-	-
Total - net periodic (income)/expense	$(0.9)	$  (4.3)	$ (7.9)	$4.9	$3.7	$ 3.5

For calculating pension and postretirement benefit income and expense amounts, the following assumptions were used:

	For the Years Ended December 31,
Statements of Income	Pension Benefits						Postretirement Benefits
	2005		2004		2003		2005		2004		2003
Discount rate	6.00	%	6.25	%	6.75	%	5.50	%	6.25	%	6.75	%
Expected long-term rate of return	8.75	%	8.75	%	8.75	%	N/A		N/A		N/A
Compensation/progression rate	4.00	%	3.75	%	4.00	%	N/A		N/A		N/A
Expected long-term rate of return -
Health assets, net of tax	N/A		N/A		N/A		6.85	%	6.85	%	6.85	%
Life assets and non-taxable     health assets	N/A		N/A		N/A		8.75	%	8.75	%	8.75	%

The following table represents the PBOP assumed health care cost trend rate for the next year and the assumed ultimate trend rate:

	Year Following December 31,
	2005		2004
Health care cost trend rate   assumed for next year	10.00	%	7.00	%
Rate to which health care   cost trend rate is assumed to   decline (the ultimate trend rate)	5.00	%	5.00	%
Year that the rate reaches   the ultimate trend rate	2011		2007

At December 31, 2004, the health care cost trend assumption was assumed to decrease by one percentage point each year through 2007.  For December 31, 2005 disclosure purposes, the health care cost trend assumption was reset for 2006 at 10 percent, decreasing one percentage point per year to an ultimate rate of 5 percent in 2011.

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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:

(Millions of Dollars)	One Percentage Point Increase	One Percentage Point Decrease
Effect on total service and   interest cost components	$0.1	$(0.1)
Effect on postretirement   benefit obligation	$1.6	$(1.4)

WMECO's investment strategy for its Pension Plan and PBOP Plan is to maximize the long-term rate of return on those plans' assets within an acceptable level of risk.  The investment strategy establishes target allocations, which are routinely reviewed and periodically rebalanced.  WMECO's expected long-term rates of return on Pension Plan assets and PBOP Plan assets are based on these target asset allocation assumptions and related expected long-term rates of return.  In developing its expected long-term rate of return assumptions for the Pension Plan and the PBOP Plan, WMECO also evaluated input from actuaries and consultants as well as long-term inflation assumptions and WMECO's historical 20-year compounded return of approximately 11 percent.  The Pension Plan's and PBOP Plan's target asset allocation assumptions and expected long-term rate of return assumptions by asset category are as follows:

	At December 31,
	Pension Benefits		Postretirement Benefits
	2005 and 2004		2005 and 2004
Asset Category	Target  Asset  Allocation	Assumed  Rate  of Return	Target  Asset  Allocation	Assumed  Rate    of Return
Equity securities:
United States	45%	9.25%	55%	9.25%
Non-United States	14%	9.25%	11%	9.25%
Emerging markets	3%	10.25%	2%	10.25%
Private	8%	14.25%	-	-
Debt Securities:
Fixed income	20%	5.50%	27%	5.50%
High yield fixed     income	5%	7.50%	5%	7.50%
Real estate	5%	7.50%	-	-

The actual asset allocations at December 31, 2005 and 2004, approximated these target asset allocations.  The plans’ actual weighted-average asset allocations by asset category are as follows:  

	At December 31,
	Pension Benefits		Postretirement Benefits
Asset Category	2005	2004	2005	2004
Equity securities:
United States	46%	47%	54%	55%
Non-United States	16%	17%	14%	14%
Emerging markets	4%	3%	1%	1%
Private	5%	4%	-	-
Debt Securities:
Fixed income	19%	19%	29%	28%
High yield fixed     income	5%	5%	2%	2%
Real estate	5%	5%	-	-
Total	100%	100%	100%	100%

Estimated Future Benefit Payments:  The following benefit payments, which reflect expected future service, are expected to be paid for the Pension and PBOP plans:

(Millions of Dollars) Year	Pension Benefits	Postretirement Benefits	Government Subsidy
2006	$ 9.2	$ 3.9	$0.4
2007	9.6	4.0	0.5
2008	9.8	4.0	0.5
2009	10.1	4.0	0.5
2010	10.4	3.9	0.5
2011-2015	56.2	19.1	2.8

Government subsidy represents amounts expected to be received from the federal government for the new Medicare prescriptions drug benefit under the PBOP Plan.

Contributions:  WMECO does not expect to make any contributions to the Pension Plan in 2006 and expects to make $4.2 million in contributions to the PBOP Plan in 2006.  

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.

Postretirement health plan assets for non-union employees are subject to federal income taxes.

4.  Commitments and Contingencies  

A.

Regulatory Developments and Rate Matters

Transition Cost Reconciliation: On March 31, 2005, WMECO filed its 2004 transition cost reconciliation with the DTE.  The DTE has combined the 2003 transition cost reconciliation filing, standard offer service and default service reconciliation, the transmission cost adjustment filing, and the 2004 transition cost reconciliation filing into a single proceeding.  The timing of a decision in the combined proceeding is uncertain, but management does not expect the outcome to have a material adverse impact on WMECO's net income or financial position.

B.

Environmental Matters

General:  WMECO is subject to environmental laws and regulations intended to mitigate or remove the effect of past operations and improve or maintain the quality of the environment.  These laws and regulations require the removal or the remedy of the effect on the environment of the disposal or release of certain specified hazardous substances at current and former operating sites.  As such, WMECO has an active environmental auditing and training program and believes that it is substantially in compliance with all enacted laws and regulations.

Environmental reserves are accrued using a probabilistic model approach when assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated.  The probabilistic model approach estimates the liability based on the most likely action plan from a variety of available remediation options, ranging from no action to several different remedies ranging from establishing institutional controls to full site remediation and monitoring.

These estimates are subjective in nature as they take into consideration several different remediation options at each specific site.  The reliability and precision of these estimates can be affected by several factors including new information concerning either the level of contamination at the site, recently enacted laws and regulations or a change in cost estimates due to certain economic factors.  

The amounts recorded as environmental liabilities on the consolidated balance sheets represent management’s best estimate of the liability for environmental costs and takes into consideration site assessment and remediation costs.  Based on currently available information for estimated site assessment and remediation costs at December 31, 2005 and 2004, WMECO had $0.4 million and $0.6 million, respectively, recorded as environmental reserves.  A reconciliation of the activity in these reserves at December 31, 2005 and 2004 is as follows:

	For the Years Ended December 31,
(Millions of Dollars)	2005	2004
Balance at beginning of year	$ 0.6	$0.7
Additions and adjustments	0.2	0.3
Payments	(0.4)	(0.4)
Balance at end of year	$ 0.4	$0.6

WMECO currently has 9 sites included in the environmental reserve.  Of those 9 sites, 6 sites are in the remediation or long-term monitoring phase, 2 sites have had some level of site assessment completed and one site is in the preliminary stage of site assessment.  

For one site that is included in the company's liability for environmental costs, the information known and nature of the remediation options at that site allows an estimate of the range of losses to be made.  This site is a manufactured gas plant (MGP) site.  At December 31, 2005, $0.1 million has been accrued as a liability for this site, which represents management's best estimate of the liability for environmental costs.  This amount differs from an estimated range of loss from zero to $9 million as management utilizes the probabilistic model approach to make its estimate of the liability for environmental costs.

For the 8 remaining sites for which an estimate is based on the probabilistic model approach, determining a range of estimated losses is not possible.  These liabilities are estimated on an undiscounted basis and do not assume that any amounts are recoverable from insurance companies or other third parties.  The environmental reserve includes sites at different stages of discovery and remediation and does not include any unasserted claims.  

At December 31, 2005, there is one site for which there are unasserted claims; however, any related remediation costs are not probable or estimable at this time.  WMECO's environmental liability also takes into account recurring costs of managing hazardous substances and pollutants, mandated expenditures to remediate previously contaminated sites and any other infrequent and non-recurring clean up costs.

It is possible that new information or future developments could require a reassessment of the potential exposure to related environmental matters.  As this information becomes available, management will continue to assess the potential exposure and adjust the reserves accordingly.

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MGP Sites:  MGP sites are sites that manufactured gas from coal and produced certain byproducts that may pose risk to human health and the environment.  At December 31, 2005 and 2004, $0.1 million and $0.3 million, respectively, represent amounts for the site assessment and remediation of MGPs.  WMECO currently has three MGP sites included in its environmental liability.  Of the three MGP sites, one is currently undergoing remediation efforts with the other two MGP sites in the site assessment stage.

On January 19, 2005, the DPUC issued a final decision approving the sale proceeding of a former MGP site that was held for sale at December 31, 2004.  The final decision approved the price of $24 million for the sale of the land and also approved the deferral of the gain in the amount of $14 million ($8.4 million net of tax) of which $0.1 million was attributable to WMECO.  During 2005, the former MGP site was sold to an independent third party.

CERCLA Matters:  The Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA) and its’ amendments or state equivalents impose joint and several strict liabilities, regardless of fault, upon generators of hazardous substances resulting in removal and remediation costs and environmental damages.  Liabilities under these laws can be material and in some instances may be imposed without regard to fault or for past acts that may have been lawful at the time they occurred.  WMECO has one superfund site under CERCLA for which it has been notified that it is a potentially responsible party (PRP).  For sites where there are other PRPs and WMECO is not managing the site assessment and remediation, the liability accrued represents WMECO's estimate of what it will pay to settle its obligations with respect to the site.

It is possible that new information or future developments could require a reassessment of the potential exposure to related environmental matters.  As this information becomes available management will continue to assess the potential exposure and adjust the reserves accordingly.  

Rate Recovery:  WMECO does not have a regulatory mechanism to recover environmental costs from its customers, and changes in WMECO's environmental reserves impact WMECO's earnings.

C.

Spent Nuclear Fuel Disposal Costs

Under the Nuclear Waste Policy Act of 1982 (the Act), WMECO must pay the United States 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, 2005 and 2004, fees due to the DOE for the disposal of Prior Period Fuel were $50.9 million and $49.3 million, respectively, including interest costs of $35.3 million and $33.7 million, respectively.  At December 31, 200 5, an additional $0.2 million has been included for additional non-DOE fees incurred to date.  

During 2004, WMECO established a trust, which holds marketable securities to fund amounts due to the DOE for the disposal of WMECO's prior period fuel.  For further information on this trust, see Note 6, "Marketable Securities," to the consolidated financial statements.

D.

Long-Term Contractual Arrangements

Vermont Yankee Nuclear Power Corporation (VYNPC):  Previously under the terms of its agreement, WMECO paid its ownership (or entitlement) shares of costs, which included depreciation, O&M expenses, taxes, the estimated cost of decommissioning, and a return on invested capital to VYNPC and recorded these costs as purchased-power expenses.  On July 31, 2002, VYNPC consummated the sale of its nuclear generating unit to a subsidiary of Entergy Corporation for approximately $180 million.  WMECO has a commitment to buy approximately 2.5 percent of the plant's output through March of 2012 at a range of fixed prices.  The total cost of purchases under contracts with VYNPC amounted to $4 million in 2005, $4.2 million in 2004, and $4.6 million in 2003.  

Electricity Procurement Contracts:  WMECO has entered into various arrangements for the purchase of electricity.  The total cost of purchases under these arrangements amounted to $2 million in 2005, $2.2 million in 2004 and $2.8 million in 2003.  These amounts relate to IPP contracts and do not include contractual commitments related to WMECO's basic 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.  The total cost of this agreement amounted to $2.5 million in 2005, $2.7 million in 2004 and $2.9 million in 2003.

Yankee Companies FERC-Approved Billings, Subject to Refund:  WMECO has significant decommissioning and plant closure cost obligations to the Yankee Companies.  Each plant has been shut down and is undergoing decommissioning.  The Yankee Companies collect decommissioning and closure costs through wholesale, FERC-approved rates charged under power purchase agreements with several New England utilities, including WMECO.  WMECO in turn passes these costs on to its customers through DTE-approved retail rates.  YAEC and MYAPC received FERC approval to collect all presently estimated decommissioning and closure costs.  On November 23, 2005, YAEC submitted an application to the FERC to increase YAEC's wholesale decommissioning charges.  On January 31, 2006, the FERC issued an order accepting the rate increase, effective February 1, 2006, subject to refund after hearings and settlement judge proceedings.  CYAPC received an order on August 30, 2004 from the FERC allowing collection of its decommissioning and closure costs, subject to refund.  The table of estimated future annual costs below includes the estimated decommissioning and closure costs for YAEC, MYAPC and CYAPC.

24

Estimated Future Annual Costs:  The estimated future annual costs of WMECO’s significant long-term contractual arrangements are as follows:

(Millions of Dollars)	2006	2007	2008	2009	2010	Thereafter
VYNPC	$ 4.5	$ 4.3	$ 4.3	$ 4.7	$ 4.6	$ 5.8
Electricity procurement   contracts	2.3	2.3	2.3	2.3	2.3	-
Hydro-Quebec	2.7	2.6	2.6	2.5	2.5	25.2
Yankee Companies   FERC-approved billings,  subject to refund	17.6	14.0	12.1	11.5	11.4	- -
Totals	$27.1	$23.2	$21.3	$21.0	$20.8	$31.0

E.

Deferred Contractual Obligations

FERC Proceedings:  In 2003, CYAPC increased the estimated decommissioning and plant closure costs for the period 2000 through 2023 by approximately $395 million over the April 2000 estimate of $436 million approved by the FERC in a 2000 rate case settlement.  The revised estimate reflects the increases in the projected costs of spent fuel storage, increased security and liability and property insurance costs, and the fact that CYAPC is now self performing all work to complete the decommissioning of the plant due to the termination of the decommissioning contract with Bechtel Power Corporation (Bechtel) in July of 2003.  WMECO's share of CYAPC's increase in decommissioning and plant closure costs is approximately $38 million.  On July 1, 2004, CYAPC filed with the FERC for recovery seeking to increase its annual decommissioning collections from $16.7 million to $93 million for a six-year perio d beginning on January 1, 2005.  On August 30, 2004, the FERC issued an order accepting the rates, with collection beginning on February 1, 2005, subject to refund.

Both the Connecticut Department of Public Utility Control (DPUC) and Bechtel filed testimony in the FERC proceeding claiming that CYAPC was imprudent in its management of the decommissioning project.  In its testimony, the DPUC recommended a disallowance of $225 million to $234 million out of CYAPC's requested rate increase of approximately $395 million.  WMECO's share of the DPUC's recommended disallowance would be between $21 million to $22 million.  The FERC staff also filed testimony that recommended a $38 million decrease in the requested rate increase claiming that CYAPC should have used a different gross domestic product (GDP) escalator.  WMECO's share of this recommended decrease is $3.6 million.  

On November 22, 2005, a FERC administrative law judge (ALJ) issued an initial decision finding no imprudence on CYAPC's part.  However, the ALJ did agree with the FERC staff’s position that a lower GDP escalator should be used for calculating the rate increase and found that CYAPC should recalculate its decommissioning charges to reflect the lower escalator.  Briefs to the full FERC addressing these issues were filed in January and February of 2006, and a final order is expected later in 2006.  Management expects that if the FERC staff's position on the decommissioning GDP cost escalator is found by the FERC to be more appropriate than that used by CYAPC to develop its proposed rates, then CYAPC would review whether to reduce its estimated decommissioning obligation and reduce the customers' obligation, including WMECO.  

The company cannot at this time predict the timing or outcome of the FERC proceeding required for the collection of the increased CYAPC decommissioning costs.  The company believes that the costs have been prudently incurred and will ultimately be recovered from the customers of WMECO.  However, there is a risk that some portion of these increased costs may not be recovered, or will have to be refunded if recovered, as a result of the FERC proceedings.  

On June 10, 2004, the DPUC and the Connecticut Office of Consumer Counsel (OCC) filed a petition seeking a declaratory order that CYAPC be allowed to recover all decommissioning costs from its wholesale purchasers, including WMECO, but that such purchasers may not be allowed to recover in their retail rates any costs that the FERC might determine to have been imprudently incurred.  On August 30, 2004, the FERC denied this petition.  On September 29, 2004, the DPUC and OCC asked the FERC to reconsider the petition and on October 20, 2005, the FERC denied the reconsideration, holding that the sponsor companies are only obligated to pay CYAPC for prudently incurred decommissioning costs and the FERC has no jurisdiction over the sponsors' rates to their retail customers.  On December 12, 2005, the DPUC sought review of these orders by the United States Court of Appeals for the D.C. Circuit.  The FERC and CYAPC have asked the court to dism iss the case and the DPUC has objected to the dismissal.  WMECO cannot predict the timing or the outcome of these proceedings.  

Bechtel Litigation:  CYAPC and Bechtel commenced litigation in Connecticut Superior Court over CYAPC's termination of Bechtel's contract for the decommissioning of CYAPC's nuclear generating plant.  After CYAPC terminated the contract, responsibility for decommissioning was transitioned to CYAPC, which recommenced the decommissioning process.

On March 7, 2006, CYAPC and Bechtel executed a settlement agreement terminating this litigation.  Bechtel has agreed to pay CYAPC $15 million, and CYAPC will withdraw its termination of the contract for default and deem it terminated by agreement.

Spent Nuclear Fuel Litigation:  CYAPC, YAEC and MYAPC also commenced litigation in 1998 charging that the federal government breached contracts it entered into with each company in 1983 under the Act.  Under the Act, the DOE was to begin removing spent nuclear fuel from the nuclear plants of the Yankee Companies no later than January 31, 1998 in return for payments by each company into the nuclear waste fund.  No fuel has been collected by the DOE, and spent nuclear fuel is stored on the sites of the Yankee Companies' plants.  The Yankee Companies collected the funds for payments into the nuclear waste fund from wholesale utility customers under FERC-approved contract rates.  The wholesale utility customers in turn collect these payments from their retail electric customers.  The Yankee Companies' individual damage claims attributed to the government's breach ranging between $523 million and $543 million are specific to each plant and include incremental storage, security, construction and other costs through 2010.  The CYAPC damage claim ranges from $186 million to $198 million, the YAEC damage claim ranges from $177 million to $185 million and the MYAPC damage claim is $160 million.  The DOE trial ended on August 31, 2004 and a verdict has not been reached.  Post-trial findings of facts and final briefs were filed by the parties in January of 2005.  The Yankee Companies' current rates do not include an amount for recovery of damages in this matter.  Management can predict neither the outcome of this matter nor its ultimate impact on WMECO.

YAEC:   In November of 2005, YAEC established an updated estimate of the cost of completing the decommissioning of its plant resulting in an increase of approximately $85 million.  WMECO's share of the increase in estimated costs is $6 million.  This estimate reflects the cost of completing site closure activities from October of 2005 forward and storing spent nuclear fuel and other high level waste on site until 2020.  This estimate projects a total cost of $192.1 million for the completion of decommissioning and long-term fuel storage.  To fund these costs, on November 23, 2005, YAEC submitted an application to the FERC to increase YAEC’s wholesale decommissioning charges.  The DPUC and the Massachusetts attorney general protested these increases.  On January 31, 2006, the FERC issued an order accepting the rate increase, effective February 1, 2006, subject to refund after hearings and settl ement judge proceedings.  The hearings have been suspended pending settlement discussions between YAEC, the FERC and other intervenors in the case.  WMECO has a 7 percent ownership interest in YAEC and can predict neither the outcome of this matter nor its ultimate impact on WMECO.

5.  Fair Value of Financial Instruments  

The following methods and assumptions were used to estimate the fair value of each of the following financial instruments:

Prior Spent Nuclear Fuel Trust:  During 2004, WMECO established a trust to fund the amounts due to the DOE for its prior spent nuclear fuel obligation.  These investments having a cost basis of $51.1 million and $49.5 million for 2005 and 2004, respectively, were recorded at their fair market value of $50.8 million and $49.3 million at December 31, 2005 and 2004, respectively.  For further information regarding these investments, see Note 6, "Marketable Securities," to the consolidated financial statements.

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, 2005
(Millions of Dollars)	Carrying Amount	Fair Value
Long-term debt -
Other long-term debt	$259.9	$259.3
Rate reduction bonds	111.3	117.8

	At December 31, 2004
(Millions of Dollars)	Carrying Amount	Fair Value
Long-term debt -
Other long-term debt	$208.1	$211.7
Rate reduction bonds	122.5	134.3

Other long-term debt includes $51.1 million and $49.3 million of fees and interest due for spent nuclear fuel disposal costs at December 31, 2005 and 2004, respectively.

Other Financial Instruments:  The carrying value of financial instruments included in current assets and current liabilities approximates their fair value.

6.  Marketable Securities  

The following is a summary of WMECO's prior spent nuclear fuel trust, which are recorded at their fair market values and are included in current and long-term marketable securities on the accompanying consolidated balance sheets.  Changes in the fair value of these securities are recorded as unrealized gains and losses in accumulated other comprehensive income.   Not included in the amounts below are SERP securities totaling $0.5 million at December 31, 2005 and 2004, which are included in current and long-term marketable securities on the accompanying consolidated balance sheets.  

	At December 31,
(Millions of Dollars)	2005	2004
WMECO prior spent nuclear fuel trust	$50.8	$49.3

25

At December 31, 2005 and 2004, these marketable securities are comprised of the following:  

(Millions of Dollars) At December 31, 2005	Amortized Cost	Pre-Tax Gross Unrealized Gains	Pre-Tax Gross Unrealized Losses	Estimated Fair Value
Fixed income securities	$51.1	$0.1	$(0.4)	$50.8

(Millions of Dollars) At December 31, 2004	Amortized Cost	Pre-Tax Gross Unrealized Gains	Pre-Tax Gross Unrealized Losses	Estimated Fair Value
Fixed income securities	$49.5	$    -	$(0.2)	$49.3

At December 31, 2005 and 2004, WMECO evaluated the securities in an unrealized loss position and has determined that none of the related unrealized losses are deemed to be other-than-temporary in nature.  At December 31, 2005 and 2004, the gross unrealized losses and fair value of WMECO's investments that have been in a continuous unrealized loss position for less than 12 months and 12 months or greater were as follows:

	Less than 12 Months		12 Months or Greater		Total
(Millions of Dollars) At December 31, 2005	Estimated Fair Value	Pre-Tax Gross Unrealized Losses	Estimated Fair Value	Pre-Tax Gross Unrealized Losses	Estimated Fair Value	Pre-Tax Gross Unrealized Losses
Fixed income   securities	$20.8	$(0.3)	$3.3	$(0.1)	$24.1	$(0.4)

	Less than 12 Months		12 Months or Greater		Total
(Millions of Dollars) At December 31, 2004	Estimated Fair Value	Pre-Tax Gross Unrealized Losses	Estimated Fair Value	Pre-Tax Gross Unrealized Losses	Estimated Fair Value	Pre-Tax Gross Unrealized Losses
Fixed income   securities	$30.1	$(0.2)	$ -	$ -	$30.1	$(0.2)

For information related to the change in net unrealized holding gains and losses included in shareholders' equity, see Note 9, "Accumulated Other Comprehensive Income/(Loss)," to the consolidated financial statements.

WMECO utilizes the average cost basis method for the WMECO spent nuclear fuel trust to compute the realized gains and losses on the sale of available-for-sale securities.  For the year ended December 31, 2005, WMECO recognized $0.4 million in realized losses relating to the sale of available-for-sale securities.  There were no realized gains recorded in 2005.  For the year ended December 31, 2005, realized losses of $0.4 million are included in fuel, purchased and net interchange power on the accompanying consolidated statements of income.  There were no realized gains or losses relating to the WMECO spent nuclear fuel trust in 2004 or 2003.  WMECO utilizes the average cost basis method for the prior spent nuclear fuel trust to compute the realized gains and losses on the sale of available-for-sale securities.  

Proceeds from the sale of these securities totaled $82.9 million and $55.2 million for the years ended December 31, 2005 and 2004, respectively.

At December 31, 2005, the contractual maturities of the available-for-sale securities are as follows:

(Millions of Dollars)	Amortized Cost	Estimated Fair Value
Less than one year	$20.8	$20.6
One to five years	19.5	19.4
Six to ten years	-	-
Greater than ten years	10.8	10.8
Total	$51.1	$50.8

Amounts above exclude an additional $0.3 million and $0.2 million of SERP securities that are classified as less than one year and one to five years, respectively, and are included on the accompanying consolidated balance sheet at December 31, 2005.

For further information regarding marketable securities, see Note 1O, "Summary of Significant Accounting Policies - Marketable Securities" to the consolidated financial statements.

7.  Leases  

WMECO has entered into lease agreements for the use of data processing and office equipment, vehicles, and office space.  The provisions of these lease agreements generally provide for renewal options.  Certain lease agreements contain contingent lease payments.  The contingent lease payments are based on various factors, such as the commercial paper rate plus a credit spread or the consumer price index.

There were no capital leases, or interest related to these payments, charged to operating expense in 2005, 2004 and 2003.  Operating lease rental payments charged to expense were $3.6 million in 2005, $3.5 million in 2004, and $3.1 million in 2003.  The capitalized portion of operating lease payments was approximately $1.1 million, $0.9 million and $1 million for the years ended 2005, 2004 and 2003, respectively.

Future minimum rental payments excluding executory costs, such as property taxes, state use taxes, insurance, and maintenance, under long-term noncancelable operating leases, at December 31, 2005 are as follows:

(Millions of Dollars)	Operating Leases
2006	$ 5.2
2007	4.9
2008	4.5
2009	3.8
2010	3.4
Thereafter	10.1
Future minimum lease payments	$31.9

8.  Dividend Restrictions

The Federal Power Act and certain state statutes limit the payment of dividends by WMECO to its retained earnings balance.  At December 31, 2005, retained earnings available for payment of dividends is restricted to $85 million.

9.  Accumulated Other Comprehensive Income/(Loss)  

The accumulated balance for each other comprehensive income/(loss) item is as follows:

(Millions of Dollars)	December 31, 2004	Current Period Change	December 31, 2005
Qualified cash flow    hedging instruments	$      -	$  1.0	$  1.0
Unrealized losses     on securities	-	(0.2)	(0.2)
Minimum supplemental  executive retirement  pension liability   adjustments	(0.1)	-	(0.1)
Accumulated other   comprehensive   (loss)/income	$(0.1)	$ 0.8	$ 0.7

(Millions of Dollars)	December 31, 2003	Current Period Change	December 31, 2004
Minimum supplemental  executive retirement  pension liability   adjustments	$(0.1)	$ -	$(0.1)
Accumulated other   comprehensive loss	$(0.1)	$ -	$(0.1)

The changes in the components of other comprehensive loss are reported net of the following income tax effects:

(Millions of Dollars)	2005	2004	2003
Qualified cash flow   hedging instruments	$(0.6)	$   -	$   -
Unrealized losses      on securities	0.2	-	-
Minimum supplemental  executive retirement  pension liability  adjustments	-	-	-
Accumulated other   comprehensive loss	$(0.4)	$  -	$   -

The qualified cash flow hedge activity relates to an interest rate lock hedge entered into by WMECO in 2005 as a result of the decision to sell senior notes.

10. Long-Term Debt 

Details of long-term debt outstanding are as follows:

At December 31,	2005	2004
	(Millions of Dollars)
Pollution Control Notes:
Tax Exempt 1993 Series A,     5.85% due 2028	$53.8	$53.8
Other:
Taxable Senior Series A,     5.00% due 2013	55.0	55.0
Taxable Senior Series B,     5.90% due 2034	50.0	50.0
Taxable Senior Series C,     5.24% due 2015	50.0	-
Total Pollution Control Notes   and Other	208.8	158.8
Fees and interest due for spent nuclear fuel  disposal costs	51.1	49.3
Total pollution control notes and fees   and interest for spent nuclear fuel   disposal costs	259.9	208.1
Less amounts due within one year	-	-
Unamortized premium and discount, net	(0.4)	(0.4)
Long-term debt	$259.5	$207.7

There are no cash sinking fund requirements or debt maturities for the years 2006 through 2010.

On August 11, 2005, WMECO closed the sale of $50 million 10-year senior notes with an interest rate of 5.24 percent.  Proceeds from this issuance were used to repay short-term borrowings used to finance capital expenditures.

For information regarding fees and interest due for spent nuclear fuel disposal costs, see Note 4C, "Commitments and Contingencies - Spent Nuclear Fuel Disposal Costs," to the consolidated financial statements.

11. Segment Information

Segment information related to the distribution and transmission business for WMECO for the years ended December 31, 2005, 2004 and 2003 is as follows (millions of dollars):

	For the Year Ended December 31, 2005
	Distribution	Transmission	Totals
Operating revenues	$391.1	$18.3	$409.4
Depreciation and   amortization	(22.0)	(2.0)	(24.0)
Other operating expenses	(335.6)	(9.3)	(344.9)
Operating income	33.5	7.0	40.5
Interest expense,   net of AFUDC	(17.0)	(1.1)	(18.1)
Interest income	0.4	-	0.4
Other income, net	1.4	0.2	1.6
Income tax expense	(7.2)	(2.1)	(9.3)
Net income	$  11.1	$  4.0	$  15.1
Total assets (1)	$946.0	$      -	$946.0
Cash flows for total   investments in plant	$  32.4	$12.3	$  44.7

26

	For the Year Ended December 31, 2004
	Distribution	Transmission	Totals
Operating revenues	$363.5	$15.7	$379.2
Depreciation and   amortization	(39.2)	(1.8)	(41.0)
Other operating expenses	(295.7)	(7.5)	(303.2)
Operating income	28.6	6.4	35.0
Interest expense,   net of AFUDC	(14.4)	(1.4)	(15.8)
Interest income	0.4	-	0.4
Other income, net	-	-	-
Income tax expense	(5.2)	(2.0)	(7.2)
Net income	$    9.4	$3.0	$  12.4
Total assets (1)	$922.5	-	$922.5
Cash flows for total   investments in plant	$  33.0	$6.3	$ 39.3

	For the Year Ended December 31, 2003
	Distribution	Transmission	Totals
Operating revenues	$376.0	$15.2	$391.2
Depreciation and   amortization	(65.7)	(1.8)	(67.5)
Other operating expenses	(279.8)	(6.3)	(286.1)
Operating income	30.5	7.1	37.6
Interest expense,   net of AFUDC	(13.3)	(0.5)	(13.8)
Interest income	1.6	-	1.6
Other income/(loss), net	2.6	(0.1)	2.5
Income tax expense	(9.0)	(2.7)	(11.7)
Net income	$  12.4	$ 3.8	$  16.2
Cash flows for total   investments in plant	$  28.2	$ 4.4	$  32.6

(1)

Information for segmenting total assets between distribution and transmission is not available at December 31, 2005 or 2004.  These distribution and transmission assets are disclosed in the distribution columns above.

27

Consolidated Quarterly Financial Data (Unaudited)
	Quarter Ended (a) (b)
(Thousands of Dollars)	March 31,	June 30,	September 30,	December 31,
2005
Operating Revenues	$104,335	$93,317	$104,611	$107,130
Operating Income	$  12,833	$  8,461	$  12,193	$    7,052
Net Income	$    4,727	$  2,368	$    4,857	$    3,133
2004
Operating Revenues	$97,922	$92,056	$94,238	$95,013
Operating Income	$  9,911	$10,398	$  5,918	$  8,726
Net Income	$  3,546	$  3,580	$  1,537	$  3,710

Selected Consolidated Financial Data (Unaudited)
(Thousands of Dollars)	2005	2004	2003	2002	2001
Operating Revenues	$409,393	$379,229	$391,178	$369,487	$478,869
Net Income	15,085	12,373	16,212	37,682	14,968
Cash Dividends on Common Stock	7,685	6,485	22,011	16,009	22,000
Net Property, Plant and Equipment (c)	499,317	468,884	447,771	406,209	396,399
Total Assets (d)	945,996	922,472	872,077	853,646	852,662
Rate Reduction Bonds	111,331	122,489	132,960	142,742	152,317
Long-Term Debt (e)	259,487	207,684	157,202	101,991	101,170
Obligations Under Capital Leases (e)	-	-	57	87	110

(a)

Certain reclassifications of prior years' data have been made to conform with the current year's presentation.

(b)

Quarterly operating income amounts differ from those previously reported as a result of the change in classification of certain costs that were not recoverable from regulated customers.  These amounts, previously presented in other income, net, have been reclassified to other operation expenses and are summarized as follows (thousands of dollars):  

	2005	2004
March 31,	$  37	$136
June 30,	158	171
September 30,	157	238

(c)

Amount includes CWIP.

(d)

Total assets were not adjusted for cost of removal prior to 2002.

(e)

Includes portions due within one year.

28

Consolidated Statistics (Unaudited)
	2005	2004	2003	2002	2001
Revenues:  (Thousands)
Residential	$190,023	$167,275	$165,871	$158,060	$174,899
Commercial	133,356	128,425	133,122	127,030	157,722
Industrial	59,937	62,347	63,990	60,782	83,752
Wholesale - Other Utilities	19,064	8,646	14,347	9,354	38,893
Streetlighting and Railroads	5,030	4,782	4,817	5,071	5,306
Miscellaneous	1,983	7,754	9,031	9,190	18,297
Total	$409,393	$379,229	$391,178	$369,487	$478,869
Sales:  (kWh - Millions)
Residential	1,596	1,546	1,521	1,459	1,389
Commercial	1,616	1,583	1,567	1,523	1,495
Industrial	910	935	909	912	940
Wholesale - Other Utilities	176	169	255	180	864
Streetlighting and Railroads	25	25	26	28	24
Total	4,323	4,258	4,278	4,102	4,712
Customers:  (Average)
Residential	186,882	185,083	185,202	183,662	182,688
Commercial	19,174	18,917	18,838	18,516	15,996
Industrial	894	892	897	910	808
Other	714	695	693	672	674
Total	207,664	205,587	205,630	203,760	200,166
Average Annual Use Per Residential Customer (kWh)	8,539	8,353	8,214	7,921	7,476
Average Annual Bill Per Residential Customer	$1,016.82	$903.79	$895.33	$857.84	$941.23
Average Revenue Per kWh:
Residential	11.91¢	10.82¢	10.90¢	10.83¢	12.59¢
Commercial	8.25	8.10	8.50	8.34	10.55
Industrial	6.59	6.67	7.04	6.66	8.91

29

EX-13.3

Exhibit 13.3

Management’s Discussion and Analysis

Financial Condition and Business Analysis

Executive Summary

The following items in this executive summary are explained in more detail in this annual report.

Results:

·

Public Service Company of New Hampshire (PSNH or the company) reported earnings of $41.7 million in 2005 compared with earnings of $46.6 million in 2004 and $45.6 million in 2003.  Included in earnings were transmission earnings of $7.8 million, $6.7 million and $7.3 million in 2005, 2004 and 2003, respectively, and distribution earnings of $33.9 million, $39.9 million and $38.3 million in 2005, 2004 and 2003, respectively.

Legislative Items:

·

On August 8, 2005, President Bush signed into law comprehensive federal energy legislation with several provisions affecting PSNH.  As part of this legislation, the Public Utility Holding Company Act of 1935 (PUHCA) was repealed.  Some but not all of the Securities and Exchange Commission's (SEC) responsibilities under PUHCA were transferred to the Federal Energy Regulatory Commission (FERC).  

·

The Regional Greenhouse Gas Initiative (RGGI) agreement, signed on December 20, 2005, is a cooperative effort by certain northeastern states to develop a regional program for stabilizing current levels and reducing carbon dioxide (CO2) emissions by ten percent by 2020 from fossil-fired electric generators.  RGGI may impact PSNH’s Merrimack, Newington and Schiller stations.  At this time, the impact of this agreement on PSNH cannot be determined.

·

In November of 2005, PSNH and various legislative, state government and environmental leaders announced that they had reached a consensus to propose legislation to reduce the level of mercury emissions from PSNH’s coal-fired plants by 2013 with incentives for early reductions.  As part of the proposed legislation, PSNH's primary long-term alternative to comply with the proposed legislation would be to install wet scrubber technology at its two Merrimack coal units, which combined generate 433 MW, at a cost of approximately $250 million.  The proposed legislation is being considered during the 2006 legislative session.

Regulatory Items:

·

PSNH has received regulatory approval to recover the increased cost of energy being supplied to its customers in 2006.  This increased cost is primarily the result of increased fuel and purchased power costs.

·

PSNH’s 2004 stranded cost recovery charge (SCRC) reconciliation filing was filed with the New Hampshire Public Utilities Commission (NHPUC) on May 2, 2005.  In October of 2005, PSNH, the NHPUC staff and the New Hampshire Office of Consumer Advocate (OCA) reached a settlement agreement in this case.  This settlement agreement was approved by the NHPUC on December 22, 2005.  That settlement agreement also recommended that the NHPUC staff engage a coal procurement expert to analyze PSNH’s coal procurement and transportation operations.  Consistent with the settlement agreement, the NHPUC deferred action on coal-related costs until that analysis has been completed.

·

On December 2, 2005, the NHPUC issued an order to rehear the order that lowered the return on equity (ROE) on PSNH’s generating facilities to 9.62 percent from 11 percent effective August 1, 2005.  On January 3, 2006, PSNH appealed the revised decision to the New Hampshire Supreme Court and simultaneously asked the NHPUC for reconsideration of its decision.  The appeal before the New Hampshire Supreme Court is pending.  On February 10, 2006, PSNH's most recent request for reconsideration by the NHPUC was denied.

·

On March 6, 2006, the New England Independent System Operator (ISO-NE) and a broad cross-section of critical stakeholders from around the region, including PSNH, filed a comprehensive settlement agreement at the FERC implementing a Forward Capacity Market (FCM) in place of Locational Installed Capacity (LICAP).  The settlement agreement must be approved by the FERC, and the parties have asked for a decision by June 30, 2006.

Liquidity:

·

On October 5, 2005, PSNH issued $50 million of 30-year first mortgage bonds.  

·

In 2005, PSNH’s capital expenditures totaled $158.8 million compared with $153.2 million in 2004 and $105.1 million in 2003.  The increased level of capital expenditures was caused primarily by higher distribution and generation capital expenditures.

·

Cash flows from operations decreased by $47.5 million to $155.3 million in 2005 from $202.8 million in 2004.

Overview

PSNH is a wholly owned subsidiary of Northeast Utilities (NU).  NU’s other regulated electric subsidiaries include The Connecticut Light and Power Company (CL&P) and Western Massachusetts Electric Company (WMECO).  

PSNH earned $41.7 million in 2005, compared with $46.6 million in 2004 and $45.6 million in 2003.  Included in earnings were transmission earnings of $7.8 million, $6.7 million and $7.3 million in 2005, 2004 and 2003, respectively, and distribution earnings of $33.9 million, $39.9 million and $38.3 million in 2005, 2004 and 2003, respectively.  PSNH's distribution and generation earnings in 2005 were lower primarily due to a lower ROE on the generation facilities in 2005 and higher interest and operating expenses, partially offset by delivery rate increases of $3.5 million in October of 2004 and $10 million in June of 2005.  

PSNH's retail electric sales were positively impacted by weather in 2005, particularly by an unseasonably hotter than average third quarter of 2005, which increased electricity consumption.  Retail electric sales increased 1.9 percent over 2004; however, on a weather adjusted basis, retail electric sales decreased 0.2 percent.

With a commodity-driven rate increase taking effect early in 2006 and the weather being much milder to date in 2006, management is concerned that actual sales could be lower in 2006 than in 2005.  While sales volume does not affect transmission business earnings positively or negatively, lower electric sales do negatively affect distribution company earnings.

Liquidity

Cash flows from operations decreased by $47.5 million to $155.3 million in 2005 from $202.8 million in 2004.  The decrease in cash flows is primarily due to an increase in regulatory refunds, higher tax payments, payments made relating to the emissions allowance program and a decrease in accounts payable related to an intercompany billing and construction costs.  

Cash flows from operations increased by $119.9 million from $82.9 million in 2003 to $202.8 million in 2004.  The increase in cash flows from operations was primarily the result of an increase in amortization of regulatory assets and lower income taxes paid in 2004 than 2003.

On October 5, 2005, PSNH issued $50 million of 30-year first mortgage bonds with an interest rate of 5.60 percent, the proceeds from which were used to repay short-term borrowings used to finance capital expenditures.  

On December 9, 2005, PSNH amended its 5-year unsecured revolving credit facility by extending the termination date by one year to November 6, 2010.  The company can borrow up to $100 million on a short-term basis, or subject to regulatory approvals, on a long-term basis.  At December 31, 2005, there were no borrowings outstanding under this facility.  At December 31, 2004, PSNH had $10 million in borrowings under this credit facility.

PSNH's senior secured debt is rated A3, BBB and BBB+ with a stable outlook by Moody's Investors Service (Moody's), Standard and Poor's (S&P) and Fitch Ratings, respectively.  

In 2005, PSNH paid approximately $42.4 million to NU in the form of common dividends.

Capital expenditures described herein are cash capital expenditures and exclude cost of removal, allowance for funds used during construction (AFUDC) and the capitalized portion of pension income.  PSNH’s capital expenditures totaled $158.8 million in 2005, compared with $153.2 million in 2004 and $105.1 million in 2003.  The increase in PSNH's capital expenditures was primarily the result of higher distribution and generation capital expenditures, which totaled $131.9 million in 2005 compared with $123.1 million in 2004 and $78.2 million in 2003.  

Business Development and Capital Expenditures

In 2005, PSNH’s capital expenditures totaled $158.8 million compared with $153.2 million in 2004, and $105.1 million in 2003.  PSNH's distribution and generation capital expenditures totaled $131.9 million in 2005, compared with $123.1 million and $78.2 million in 2004 and 2003, respectively.  Total capital expenditures include $45 million related to the conversion of a 50 MW coal-fired unit at Schiller Station in Portsmouth, New Hampshire to burn wood (Northern Wood Power Project).  The Northern Wood Power Project began in late 2004 and is expected to achieve commercial generation in the second half of 2006.  The NHPUC's 2004 approval of the project was appealed to the New Hampshire Supreme Court by some of New Hampshire's existing wood-fired generating plant owners.  The Supreme Court upheld the NHPUC's finding that the project is in the public interest and, as a result, the project was able to proceed in accordance with the original schedule.  This project is approximately 90 percent complete and PSNH has capitalized $64.7 million related to this project at December 31, 2005.

In 2005, PSNH also spent $26.9 million on upgrading and expanding its electric transmission system.    

PSNH currently forecasts distribution and generation expenditures of approximately $500 million from 2006 through 2010.  In addition, approximately $250 million of transmission projects is currently forecasted from 2006 to 2010, totaling approximately $750 million in total capital projects.  PSNH estimates total annual capital expenditures of approximately $150 million from 2006 through 2010.

Transmission Access and FERC Regulatory Changes

In January of 2005, the New England transmission owners approved activation of the New England Regional Transmission Organization (RTO) which occurred on February 1, 2005.  PSNH is now a member of the New England RTO and provides regional open access transmission service over its transmission system under the New England Independent System Operator (ISO-NE) Transmission, Markets and Services Tariff, FERC Electric

Tariff No. 3 and local open access transmission service under the ISO-NE Transmission, Markets and Services Tariff, FERC Electric No. 3, Schedule 21 - NU.  

As a result of the RTO start-up on February 1, 2005, the ROE in the local network service (LNS) tariff was increased to 12.8 percent.  The ROE being utilized in the calculation of the current regional network service (RNS) rates is the sum of the 12.8 percent "base" ROE, plus a 50 basis point incentive adder for joining the RTO, or a total of 13.3 percent.  An initial decision by a FERC administrative law judge (ALJ) has set the base ROE at 10.72 percent as compared with the 12.8 percent requested by the New England RTO.  One of the adjustments made by the ALJ was to modify the underlying proxy group used to determine the ROE, resulting in a reduction in the base ROE of approximately 50 basis points.  The ALJ deferred to the FERC for final resolution on the 100 basis point incentive adder for new transmission investments but reaffirmed the 50 basis point incentive for joining the RTO.  The New England transmission owner s have challenged the ALJ’s findings and recommendations through written exceptions filed on June 27, 2005 and a final order from the FERC is expected in 2006.  The result of this order, if upheld by the FERC, would be an ROE for LNS of 10.72 percent and an ROE for RNS of 11.22 percent.  When blended, the resulting "all in" ROE would be approximately 11.15 percent for the NU transmission business.  Management cannot at this time predict what ROE will ultimately be established by the FERC in these proceedings but for purposes of current earnings accruals and estimates, the transmission business is assuming an ROE of 11.5 percent.

In November of 2005, the FERC announced that it was considering a number of proposals to provide financial incentives for the construction of high-voltage electric transmission in the United States.  Those proposals included reflecting in rate base 100 percent of the cost of construction work in progress (CWIP); accelerated recovery of depreciation; imputing hypothetical capital structures in ratemaking; establishing ROEs for transmission owners that join RTOs; and other incentives that could improve the earnings and/or cash flows associated with PSNH’s transmission capital expenditures.  Comments on the FERC proposals were submitted in January of 2006, and final rules are expected by the summer of 2006.  

Legislative Matters

Federal Energy Legislation:  On August 8, 2005, President Bush signed into law comprehensive energy legislation.  Among provisions potentially affecting PSNH are the repeal of PUHCA, FERC backstop siting authority for transmission, transmission pricing and rate reform, renewable production tax credits, and accelerated depreciation for certain new electric and gas facilities. The renewable production tax credits provision is expected to save PSNH approximately $3 million annually in federal income taxes for the first 10 years after the Northern Wood Power Project becomes operational.  The accelerated depreciation provision, assuming timely rate recovery, is expected to increase PSNH’s cash flows by more than $0.6 million annually.  As part of this legislation, some but not all of the SEC's responsibilities under PUHCA were transferred to the FERC.  

Environmental Legislation:  The RGGI is a cooperative effort by certain northeastern states to develop a regional program for stabilizing and ultimately reducing CO2 emissions from fossil-fired electric generators.  This initiative proposed to stabilize CO2 emissions at current levels and require a ten percent reduction by 2020.  The RGGI agreement was signed on December 20, 2005 by the states of Connecticut, Delaware, Maine, New Jersey, New Hampshire, New York, and Vermont.  Each state commits to propose for approval legislative and regulatory mechanisms to implement the program.  RGGI may impact PSNH’s Merrimack, Newington and Schiller stations.  At this time, the impact of this agreement on PSNH cannot be determined.  

The New Hampshire legislature is considering a bill in its 2006 legislative session that would place strict limitations on the level of mercury that PSNH’s existing generation plants can emit.  Legislation was first proposed in the 2005 session and passed by the New Hampshire senate in 2005 which would require PSNH to achieve fixed annual caps as early as 2009.  The bill was subsequently defeated by the New Hampshire House of Representatives early in 2006.  The legislature will now take up a new bill that requires PSNH to reduce power plant mercury emissions by at least 80 percent by 2013 while providing incentives for early reductions.  Management has been reviewing the proposed legislation.  PSNH’s primary long-term alternative is to install wet scrubber equipment at its Merrimack Station at a cost of approximately $250 million.  PSNH’s other alternatives include the use of carbon injection pollution control equipment, reducing operating capacity of its plants and possible retirement or repowering of one or more of its generating units.  While state law and PSNH's restructuring agreement provide for the recovery of its generation costs, including the cost to comply with state environmental regulations, at this time management is unable to determine the impact of any potential new legislation on PSNH's net income or financial position.

Regulatory Issues and Rate Matters

Transmission - Wholesale Rates:  Wholesale transmission revenues are based on rates and formulas that are approved by the FERC. Most of PSNH’s wholesale transmission revenues are collected through a combination of the RNS tariff and PSNH's LNS tariff.  PSNH's RNS rate is reset on June 1 of each year.  PSNH’s LNS rate is reset on January 1 and June 1 of each year.  On January 1, 2006, PSNH’s LNS rates increased PSNH's wholesale revenues by $3.2 million on an annualized basis.  The LNS and RNS rates to be effective on June 1, 2006 have not yet been determined.  Additionally, PSNH’s LNS tariff provides for a true-up to actual costs, which ensures that PSNH's transmission business recovers its total transmission revenue requirements, including the allowed ROE.  At December 31, 2005, this true-up resulted in the recognition of a $0.6 million regulatory liabi lity.  

Transmission - Retail Rates:  A significant portion of the PSNH transmission business revenue comes from the ISO-NE charges to the distribution business.  The distribution business recovers these costs through the retail rates that are charged to its retail customers.  PSNH does not currently have a retail transmission rate tracking mechanism.

LICAP:  In March of 2004, ISO-NE proposed at the FERC an administratively determined electric generation capacity pricing mechanism known as LICAP, intended to provide a revenue stream sufficient to maintain existing generation assets and encourage the construction of new generation assets at levels sufficient to serve peak load, plus fixed reserve and contingency margins.

After opposition from state regulators, utilities and various Congressional delegations, the FERC ordered settlement negotiations before an ALJ to determine whether there was an acceptable alternative to LICAP.  On March 6, 2006, ISO-NE and a broad cross-section of critical stakeholders from around the region, including PSNH, filed a comprehensive settlement agreement at the FERC implementing a FCM in place of LICAP.  The settlement agreement provides for a fixed level of compensation to generators from December 1, 2006 through May 31, 2010 without regard to location in New England, and annual forward capacity auctions, beginning in 2008, for the 1-year period ending on May 31, 2011, and annually thereafter.  The settlement agreement must be approved by the FERC, and the parties have asked for a decision by June 30, 2006.  According to preliminary estimates, FCM would require PSNH to pay approximately $80 mil lion during the 3½-year transition period.  PSNH will incur charges and would be able to recover these costs from its customers.  

ES Rates:  In accordance with the "Agreement to Settle PSNH Restructuring" and state law, PSNH files for updated Transition Energy Service Rate and Default Energy Service Rate, collectively referred to as Energy Service Rate (ES), periodically to ensure timely recovery of its costs.  The ES rate recovers PSNH's generation and purchased power costs, including a return on PSNH's generation assets.  PSNH defers for future recovery or refund any difference between its ES revenues and the actual costs incurred.  

On January 28, 2005, the NHPUC issued an order approving an ES rate of $0.0649 per kWh for the period February 1, 2005 through January 31, 2006 which included an 11 percent ROE on PSNH's generation assets.  This generation ROE was the subject of a second set of proceedings.  On June 8, 2005, the NHPUC issued an order requiring PSNH to use a generation ROE of 9.63 percent, effective July 1, 2005.  On July 7, 2005, PSNH filed a motion for reconsideration in the ROE portion of the above docket.  On December 2, 2005 the NHPUC issued a revised decision, lowering PSNH’s allowed ROE to 9.62 percent that was retroactive to an effective date of August 1, 2005.  On January 3, 2006, PSNH appealed the revised decision to the New Hampshire Supreme Court and simultaneously asked the NHPUC for reconsideration of its decision.  The appeal before the New Hampshire Supreme Court is pending.  On February 10, 2006, PSNH's most recent request for reconsideration by the NHPUC was denied.  This decrease in allowed ROE will lower PSNH's net income by approximately $1.5 million annually based on the current level of generation asset investment.  

On July 1, 2005, PSNH filed a petition with the NHPUC requesting an increase in the ES rate from the then current $0.0649 per kWh to $0.0734 per kWh based on actual costs and underrecoveries incurred through June 30, 2005 and updated cost projections.  The updated cost projections included an increase in costs as a direct result of higher fuel and purchased power costs that PSNH expected to incur.  The generation ROE used in the updated cost projections was based upon the 9.63 percent ROE ordered on June 8, 2005.  An order changing the ES rate to $0.0724 per kWh, effective August 1, 2005, was issued by the NHPUC on August 1, 2005.

On September 30, 2005, PSNH filed a petition with the NHPUC requesting a change in ES rates for the period February 1, 2006 through January 31, 2007.  On December 14, 2005, PSNH and other parties, including the NHPUC staff and the OCA, filed a stipulation and settlement agreement related to the September 30, 2005 filing.  A provision of the settlement agreement included an allowance to implement deferred accounting treatment for asset retirement obligations (AROs) that PSNH is required to recognize under generally accepted accounting principles, including the future amortization of these ARO deferrals.

On December 19, 2005, PSNH filed updated ES cost information and requested approval of an ES rate of $0.0913 per kWh for the 11-month period from February 1, 2006 through December 31, 2006.  Hearings regarding the settlement agreement and the updated ES rate were held on December 21, 2005 and the NHPUC issued an order on January 20, 2006 approving the settlement agreement, as filed, and the ES rate of $0.0913 per kWh for the 11-month period.

SCRC Reconciliation Filing:  The SCRC allows PSNH to recover its stranded costs.  On an annual basis, PSNH files with the NHPUC a SCRC reconciliation filing for the preceding calendar year.  This filing includes the reconciliation of stranded cost revenues and costs and ES revenues and costs.  The NHPUC reviews the filing, including a prudence review of the operations within PSNH‘s generation business segment.  The cumulative deferral of SCRC revenues in excess of costs was $303.3 million at December 31, 2005.  This cumulative deferral will decrease the amount of non-securitized stranded costs to be recovered from PSNH's customers in the future from $368 million to $64.7 million.

The 2004 SCRC reconciliation filing was filed with the NHPUC on May 2, 2005.  In October of 2005, PSNH, the NHPUC staff and the OCA reached a settlement agreement in this case.  The major provisions of this settlement agreement include the following:  1) PSNH will be allowed to recover its 2004 ES costs and stranded costs without disallowances, 2) PSNH will be allowed to include its cumulative unbilled revenues in its ES and stranded cost reconciliations and 3) the NHPUC will defer any action regarding PSNH’s coal supply and transportation procedures until it completes a review using an outside expert.  The NHPUC issued its order on December 22, 2005, approving the settlement agreement as filed.  While management believes its coal procurement and transportation policies and procedures are prudent and consistent with industry practice, it is unable to determine the impact, if any, of the expected NHPUC review on PSNH's n et income or financial position.

Litigation with Independent Power Producers (IPPs):  Two wood-fired IPPs that sell their output to PSNH under long-term rate orders issued by the NHPUC brought suit against PSNH in state superior court.  The IPPs and PSNH dispute the end dates of the above-market long-term rates set forth in the respective rate orders.  Subsequent to the IPP's court filing, PSNH petitioned the NHPUC to decide this matter, and requested that the court stay its proceeding pending the NHPUC's decision.  By court order dated October 20, 2005, the court granted PSNH's motion to stay indicating that the NHPUC had primary jurisdiction over this matter.  

On November 11, 2005, the IPPs filed motions with the NHPUC seeking to disqualify two of the three NHPUC commissioners from participating in this proceeding.  As a result, on December 7, 2005, the IPPs then filed an interlocutory appeal with the New Hampshire Supreme Court (Supreme Court) on the basis that the forum for resolving this dispute is in state superior court.  On December 27, 2005, PSNH and the New Hampshire Attorney General’s Office (representing the NHPUC) each filed motions for summary disposition with the Supreme Court.  On February 7, 2006, the

Supreme Court declined to accept the IPPs interrogatory appeal.  As a result the matter will return to the NHPUC for a decision.  PSNH recovers the over-market cost of the IPP contracts through the SCRC.

Deferred Contractual Obligations

FERC Proceedings:  In 2003 the Connecticut Yankee Atomic Power Company (CYAPC) increased the estimated decommissioning and plant closure costs for the period 2000 through 2023 by approximately $395 million over the April 2000 estimate of $436 million approved by the FERC in a 2000 rate case settlement.  The revised estimate reflects the increases in the projected costs of spent fuel storage, increased security and liability and property insurance costs, and the fact that CYAPC is now self performing all work to complete the decommissioning of the plant due to the termination of the decommissioning contract with Bechtel Power Corporation (Bechtel) in July of 2003.  PSNH's share of CYAPC's increase in decommissioning and plant closure costs is approximately $20 million.  On July 1, 2004, CYAPC filed with the FERC for recovery seeking to increase its annual decommissioning collections from $16.7 million to $93 million for a six-year period beginning on January 1, 2005.  On August 30, 2004, the FERC issued an order accepting the rates, with collection beginning on February 1, 2005, subject to refund.

Both the Connecticut Department of Public Utility Control (DPUC) and Bechtel filed testimony in the FERC proceeding claiming that CYAPC was imprudent in its management of the decommissioning project.  In its testimony, the DPUC recommended a disallowance of $225 million to $234 million out of CYAPC's requested rate increase of approximately $395 million.  PSNH's share of the DPUC's recommended disallowance would be between $11 million to $12 million.  The FERC staff also filed testimony that recommended a $38 million decrease in the requested rate increase claiming that CYAPC should have used a different gross domestic product (GDP) escalator.  PSNH's share of this recommended decrease is $1.9 million.

On November 22, 2005, a FERC ALJ issued an initial decision finding no imprudence on CYAPC's part.  However, the ALJ did agree with the FERC staff’s position that a lower GDP escalator should be used for calculating the rate increase and found that CYAPC should recalculate its decommissioning charges to reflect the lower escalator.  Briefs to the full FERC addressing these issues were filed in January and February of 2006, and a final order is expected later in 2006.  Management expects that if the FERC staff's position on the decommissioning GDP cost escalator is found by the FERC to be more appropriate than that used by CYAPC to develop its proposed rates, then CYAPC would review whether to reduce its estimated decommissioning obligation and reduce the customers' obligation, including PSNH.  

The company cannot at this time predict the timing or outcome of the FERC proceeding required for the collection of the increased CYAPC decommissioning costs.  The company believes that the costs have been prudently incurred and will ultimately be recovered from the customers of PSNH.  However, there is a risk that some portion of these increased costs may not be recovered, or will have to be refunded if recovered, as a result of the FERC proceedings.  

On June 10, 2004, the DPUC and the Connecticut Office of Consumer Counsel (OCC) filed a petition seeking a declaratory order that CYAPC be allowed to recover all decommissioning costs from its wholesale purchasers, including PSNH, but that such purchasers may not be allowed to recover in their retail rates any costs that the FERC might determine to have been imprudently incurred.  On August 30, 2004, the FERC denied this petition.  On September 29, 2004, the DPUC and OCC asked the FERC to reconsider the petition and on October 20, 2005, the FERC denied the reconsideration, holding that the sponsor companies are only obligated to pay CYAPC for prudently incurred decommissioning costs and the FERC has no jurisdiction over the sponsors' rates to their retail customers.  On December 12, 2005, the DPUC sought review of these orders by the United States Court of Appeals for the D.C. Circuit.  The FERC and CYAPC have asked the court to dismi ss the case and the DPUC has objected to a dismissal.  PSNH cannot predict the timing or the outcome of these proceedings.  

Bechtel Litigation:  CYAPC and Bechtel commenced litigation in Connecticut Superior Court over CYAPC's termination of Bechtel's contract for the decommissioning of CYAPC's nuclear generating plant.  After CYAPC terminated the contract, responsibility for decommissioning was transitioned to CYAPC, which recommenced the decommissioning process.

On March 7, 2006, CYAPC and Bechtel executed a settlement agreement terminating this litigation.  Bechtel has agreed to pay CYAPC $15 million, and CYAPC will withdraw its termination of the contract for default and deem it terminated by agreement.

Spent Nuclear Fuel Litigation:  CYAPC, Yankee Atomic Energy Company (YAEC) and Maine Yankee Atomic Power Company (MYAPC) (Yankee Companies) also commenced litigation in 1998 charging that the federal government breached contracts it entered into with each company in 1983 under the Act.  Under the Act, the Department of Energy (DOE) was to begin removing spent nuclear fuel from the nuclear plants of the Yankee Companies no later than January 31, 1998 in return for payments by each company into the nuclear waste fund.  No fuel has been collected by the DOE, and spent nuclear fuel is stored on the sites of the Yankee Companies' plants.  The Yankee Companies collected the funds for payments into the nuclear waste fund from wholesale utility customers under FERC-approved contract rates.  The wholesale utility customers in turn collect these payments from their retail electric customers.  The Yankee Companies' individual da mage claims attributed to the government's breach ranging between $523 million and $543 million are specific to each plant and include incremental storage, security, construction and other costs through 2010.  The CYAPC damage claim ranges from $186 million to $198 million, the YAEC damage claim ranges from $177 million to $185 million and the MYAPC damage claim is $160 million.  The DOE trial ended on August 31, 2004 and a verdict has not been reached.  Post-trial findings of facts and final briefs were filed by the parties in January of 2005.  The Yankee Companies' current rates do not include an amount for recovery of damages in this matter.  Management can predict neither the outcome of this matter nor its ultimate impact on PSNH.

YAEC:  In November of 2005, YAEC established an updated estimate of the cost of completing the decommissioning of its plant resulting in an increase of approximately $85 million.  PSNH’s share of the increase in estimated costs is $6 million.  This estimate reflects the cost of completing site closure activities from October of 2005 forward and storing spent nuclear fuel and other high level waste on site until 2020.  This estimate projects a total cost of $192.1 million for the completion of decommissioning and long-term fuel storage.  To fund these costs, on November 23, 2005, YAEC submitted an application to the FERC to increase YAEC’s wholesale decommissioning charges.  The DPUC and the Massachusetts attorney general protested these increases.  On January 31, 2006, the FERC issued an order accepting the rate increase, effective February 1, 2006, subject to refund after hearings and settlement judge proceedings.  The hearings have been suspended pending settlement discussions between YAEC, the FERC and other intervenors in the case.  PSNH has a 7 percent ownership interest in YAEC and can predict neither the outcome of this matter nor its ultimate impact on PSNH.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates, assumptions and at times difficult, subjective or complex judgments.  Changes in these estimates, assumptions and judgments, in and of themselves, could materially impact the financial statements of PSNH.  Management communicates to and discusses with NU's Audit Committee of the Board of Trustees all critical accounting policies and estimates.  The following are the accounting policies and estimates that management believes are the most critical in nature.  

Revenue Recognition:  PSNH's retail revenues are based on rates approved by the NHPUC.  These regulated rates are applied to customers’ use of energy to calculate a bill.  In general, rates can only be changed through formal proceedings with the NHPUC.

The determination of the energy sales to individual customers is based on the reading of meters, which occurs on a systematic basis throughout the month.  Billed revenues are based on these meter readings.  At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and an estimated amount of unbilled revenues is recorded.

Wholesale transmission revenues are based on rates and formulas that are approved by the FERC.  Most of PSNH’s wholesale transmission revenues are collected through a combination of the RNS tariff and PSNH's LNS tariff.  The RNS tariff, which is administered by the ISO-NE, recovers the revenue requirements associated with transmission facilities that are deemed by the FERC to be Pool Transmission Facilities.  The LNS tariff, which was accepted by the FERC, provides for the recovery of PSNH’s total transmission revenue requirements, net of revenue credits received from various rate components, including revenues received under the RNS rates.  At December 31, 2005, this true up has resulted in the recognition of a $0.6 million regulatory liability.  

A significant portion of PSNH’s transmission business revenue comes from ISO-NE charges to PSNH’s electric distribution business.  PSNH recovers these costs through the retail rates that are charged to its retail customers.  PSNH does not currently have a retail transmission rate tracking mechanism.  

Unbilled Revenues:  Unbilled revenues represent an estimate of electricity or gas delivered to customers that has not yet been billed.  Unbilled revenues are included in revenue on the accompanying consolidated statements of income and are assets on the accompanying consolidated balance sheets that are reclassified to accounts receivable in the following month as customers are billed.

The estimate of unbilled revenues is sensitive to numerous factors that can significantly impact the amount of revenues recorded. Estimating the impact of these factors is complex and requires management’s judgment.  The estimate of unbilled revenues is important to PSNH’s consolidated financial statements as adjustments to that estimate could significantly impact operating revenues and earnings.

Through December 31, 2004, PSNH estimated unbilled revenues monthly using the requirements method.  The requirements method utilized the total monthly volume of electricity or gas delivered to the system and applied a delivery efficiency (DE) factor to reduce the total monthly volume by an estimate of delivery losses in order to calculate total estimated monthly sales to customers.  The total estimated monthly sales amount less the total monthly billed sales amount resulted in a monthly estimate of unbilled sales.  Unbilled revenues were estimated by first allocating sales to the respective rate classes, then applying an average rate to the estimate of unbilled sales.  The estimated DE factor had a significant impact on estimated unbilled revenue amounts.

In the first quarter of 2005, management adopted a new method to estimate unbilled revenues for PSNH.  The new method allocates billed sales to the current calendar month based on the daily load for each billing cycle (DLC method.)  The billed sales are subtracted from total calendar month sales to estimate unbilled sales.  The impact of adopting the new method was not material.  This new method replaces the requirements method described previously.  

Regulatory Accounting:  The accounting policies of PSNH historically reflect the effects of the rate-making process in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71).  The transmission, distribution and generation businesses of PSNH continue to be cost-of-service rate regulated, and management believes the application of SFAS No. 71 to those businesses continues to be appropriate.  Management must reaffirm this conclusion at each balance sheet date.  If, as a result of a change in circumstances, it is determined that any portion of the company no longer meets the criteria of regulatory accounting under SFAS No. 71, that portion of the company will have to discontinue regulatory accounting and write-off the respective regulatory assets and liabilities.  Such a write-off could have a material impact on PSNH’s consolidated financial statements.

The application of SFAS No. 71 results in recording regulatory assets and liabilities.  Regulatory assets represent the deferral of incurred costs that are probable of future recovery in customer rates.  In some cases, PSNH records regulatory assets before approval for recovery has been received

from the applicable regulatory commission.  Management must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery.  Management bases its conclusion on certain factors, including changes in the regulatory environment, recent rate orders issued by the applicable regulatory agencies and the status of any potential new legislation.  Regulatory liabilities represent revenues received from customers to fund expected costs that have not yet been incurred or are probable future refunds to customers.

Management uses its best judgment when recording regulatory assets and liabilities; however, regulatory commissions can reach different conclusions about the recovery of costs, and those conclusions could have a material impact on PSNH’s consolidated financial statements.  Management believes it is probable that PSNH will recover the regulatory assets that have been recorded.

Presentation:  In accordance with current accounting pronouncements, PSNH’s consolidated financial statements include all subsidiaries upon which control is maintained and all variable interest entities (VIE).  Determining whether the company is the primary beneficiary of a VIE is subjective and requires management’s judgment.  There are certain variables taken into consideration to determine whether the company is considered the primary beneficiary to the VIE.  A change in any one of these variables could require the company to reconsider whether or not it is the primary beneficiary of the VIE.  All intercompany transactions between these subsidiaries are eliminated as part of the consolidation process.

PSNH has less than 50 percent ownership interests in CYAPC, YAEC and MYAPC.  PSNH does not control these companies and does not consolidate them in its financial statements.  PSNH accounts for the investments in these companies using the equity method.  Under the equity method, PSNH records its ownership share of the earnings or losses at these companies.  Determining whether or not PSNH should apply the equity method of accounting for an investment requires management judgment.

In December of 2003, the Financial Accounting Standards Board (FASB) issued a revised version of FASB Interpretation No. (FIN) 46, "Consolidation of Variable Interest Entities," (FIN 46R).  FIN 46R was effective for PSNH for the first quarter of 2004 and did not have an impact on PSNH’s consolidated financial statements.

Pension and Postretirement Benefits Other Than Pensions (PBOP):  PSNH participates in a uniform noncontributory defined benefit retirement plan (Pension Plan) covering substantially all regular PSNH employees.  PSNH also participates in a postretirement benefit plan (PBOP Plan) to provide certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired employees.  For each of these plans, the development of the benefit obligation, fair value of plan assets, funded status and net periodic benefit credit or cost is based on several significant assumptions.  If these assumptions were changed, the resulting change in benefit obligations, fair values of plan assets, funded status and net periodic benefit credits or costs could have a material impact on PSNH’s consolidated financial statements.  

Pre-tax periodic pension expense for the Pension Plan totaled an expense of $18.1 million, $12.4 million and $6.8 million for the years ended December 31, 2005, 2004 and 2003, respectively.  The pension expense 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."

Not included in the pension expense amount are pension amounts related to intercompany allocations totaling $2.2 million, $0.7 million and $(0.2) million for the years ended December 31, 2005, 2004 and 2003, respectively, including pension curtailment and termination benefit expenses of $0.6 million and $0.1 million for the years ended December 31, 2005 and 2004, respectively.  These amounts are included in other operating expenses on the accompanying consolidated financial statements.

The pre-tax net PBOP Plan cost, excluding curtailment expense, totaled $9.4 million, $7.5 million and $6.2 million for the years ended December 31, 2005, 2004 and 2003, respectively.  

On December 15, 2005, the NU Board of Trustees approved a benefit for new non-union employees hired on and after January 1, 2006 to receive retirement benefits under a new 401(k) benefit rather than under the Pension Plan.  Non-union employees actively employed on December 31, 2005 will be given the choice in 2006 to elect to continue participation in the Pension Plan or instead receive a new employer contribution under the 401(k) Savings Plan effective January 1, 2007.  If the new benefit is elected, their accrued pension liability in the Pension Plan will be frozen as of December 31, 2006.  Non-union employees will make this election in the second half of 2006.  This decision resulted in the recording of an estimated pre-tax curtailment expense of $1.1 million in 2005, as a certain number of employees are expected to elect the new 401(k) benefit, resulting in a reduction in aggregate estimated future years of service under the Pension Plan.  Management estimated the amount of the curtailment expense associated with this change based upon actuarial calculations and certain assumptions, including the expected level of transfers to the new 401(k) benefit.  Any adjustments to this estimate resulting from actual employee elections will be recorded in 2006.

There were no curtailments or termination benefits recorded for the Pension Plan in 2004 or 2003 or the PBOP Plan in 2005, 2004 or 2003.

Long-Term Rate of Return Assumptions:  In developing the expected long-term rate of return assumptions, PSNH evaluated input from actuaries and consultants, as well as long-term inflation assumptions and PSNH’s historical 20-year compounded return of approximately 11 percent.  PSNH’s expected long-term rates of return on assets is based on certain target asset allocation assumptions and expected long-term rates of return.  PSNH believes that 8.75 percent is a reasonable long-term rate of return on Pension Plan and PBOP Plan assets (life assets and non-taxable health assets) and 6.85 percent for PBOP health assets, net of tax for 2005.  PSNH will continue to evaluate these actuarial assumptions, including the expected rate of return, at least annually, and will adjust the appropriate assumptions as necessary.  The Pension Plan’s and PBOP Plan’s target asset allocation assumptions and expected long - -term rates of return assumptions by asset category are as follows:

	At December 31,
	Pension Benefits		Postretirement Benefits
	2005 and 2004		2005 and 2004
Asset Category	Target Asset Allocation	Assumed Rate of Return	Target Asset Allocation	Assumed Rate of Return
Equity securities:
United States	45%	9.25%	55%	9.25%
Non-United States	14%	9.25%	11%	9.25%
Emerging markets	3%	10.25%	2%	10.25%
Private	8%	14.25%	-	-
Debt Securities:
Fixed income	20%	5.50%	27%	5.50%
High yield fixed     income	5%	7.50%	5%	7.50%
Real estate	5%	7.50%	-	-

The actual asset allocations at December 31, 2005 and 2004 approximated these target asset allocations.  PSNH routinely reviews the actual asset allocations and periodically rebalances the investments to the targeted asset allocations when appropriate.  For information regarding actual asset allocations, see Note 3, "Pension Benefits and Postretirement Benefits Other Than Pensions," to the consolidated financial statements.

Actuarial Determination of Income and Expense:  PSNH bases the actuarial determination of Pension Plan and PBOP Plan income/expense on a market-related valuation of assets, which reduces year-to-year volatility.  This market-related valuation calculation recognizes investment gains or losses over a four-year period from the year in which they occur.  Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the fair value of assets.  Since the market-related valuation calculation recognizes gains or losses over a four-year period, the future value of the market-related assets will be impacted as previously deferred gains or losses are recognized.  There will be no impact on the fair value of Pension Plan and PBOP Plan assets in the trust funds of these plans.

At December 31, 2005, the Pension Plan had cumulative unrecognized investment gains of $7.4 million, which will decrease pension expense over the next four years.  At December 31, 2005, the Pension Plan had cumulative unrecognized actuarial losses of $73.3 million, which will increase pension expense over the expected future working lifetime of active Pension Plan participants, or approximately 13 years.  The combined total of unrecognized investment gains and actuarial losses at December 31, 2005 is a net unrecognized loss of $65.9 million.  These gains and losses impact the determination of pension expense and the actuarially determined accrued pension amount recorded on the consolidated balance sheets but have no impact on expected Pension Plan funding.

At December 31, 2005, the PBOP Plan had cumulative unrecognized investment gains of $9.3 million, which will decrease PBOP Plan expense over the next four years.  At December 31, 2005, the PBOP Plan also had cumulative unrecognized actuarial losses of $38.8 million, which will increase PBOP Plan expense over the expected future working lifetime of active PBOP Plan participants, or approximately 13 years.  The combined total of unrecognized investment gains and actuarial losses at December 31, 2005 is a net unrecognized loss of $29.5 million.  These gains and losses impact the determination of PBOP Plan cost and the actuarially determined accrued PBOP Plan cost recorded on the consolidated balance sheets.

Discount Rate:  The discount rate that is utilized in determining future pension and PBOP obligations is based on a yield-curve approach where each cash flow related to the Pension Plan or PBOP Plan liability stream is discounted at an interest rate specifically applicable to the timing of the cash flow.  The yield curve is developed from the top quartile of AA rated Moody’s and S&P’s bonds without callable features outstanding at December 31, 2005.  This process calculates the present values of these cash flows and calculates the equivalent single discount rate that produces the same present value for future cash flows.  The discount rates determined on this basis are 5.80 percent for the Pension Plan and 5.65 percent for the PBOP Plan at December 31, 2005.  Discount rates used at December 31, 2004 were 6.00 percent for the Pension Plan and 5.50 percent for the PBOP Plan.

Expected Contributions and Forecasted Expense: Due to the effect of the unrecognized actuarial losses and based on an expected rate of return on Pension Plan assets of 8.75 percent, a discount rate of 6.00 percent and an expected rate of return on PBOP assets of 6.85 percent for health assets, net of tax and 8.75 percent for life assets and nontaxable health assets, a discount rate of 5.50 ­­­percent and various other assumptions, PSNH estimates that expected contributions to and forecasted expense for the Pension Plan and PBOP Plan will be as follows (in millions):

	Pension Plan		Postretirement Plan
Year	Expected Contributions	Forecasted Expense	Expected Contributions	Forecasted Expense
2006	$ 0.0	$20.8	$9.6	$9.6
2007	$ 0.0	$20.4	$8.1	$8.1
2008	$ 0.0	$21.0	$7.7	$7.7

Future actual pension and postretirement expense will depend on future investment performance, changes in future discount rates and various other factors related to the populations participating in the plans and amounts capitalized.

Sensitivity Analysis:  The following represents the increase/(decrease) to the Pension Plan's and PBOP Plan's reported cost as a result of the change in the following assumptions by 50 basis points (in millions):

	At December 31,
	Pension Plan		Postretirement Plan
Assumption Change	2005	2004	2005	2004
Lower long-term rate   of return	$  0.9	$  1.0	$0.2	$0.1
Lower discount rate	2.6	2.2	0.2	0.2
Lower compensation  increase	$(1.2)	$(0.9)	N/A	N/A

Plan Assets:  The market-related value of the Pension Plan assets has increased by $0.7 million to $202.3 million at December 31, 2005.  The projected benefit obligation (PBO) for the Pension Plan has also increased by $30.5 million to $354.6 million at December 31, 2005.  These changes have increased the underfunded status of the Pension Plan on a PBO basis from an underfunded position of $122.5 million at December 31, 2004 to an underfunded position of $152.3 million at December 31, 2005.  The PBO includes expectations of future employee compensation increases.  The accumulated benefit obligation (ABO) of the Pension Plan was approximately $106.6 million more than Pension Plan assets at December 31, 2005 and approximately $69.1 million more than Pension Plan assets at December 31, 2004.  The ABO for the entire NU plan is the obligation for employee service and compensation provided through December 31, 2005.  Under current accounting rules, if the ABO for the entire NU plan exceeds the entire NU Pension Plan assets at a future plan measurement date, PSNH will record its share of the additional minimum liability.  PSNH has not made employer contributions to the Pension Plan since 1991.

The value of PBOP Plan assets has increased from $34.6 million at December 31, 2004 to $39.9 million at December 31, 2005.  The benefit obligation for the PBOP Plan has also increased from $79.7 million at December 31, 2004 to $87 million at December 31, 2005.  These changes have increased the underfunded status of the PBOP Plan on an accumulated projected benefit obligation basis from $45.1 million at December 31, 2004 to $47.1 million at December 31, 2005.  PSNH has made a contribution each year equal to the PBOP Plan’s postretirement benefit cost, excluding curtailment and termination benefits.

Health Care Cost:  The health care cost trend assumption used to project increases in medical costs was 7 percent for 2005 and 8 percent for 2004, decreasing one percentage point per year to an ultimate rate of 5 percent in 2007.  For December 31, 2005 disclosure purposes, the health care cost trend assumption was reset for 2006 at 10 percent, decreasing one percentage point per year to an ultimate rate of 5 Percent in 2011.  The effect of increasing the health care cost trend by one percentage point would have increased service and interest lost components of the PBOP Plan cost by $0.2 million in 2005 and $0.1 million in 2004.

Income Taxes:  Income tax expense is calculated each year in each of the jurisdictions in which PSNH operates.  This process involves estimating PSNH’s actual current tax exposures as well as assessing temporary differences resulting from differing treatment of items, such as timing of the deduction and expenses for tax and book accounting purposes.  These differences result in deferred tax assets and liabilities, which are included in PSNH’s consolidated balance sheets.  The income tax estimation process impacts all of PSNH’s segments and adjustments made to income taxes could significantly affect PSNH’s consolidated financial statements.  Management must also assess the likelihood that deferred tax assets will be recovered from future taxable income, and to the extent that recovery is not likely, a valuation allowance must be established.  Significant management judgment is required in determinin g 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.  The regulatory asset amounted to $35.9 million and $37.5 million at December 31, 2005 and 2004, respectively.  Regulatory agencies in the jurisdictions in which PSNH operates require the tax effect of specific temporary differences to be "flowed through" to utility customers.  Flow through treatment means that deferred tax expense is not recorded on the consolidated statements of income.  Instead, the tax effect of the temporary difference impacts both amounts for income tax expense currently included in customers’ rates and the company’s net income.  Flow through treatment can result in effective income tax rates that are significantly different than expected in come tax rates.  Recording deferred taxes on flow through items is required by SFAS No. 109, and the offset to the deferred tax amounts is the regulatory asset referred to above.

A reconciliation from expected tax expense at the statutory federal income tax rate to actual tax expense recorded is included in the accompanying footnotes to the consolidated financial statements.  See Note 1H, "Summary of Significant Accounting Policies - Income Taxes," to the consolidated financial statements, for further information.

The estimates that are made by management in order to record income tax expense, accrued taxes and deferred taxes are compared each year to the actual tax amounts filed on PSNH’s income tax returns.  The income tax returns were filed in the fall of 2005 for the 2004 tax year, and PSNH recorded differences between income tax expense, accrued taxes and deferred taxes on its consolidated financial statements and the amounts that were on its income tax returns.

Depreciation:  Depreciation expense is calculated based on an asset’s useful life, and judgment is involved when estimating the useful lives of certain assets.  A change in the estimated useful lives of these assets could have a material impact on PSNH’s consolidated financial statements absent timely rate relief for PSNH's assets.

Accounting for Environmental Reserves:  Environmental reserves are accrued using a probabilistic model approach when assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated.  Adjustments made to environmental liabilities could have a significant effect on earnings.  The probabilistic model approach estimates the liability based on the most likely action plan from a variety of available remediation options, ranging from no action to remedies ranging from establishing institutional controls to full site remediation and long-term monitoring.  The probabilistic model approach estimates the liabilities associated with each possible action plan based on findings through various phases of site assessments.

These estimates are based on currently available information from presently enacted state and federal environmental laws and regulations and several cost estimates from outside engineering and remediation contractors.  These amounts also take into consideration prior experience in remediating contaminated sites and data released by the United States Environmental Protection Agency and other organizations.  These estimates are subjective in nature partly because there are usually several different remediation options from which to choose when working on a specific site.  These estimates are subject to revisions in future periods based on actual costs or new information concerning either the level of contamination at the site or newly enacted laws and regulations.  The amounts recorded as environmental liabilities on the consolidated balance sheets represent management’s best estimate of the liability for environmental costs based on current site information from site assessments and remediation estimates.  These liabilities are estimated on an undiscounted basis.

PSNH has a regulatory recovery mechanism in place for environmental costs.  Accordingly, regulatory assets have been recorded for certain of PSNH’s environmental liabilities.  As of December 31, 2005 and 2004, $7 million and $8.9 million, respectively, have been recorded as regulatory assets on the accompanying consolidated balance sheets.  

Asset Retirement Obligations:  On March 30, 2005, the FASB issued FIN 47, "Accounting for Conditional Asset Retirement Obligations - an Interpretation of FASB Statement No. 143."  FIN 47 requires an entity to recognize a liability for the fair value of an ARO that is conditional on a future event if the liability’s fair value can be reasonably estimated.  PSNH adopted FIN 47 on December 31, 2005.  Upon adoption, management identified several conditional removal obligations that have been accounted for as AROs.  For further information regarding the adoption of FIN 47, see Note 1L, "Summary of Significant Accounting Policies - Asset Retirement Obligations," to the consolidated financial statements.

Under SFAS No. 71, PSNH recovers amounts in rates for future costs of removal of plant assets.  At December 31, 2005 and 2004, these amounts totaling $85.7 million and $87.6 million, respectively, are classified as regulatory liabilities on the accompanying consolidated balance sheets.

Special Purpose Entities:  During 2001 and 2002, to facilitate the issuance of rate reduction bonds intended to finance certain stranded costs, PSNH established two special purpose entities:  PSNH Funding LLC and PSNH Funding LLC 2.  The funding companies were created as part of a state-sponsored securitization program.  The funding companies are restricted from engaging in non-related activities and are required to operate in a manner intended to reduce the likelihood that they would be included in PSNH’s bankruptcy estate if it ever became involved in a bankruptcy proceeding.  The funding companies and the securitization amounts are consolidated in the accompanying consolidated financial statements.

For further information regarding the matters in this "Critical Accounting Policies and Estimates," section, see Note 1, "Summary of Significant Accounting Policies," Note 3, "Pension Benefits and Postretirement Benefits Other Than Pensions," and Note 4B, "Commitments and Contingencies - Environmental Matters," to the consolidated financial statements.

Other Matters

Commitments and Contingencies:  For further information regarding other commitments and contingencies, see Note 4, "Commitments and Contingencies," to the consolidated financial statements.

Accounting Standards Issued But Not Yet Adopted:

Accounting Changes and Error Corrections: In May of 2005, the FASB issued SFAS No. 154, "Accounting Changes and Error Corrections."  SFAS No. 154 is effective beginning on January 1, 2006 for PSNH and requires retrospective application to prior periods’ financial statements of voluntary changes in accounting principles.  It also applies to accounting changes required by a new accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions.  SFAS No. 154 does not change previous guidance for reporting the correction of an error in previously issued financial statements or a change in accounting estimate.  Implementation of SFAS No. 154 on January 1, 2006 is not expected to affect PSNH’s consolidated financial statements until such time that its provisions are required to be applied as described above.  

Contractual Obligations and Commercial Commitments:  Information regarding PSNH’s contractual obligations and commercial commitments at December 31, 2005 is summarized through 2010 and thereafter as follows:

(Millions of Dollars)	2006	2007	2008	2009	2010	Thereafter
Long-term debt (a) (b)	$      -	$       -	$      -	$      -	$      -	$507.3
Estimated interest  payments on existing   long-term debt	21.6	21.6	21.6	21.6	21.6	250.7
Capital leases  (c) (d)	0.3	0.2	0.2	-	-	-
Operating leases  (d) (e)	6.4	5.3	4.4	2.8	2.2	7.1
Required funding   of other post-  retirement benefit  obligations (e)	9.6	8.1	7.7	7.3	6.9	N/A
Long-term contractual   arrangements (d) (e)	158.6	78.6	52.4	52.2	51.8	276.9
Totals	$196.5	$113.8	$ 86.3	$ 83.9	$ 82.5	$1,042.0

 ^(a) Included in PSNH's debt agreements are usual and customary positive, negative and financial covenants.  Non-compliance with certain covenants, for example the timely payment of principal and interest, may constitute an event of default, which could cause an acceleration of principal in the absence of receipt by the company of a waiver or amendment.  Such acceleration would change the obligations outlined in the table of contractual obligations and commercial commitments.

^(b) Long-term debt excludes $0.2 million of net unamortized discounts.

^(c) The capital lease obligations include imputed interest of $0.2 million.

^(d) PSNH has no provisions in its capital or operating lease agreements or agreements related to its long-term contractual arrangements that could trigger a change in terms and conditions, such as acceleration of payment obligations.

^(e)  Amounts are not included on PSNH's consolidated balance sheets.

Rate reduction bond amounts are non-recourse to PSNH, have no required payments over the next five years and are not included in this table.  For further information regarding PSNH’s contractual obligations and commercial commitments, see Note 2, "Short-Term Debt," Note 4C, "Commitments and Contingencies - Long-Term Contractual Arrangements," Note 6, "Leases," and Note 9, "Long-Term Debt," to the consolidated financial statements.

Forward Looking Statements:  This discussion and analysis includes statements concerning PSNH's expectations, plans, objectives, future financial performance and other statements that are not historical facts.  These statements are "forward looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995.  In some cases the reader can identify these forward looking statements by words such as "estimate," "expect," "anticipate," "intend," "plan," "believe," "forecast," "should," "could," and similar expressions.  Forward looking statements involve risks and uncertainties that may cause actual results or outcomes to differ materially from those included in the forward looking statements.  Factors that may cause actual results to differ materially from those included in the forward looking statemen ts include, but are not limited to, actions by state and federal regulatory bodies, competition and industry restructuring, changes in economic conditions, changes in weather patterns, changes in laws, regulations or regulatory policy, expiration or initiation of significant energy supply contracts, changes in levels of capital expenditures, developments in legal or public policy doctrines, technological developments, volatility in electric and natural gas commodity markets, effectiveness of our risk management policies and procedures, changes in accounting standards and financial reporting regulations, fluctuations in the value of electricity positions, actions of rating agencies, terrorist attacks on domestic energy facilities and other presently unknown or unforeseen factors. Other risk factors are detailed from time to time in our reports to the SEC.  Management undertakes no obligation to update the information contained in any forward looking statements to reflect developments or circumstances occ urring after the statement is made.

Web site:  Additional financial information is available through PSNH's web site at www.psnh.com.

RESULTS OF OPERATIONS

The following table provides the variances in income statement line items for the consolidated statements of income included in this annual report for the past two years.

Income Statement Variances	2005 over/(under) 2004			2004 over/(under) 2003
(Millions of Dollars)	Amount	Percent		Amount	Percent
Operating Revenues	$160	16	%	$81	9	%
Operating Expenses:
Fuel, purchased and net interchange power	101	24		10	3
Other operation	13	8		22	16
Maintenance	(1)	(2)		1	1
Depreciation	1	2		2	5
Amortization	49	52		58	(a)
Amortization of rate reduction bonds	3	7		4	9
Taxes other than income taxes	1	2		2	7
Total operating expenses	167	19		99	13
Operating Income	(7)	(7)		(18)	(15)
Interest expense, net	1	2		1	1
Other income/(loss), net	2	(a)		3	97
Income before income tax expense	(6)	(9)		(16)	(21)
Income tax expense	(1)	(6)		(17)	(56)
Net income/(loss)	$  (5)	(11)	%	$  1	2	%

(a) Percent greater than 100.

Comparison of the Year 2005 to the Year 2004

Operating Revenues

Operating revenues increased $160 million in 2005, as compared to 2004, primarily due to higher distribution revenue ($154 million) and higher transmission revenue ($6 million).  The distribution revenue increase of $154 million is primarily due to the components of revenues which are included in regulatory commission approved tracking mechanisms that track the recovery of certain incurred costs ($141 million).  The tracking mechanisms allow for rates to be changed periodically with over allocations refunded to customers or under collections collected from customers in future periods.  The transition service energy rate component of retail revenues increased by $122 million, primarily due to an increase in the cost of fuel and purchased power.  The distribution and transmission components of PSNH’s retail rates which impact earnings increased $13 million primarily due to the retail rate increases effe ctive October 1, 2004 and June 1, 2005 ($8 million) and higher retail sales ($4 million).  Retail sales increased 1.9 percent in 2005 compared to the same period of 2004.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power increased $101 million in 2005 primarily due to the higher cost of energy as a result of higher fuel prices.

Other Operation

Other operation expenses increased $13 million in 2005 as a result of higher administrative expenses ($12 million).  The higher administrative expenses are primarily due to higher pension and other benefit costs ($6 million) and employee termination and benefit plan curtailment charges ($2 million).

Maintenance

Maintenance expense decreased $1 million in 2005 primarily due to lower fossil generation expenses ($2 million) and lower overhead line maintenance ($2 million), partially offset by higher substation maintenance ($1 million) and higher tree trimming expenses ($1 million).

Depreciation

Depreciation increased $1 million in 2005 primarily due to higher plant balances.

Amortization of Regulatory Assets, Net

Amortization of regulatory assets, net increased $49 million in 2005 primarily due to an acceleration in the recovery of PSNH’s non-securitized stranded costs.  The acceleration of non-securitized stranded cost recovery was due to the positive reconciliation of stranded cost revenues and stranded cost expense, which also includes net ES costs.

Amortization of Rate Reduction Bonds

Amortization of rate reduction bonds increased $3 million in 2005 as a result of the repayment of additional principal.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $1 million in 2005 primarily due to higher property taxes.

Interest Expense, Net

Interest expense increased $1 million in 2005 primarily due to higher interest rates on the variable pollution control revenue bonds ($2 million) and the issuance of $50 million of ten-year first mortgage bonds in July 2004 ($2 million), partially offset by lower rate reduction bond interest resulting from lower principal balances outstanding ($3 million).

Other Income/(Loss), Net

Other income, net increased $2 million in 2005 primarily due to a higher earned C&LM incentive and a higher allowance for funds used during construction (AFUDC) as a result of increased eligible CWIP for generation, lower short-term debt, and a greater component of CWIP being subject to a higher equity rate.  

Income Taxes

Income tax expense decreased $1 million in 2005 primarily due to lower pre-tax income and lower state unitary taxable income.  

Comparison of the Year 2004 to the Year 2003

Operating Revenues

Operating revenues increased $81 million in 2004 compared with the same period of 2003 primarily due to higher distribution retail revenue ($93 million) and higher transmission revenue ($6 million), partially offset by lower wholesale revenue ($19 million).  Distribution retail revenue increased primarily due to higher transition service energy rates ($67 million) and higher sales volumes ($28 million).  The Connecticut Valley Electric Company, Inc. (CVEC) acquisition increased sales and represents $18 million of the revenue increase.  Retail kilowatt-hour (kWh) sales increased by 3.1 percent in 2004.  Transmission revenues were higher primarily due to the October 2003 implementation of the FERC approved transmission rate increase.  The regulated wholesale revenue decrease is primarily due to a lower number of wholesale transactions.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power increased $10 million in 2004 primarily due to higher fossil fuel costs ($9 million) as a result of higher fuel prices.

Other Operation

Other operation expenses increased $22 million in 2004 primarily due to higher retail transmission expenses which are collected through retail delivery rates ($7 million), higher fossil generation expense ($6 million), and higher administrative expenses ($10 million) primarily due to higher pension and medical costs.

Maintenance

Maintenance expense increased $1 million in 2004 primarily due to higher tree trimming and substation maintenance ($1 million) and higher transmission station and overhead line maintenance ($1 million), partially offset by lower fossil generation expenses ($1 million), mainly due to a higher level of maintenance overhaul expenses in 2003.

Depreciation

Depreciation increased $2 million in 2004 primarily due to higher plant balances.

Amortization of Regulatory Assets, Net

Amortization of regulatory assets, net increased $58 million primarily due to an acceleration in the recovery of PSNH’s non-securitized stranded costs.  The acceleration of non-securitized stranded cost recovery was possible due to the positive reconciliation of stranded costs revenues and stranded cost expense, which also includes net ES costs.

Amortization of Rate Reduction Bonds

Amortization of rate reduction bonds increased $4 million as a result of the repayment of additional principal.  

Taxes Other Than Income Taxes

Taxes other than income taxes increased $2 million in 2004 primarily due to higher property tax ($1 million) and higher federal payroll taxes ($1 million).

Interest Expense, Net

Interest expense, net increased $1 million in 2004 primarily due to the issuance of $50 million of 10-year first mortgage bonds in July 2004, partially offset by lower interest on rate reduction bonds as a result of lower debt levels.

Other Income/(Loss), Net

Other income, net increased $3 million in 2004 primarily due to an earned Conservation and Load Management (C&LM) incentive ($2 million) and higher gains on the disposition of property ($1 million).

Income Taxes

Income tax expense decreased $17 million in 2004 primarily due to lower pre-tax earnings and a lower effective tax rate.  The lower effective tax rate resulted from other adjustments to tax expense totaling $5 million and the unitary impact on state income tax expense.

Company Report on Internal Controls    

Management is responsible for the preparation, integrity, and fair presentation of the accompanying consolidated financial statements of Public Service Company of New Hampshire and subsidiaries and other sections of this annual report.  These financial statements, which were audited by Deloitte & Touche LLP, have been prepared in conformity with accounting principles generally accepted in the United States of America using estimates and judgments, where required, and giving consideration to materiality.

The company has endeavored to establish a control environment that encourages the maintenance of high standards of conduct in all of its business activities.  Management is responsible for maintaining a system of internal controls over financial reporting, that is designed to provide reasonable assurance, at an appropriate cost-benefit relationship, to the company’s management and Board of Trustees of Northeast Utilities regarding the preparation of reliable, published financial statements.  The system is supported by an organization of trained management personnel, policies and procedures, and a comprehensive program of internal audits.  Through established programs, the company regularly communicates to its management employees their internal control responsibilities and obtains information regarding compliance with policies prohibiting conflicts of interest and policies segregating information between regulated and unregulated subs idiary companies.  The company has standards of business conduct for all employees, as well as a code of ethics for senior financial officers.

The Audit Committee of the Board of Trustees of Northeast Utilities is composed entirely of independent trustees and includes two members that the Board of Trustees considers "audit committee financial experts."  The Audit Committee meets regularly with management, the internal auditors, and the independent auditors to review the activities of each and to discuss audit matters, financial reporting matters, and the system of internal controls over financial reporting.  The Audit Committee also meets periodically with the internal auditors and the independent auditors without management present.

Because of inherent limitations in any system of internal controls, errors or irregularities may occur and not be detected.  The company believes, however, that its system of internal controls over financial reporting and control environment provide reasonable assurance that its assets are safeguarded from loss or unauthorized use and that its financial records, which are the basis for the preparation of all financial statements, are reliable.  Additionally, management believes that its disclosure controls and procedures are in place and operating effectively.  Disclosure controls and procedures are designed to ensure that information included in reports such as this annual report is recorded, processed, summarized, and reported within the time periods required and that the information disclosed is accumulated and reviewed by management for discussion and approval.

March 7, 2006

Report of Independent Registered Public Accounting Firm    

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) (the “Company”) as of December 31, 2005 and 2004, 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, 2005.  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 the standards of the Public Company Accounting Oversight Board (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.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting.  Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.  An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Public Service Company of New Hampshire and subsidiaries as of December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

     Deloitte & Touche LLP

Hartford, Connecticut

March 7, 2006

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
At December 31,	2005		2004
	(Thousands of Dollars)
ASSETS
Current Assets:
Cash	$                              27	$                         4,855
Receivables, less provision for uncollectible
accounts of $2,362 in 2005 and $1,764 in 2004	95,599	75,019
Accounts receivable from affiliated companies	20,348	34,341
Unbilled revenues	47,705	39,397
Taxes receivable	-	4,498
Fuel, materials and supplies	72,820	52,479
Prepayments and other	11,987	13,092
	248,486	223,681
Property, Plant and Equipment:
Electric utility	1,732,716	1,627,174
Other	5,816	5,675
	1,738,532	1,632,849
Less: Accumulated depreciation	698,480	664,336
	1,040,052	968,513
Construction work in progress	115,371	63,190
	1,155,423	1,031,703
Deferred Debits and Other Assets:
Regulatory assets	821,951	900,115
Other	68,723	49,875
	890,674	949,990
Total Assets	$                  2,294,583	$                  2,205,374
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,	2005	2004
	(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION
Current Liabilities:
Notes payable to banks	$                               -	$                       10,000
Notes payable to affiliated companies	15,900	20,400
Accounts payable	63,320	51,786
Accounts payable to affiliated companies	16,738	38,591
Accrued taxes	5,186	-
Accrued interest	8,202	11,799
Other	15,733	13,184
	125,079	145,760
Rate Reduction Bonds	382,692	428,769
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	242,590	311,998
Accumulated deferred investment tax credits	1,230	1,625
Deferred contractual obligations	48,262	54,459
Regulatory liabilities	414,558	323,707
Accrued pension	76,446	57,199
Other	44,136	24,968
	827,222	773,956
Capitalization:
Long-Term Debt	507,086	457,190
Common Stockholder's Equity:
Common stock, $1 par value – authorized
100,000,000 shares; 301 shares outstanding
in 2005 and 2004	-	-
Capital surplus, paid in	209,788	156,532
Retained earnings	242,633	243,277
Accumulated other comprehensive income/(loss)	83	(110)
Common Stockholder's Equity	452,504	399,699
Total Capitalization	959,590	856,889
Commitments and Contingencies (Note 4)
Total Liabilities and Capitalization	$                  2,294,583	$                  2,205,374
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,	2005	2004	2003
	(Thousands of Dollars)
Operating Revenues	$       1,128,427	$        968,749	$      888,186
Operating Expenses:
Operation -
Fuel, purchased and net interchange power	515,801	414,687	404,431
Other	175,828	162,513	140,642
Maintenance	64,200	65,620	64,872
Depreciation	46,467	45,662	43,322
Amortization of regulatory assets, net	144,746	95,436	37,861
Amortization of rate reduction bonds	46,648	43,764	40,040
Taxes other than income taxes	36,498	35,805	33,407
Total operating expenses	1,030,188	863,487	764,575
Operating Income	98,239	105,262	123,611
Interest Expense:
Interest on long-term debt	20,481	17,441	15,408
Interest on rate reduction bonds	24,074	26,901	29,081
Other interest	1,733	1,197	727
Interest expense, net	46,288	45,539	45,216
Other Income/(Loss), Net	2,022	(89)	(2,998)
Income Before Income Tax Expense	53,973	59,634	75,397
Income Tax Expense	12,234	12,993	29,773
Net Income	$            41,739	$          46,641	$        45,624
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Net Income	$            41,739	$          46,641	$        45,624
Other comprehensive income/(loss), net of tax:
Unrealized (losses)/gains on securities	(39)	76	128
Minimum supplemental executive retirement
pension liability adjustments	232	(69)	(140)
Other comprehensive income/(loss), net of tax	193	7	(12)
Comprehensive Income	$            41,932	$          46,648	$        45,612
The accompanying notes are an integral part of these consolidated financial statements.

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
						Accumulated
	Common Stock			Capital		Other
				Surplus,	Retained	Comprehensive
	Shares	Amount		Paid In	Earnings	(Loss)/Income	Total
			(Thousands of Dollars, except share information)
Balance at January 1, 2003	301	$             -		$  126,937	$  194,998	$                 (105)	$          321,830
Net income for 2003					45,624		45,624
Cash dividends on common stock					(16,800)		(16,800)
Allocation of benefits – ESOP				(382)			(382)
Capital contribution from NU parent				30,000			30,000
Other comprehensive loss						(12)	(12)
Balance at December 31, 2003	301	-		156,555	223,822	(117)	380,260
Net income for 2004					46,641		46,641
Cash dividends on common stock					(27,186)		(27,186)
Allocation of benefits – ESOP				(220)			(220)
Tax deduction for stock options exercised and Employee Stock Purchase
Plan disqualifying dispositions				197			197
Other comprehensive income						7	7
Balance at December 31, 2004	301	-		156,532	243,277	(110)	399,699
Net income for 2005					41,739		41,739
Cash dividends on common stock					(42,383)		(42,383)
Allocation of benefits – ESOP				(208)			(208)
Tax deduction for stock options exercised and Employee Stock Purchase
Plan disqualifying dispositions				45			45
Capital contribution from NU parent				53,419			53,419
Other comprehensive income						193	193
Balance at December 31, 2005	301	$             -		$   209,788	$  242,633	$                    83	$            452,504
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,	2005	2004	2003
	(Thousands of Dollars)
Operating activities:
Net income	$                41,739	$                46,641	$                45,624
Adjustments to reconcile to net cash flows
provided by operating activities:
Bad debt expense	3,904	2,742	1,379
Depreciation	46,467	45,662	43,322
Deferred income taxes	(68,347)	(24,160)	(6,670)
Amortization of regulatory assets, net	144,746	95,436	37,861
Amortization of rate reduction bonds	46,648	43,764	40,040
Amortization of recoverable energy costs	23,388	23,388	23,388
Pension expense	14,338	8,994	4,882
Regulatory (refunds)/overrecoveries	(22,910)	(21,169)	11,276
Deferred contractual obligations	(12,465)	(9,654)	(9,028)
Other non-cash adjustments	(8,468)	5,184	(53,013)
Other sources of cash	442	5,769	9,425
Other uses of cash	(19,962)	(5,615)	(5,275)
Changes in current assets and liabilities:
Receivables and unbilled revenues, net	(18,799)	(33,867)	(9,136)
Fuel, materials and supplies	(16,300)	(5,411)	2,114
Other current assets	1,170	(6,248)	(6,445)
Accounts payable	(9,009)	37,659	3,457
Accrued taxes	9,684	(1,914)	(56,241)
Other current liabilities	(1,013)	(4,448)	5,921
Net cash flows provided by operating activities	155,253	202,753	82,881
Investing Activities:
Investments in plant	(158,832)	(153,248)	(105,088)
Net proceeds from sale of property	1,461	-	-
Proceeds from sales of investment securities	3,227	3,038	2,015
Purchases of investment securities	(3,415)	(3,970)	(3,544)
CVEC acquisition special deposit	-	-	(30,105)
Other investing activities	(2,767)	2,958	(5,016)
Net cash flows used in investing activities	(160,326)	(151,222)	(141,738)
Financing Activities:
Issuance of long-term debt	50,000	50,000	-
Retirement of rate reduction bonds	(46,077)	(43,453)	(38,619)
(Decrease)/increase in short-term debt	(10,000)	-	10,000
NU Money Pool (lending)/borrowing	(4,500)	(28,500)	71,900
Capital contribution from Northeast Utilities	53,419	-	30,000
Cash dividends on common stock	(42,383)	(27,186)	(16,800)
Other financing activities	(214)	(274)	(206)
Net cash flows provided by/(used in) financing activities	245	(49,413)	56,275
Net (decrease)/increase in cash	(4,828)	2,118	(2,582)
Cash - beginning of year	4,855	2,737	5,319
Cash - end of year	$                       27	$                  4,855	$                  2,737
Supplemental Cash Flow Information:
Cash paid during the year for:
Interest, net of amounts capitalized	$                48,165	$                43,550	$                45,639
Income taxes	$                72,140	$                49,452	$                97,165
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) is a wholly owned subsidiary of Northeast Utilities (NU).  PSNH is a reporting company under the Securities Exchange Act of 1934.  Until February 8, 2006, NU was registered with the Securities and Exchange Commission (SEC) as a holding company under the Public Utility Holding Company Act of 1935 (PUHCA).  On February 8, 2006, PUHCA was repealed.  Arrangements among PSNH, other NU companies, outside agencies, and other utilities covering interconnections, interchange of electric power and sales of utility property, are subject to regulation by the Federal Energy Regulatory Commission (FERC) and/or the SEC.  PSNH is subject to further regulation for rates, accounting and other matters by the FERC and the New Hampshire Public Utilities Commission (NHPUC).  PSNH furnishes franchised retail electric service in New Hampshire.  PSNH ’s results include the operations of its distribution and generation and transmission segments.

Several wholly owned subsidiaries of NU provide support services for NU’s companies, including PSNH.  Northeast Utilities Service Company (NUSCO) provides centralized accounting, administrative, engineering, financial, information technology, legal, operational, planning, purchasing, and other services to NU’s companies.

Included in the consolidated balance sheet at December 31, 2005, are accounts receivable from affiliated companies and accounts payable to affiliated companies totaling $20.3 million and $16.7 million, respectively, relating to transactions between PSNH and other subsidiaries that are wholly owned by NU.  At December 31, 2004, these amounts totaled $34.3 million and $38.6 million, respectively.

B.

Presentation

The consolidated financial statements of PSNH include the accounts of its subsidiaries, PSNH Funding LLC and PSNH Funding LLC2.  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 consolidated 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 period data included in the accompanying consolidated financial statements have been made to conform with the current years' presentation.  

In the company's consolidated balance sheet at December 31, 2004, the company changed the classification of certain deposit amounts totaling $7.3 million related to its rate reduction bonds.  The company previously presented these amounts on a gross basis in deferred debits and other assets - other with an equal and offsetting amount in other current liabilities.  For the current year presentation, these amounts are presented on a net basis in the company's accompanying consolidated balance sheet.

In the company’s consolidated statements of income for the years ended December 31, 2004 and 2003, the company changed the classification of certain costs that were not recoverable from regulated customers totaling $0.9 million and $2 million, respectively.  The company previously presented these amounts in other income, net.  For the current year presentation, these amounts are presented in other operation expenses in the consolidated statements of income for the years ended December 31, 2004 and 2003.

The consolidated statements of cash flows for the years ended December 31, 2004 and 2003 have also been reclassified to exclude from cash flows from operations the change in accounts payable related to capital projects as well as excluding these amounts from investments in property and plant in investing activities.  These amounts totaled sources of cash of $9.6 million and uses of cash of $0.3 million for the years ended December 31, 2004 and 2003, respectively.  

C.

Accounting Standards Issued But Not Yet Adopted

Accounting Changes and Error Corrections:  In May of 2005, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 154, "Accounting Changes and Error Corrections."  SFAS No. 154 is effective beginning on January 1, 2006 for PSNH and requires retrospective application to prior periods’ financial statements of voluntary changes in accounting principle.  It also applies to accounting changes required by a new accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions.  SFAS No. 154 does not change previous guidance for reporting the correction of an error in previously issued financial statements or a change in accounting estimate.  Implementation of SFAS No. 154 on January 1, 2006 is not expected to affect PSNH’s consolidated financial statements until such time that its provisions are required to be applied as described above.

D.

Guarantees

NU provides credit assurances on behalf of subsidiaries, including PSNH, in the form of guarantees and letters of credit (LOCs) in the normal course of business.  At December 31, 2005, the maximum level of exposure in accordance with FASB Interpretation No. (FIN) 45, "Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others," under guarantees by NU on behalf of PSNH totaled $3.5 million.  A majority of these guarantees do not have established expiration dates, and some guarantees have unlimited exposure to commodity price movements.  Additionally, NU had $0.1 million of LOCs issued on behalf of PSNH at December 31, 2005.  PSNH has no guarantees of the performance of third parties.  

Several underlying contracts that NU guarantees, as well as certain surety bonds, contain credit ratings triggers that would require NU to post collateral in the event that NU’s credit ratings are downgraded below investment grade.

Until the repeal of PUHCA on February 8, 2006, NU was authorized by the SEC to provide up to $50 million of guarantees to the Utility Group, including PSNH, through June 30, 2007.  The amount of guarantees on behalf of PSNH outstanding for compliance with this limit at December 31, 2005 is $0.1 million.  These amounts are calculated using different, more probabilistic and fair-value based criteria than the maximum level of exposure required to be disclosed under FIN 45.  FIN 45 includes all exposures even though they are not reasonably likely to result in exposure to NU, on behalf of PSNH.

With the repeal of PUHCA, there are no regulatory limits on NU's ability to guarantee the obligation of its subsidiaries, including PSNH.

E.

Revenues

PSNH's retail revenues are based on rates approved by the NHPUC.  These regulated rates are applied to customers' use of energy to calculate a bill.  In general, rates can only be changed through formal proceedings with the NHPUC.  

Unbilled Revenues:  Unbilled revenues represent an estimate of electricity delivered to customers that has not yet been billed.  Unbilled revenues are included in revenue on the statement of income and are assets on the balance sheet that are reclassified to accounts receivable in the following month as customers are billed.  Such estimates are subject to adjustment when actual meter readings become available, when changes in estimating methodology occur and under other circumstances.

Through December 31, 2004, PSNH estimated unbilled revenues monthly using the requirements method.  The requirements method utilized the total monthly volume of electricity delivered to the system and applied a delivery efficiency (DE) factor to reduce the total monthly volume by an estimate of delivery losses in order to calculate total estimated monthly sales to customers.  The total estimated monthly sales amount less the total monthly billed sales amount resulted in a monthly estimate of unbilled sales.  Unbilled revenues were estimated by first allocating sales to the respective rate classes, then applying an average rate to the estimate of unbilled sales.  The estimated DE factor had a significant impact on estimated unbilled revenue amounts.

In the first quarter of 2005, management adopted a new method to estimate unbilled revenues for PSNH.  The new method allocates billed sales to the current calendar month based on the daily load for each billing cycle (DLC method).  The billed sales are subtracted from total calendar month sales to estimate unbilled sales.  The impact of adopting the new method was not material.  This new method replaces the requirements method described above.    

Transmission Revenues - Wholesale Rates:  Wholesale transmission revenues are based on rates and formulas that are approved by the FERC.  Most of PSNH’s wholesale transmission revenues are collected through a combination of the New England Regional Network Service (RNS) tariff and PSNH’s Local Network Service (LNS) tariff.  The RNS tariff, which is administered by the New England Independent System Operator (ISO-NE), recovers the revenue requirements associated with transmission facilities that are deemed by the FERC to be regional facilities.  This regional rate is reset on June 1 of each year.  The LNS tariff provides for the recovery of PSNH’s total transmission revenue requirements, net of revenues received from other sources, including those revenues received under RNS rates.  PSNH’s LNS tariff is reset on January 1 and June 1 of each year.  Additionally, PSNH’s LNS tariff provi des for a true-up to actual costs, which ensures that PSNH recovers its total transmission revenue requirements, including an allowed return on equity (ROE).  At December 31, 2005, this true-up has resulted in the recognition of a $0.6 million regulatory liability.  

Transmission Revenues - Retail Rates:  A significant portion of PSNH'S transmission business revenue comes from ISO-NE charges to PSNH's distribution business.  PSNH recovers these costs through the retail rates that are charged to its retail customers.  PSNH does not currently have a retail transmission rate tracking mechanism.   

F.

Derivative Instruments

PSNH has energy contracts that meet the definition of a derivative and qualify for the normal purchases and sales exception.  Derivatives under the normal purchases and sales exception and non derivative contracts are recorded at the time of delivery or settlement under accrual accounting.

PSNH also has derivative sales contracts that, although they may result in physical delivery, are included in operating expenses because these transactions are part of procurement activities.  Management believes that net classification in operating expenses best depicts these sales activities and is in accordance with Emerging Issues Task Force (EITF) Issue No. 03-11, "Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133, and Not 'Held for Trading Purposes' as Defined in Issue No. 02-3."

G.

Regulatory Accounting

The accounting policies of PSNH conform to accounting principles generally accepted in the United States of America applicable to rate-regulated enterprises and historically reflect the effects of the rate-making process in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation."

The transmission, distribution and generation businesses of PSNH continue to be cost-of-service rate regulated, and management believes that the application of SFAS No. 71 to those businesses continues to be appropriate.  Management also believes it is probable that PSNH will recover their investments in long-lived assets, including regulatory assets.  In addition, all material net regulatory assets are earning an equity return, except for securitized regulatory assets, which are not supported by equity, and substantial portions of the unrecovered contractual obligations.  New Hampshire’s electric utility industry restructuring laws have been modified to delay the sale of PSNH’s fossil and hydroelectric generation assets until at least April of 2006.  There has been no regulatory action to the contrary, and management currently has no plans to divest these generation assets.  As the NHPUC has allowed and is expected to continue to allow rate recovery of a return on and recovery of these assets, as well as all operating expenses, PSNH meets the criteria for the application of SFAS No. 71.  Generation costs that are not currently recovered in rates are deferred for future recovery.  Stranded costs related to generation assets are deferred for recovery as stranded costs under the "Agreement to Settle PSNH Restructuring" (Restructuring Settlement).  Part 3 stranded costs are non-securitized regulatory assets that must be recovered by a recovery end date determined in accordance with the Restructuring Settlement or be written off.  Based on current projections, PSNH expects to fully recover its Part 3 costs by the middle of 2006.  

Regulatory Assets:  The components of PSNH's regulatory assets are as follows:

	At December 31,
(Millions of Dollars)	2005	2004
Recoverable nuclear costs	$  26.1	$ 29.7
Securitized assets	375.0	421.6
Income taxes, net	35.9	37.5
Unrecovered contractual obligations	63.2	64.4
Recoverable energy costs	171.5	194.9
Other	150.3	152.0
Totals	$822.0	$900.1

Included in other regulatory assets above of $150.3 million at December 31, 2005 are the regulatory assets recorded associated with the implementation of FIN 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143," totaling $17.3 million which has been approved for deferred accounting treatment.  

Additionally, PSNH had $0.4 million and $0.1 million of regulatory costs at December 31, 2005 and 2004, respectively, that are included in deferred debits and other assets - other on the accompanying consolidated balance sheets.  These amounts represent regulatory costs that have not yet been approved by the NHPUC.  Management believes these costs are recoverable in future regulated rates.

Recoverable Nuclear Costs:  PSNH recorded a regulatory asset in conjunction with the sale of its share of Millstone 3 in March of 2001 with an unamortized balance of $26.1 million and $29.7 million at December 31, 2005 and 2004, respectively, which is included in recoverable nuclear costs.  

Securitized Assets:  In April of 2001, PSNH issued rate reduction bonds in the amount of $525 million.  PSNH used the majority of the proceeds from that issuance to buydown its affiliated power contracts with North Atlantic Energy Corporation (NAEC).  The unamortized PSNH securitized asset balance is $354.5 million and $392.2 million at December 31, 2005 and 2004, respectively.  In January of 2002, PSNH issued an additional $50 million in rate reduction bonds and used the proceeds from that issuance to repay short-term debt that was incurred to buyout a purchased-power contract in December of 2001.  The unamortized PSNH securitized asset balance for the January of 2002 issuance is $20.5 million and $29.4 million at December 31, 2005 and 2004, respectively.

Securitized assets are being recovered over the amortization period of their associated rate reduction bonds.  All outstanding rate reduction bonds of PSNH are scheduled to fully amortize by May 1, 2013.

Income Taxes, Net:  The tax effect of temporary differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of taxable income) is accounted for in accordance with the rate-making treatment of the NHPUC and SFAS No. 109, "Accounting for Income Taxes."  Differences in income taxes between SFAS No. 109 and the rate-making treatment of the NHPUC are recorded as regulatory assets which totaled $35.9 million and $37.5 million at December 31, 2005 and 2004, respectively.  For further information regarding income taxes, see Note 1H, "Summary of Significant Accounting Policies - Income Taxes," to the consolidated financial statements.

Unrecovered Contractual Obligations:  Under the terms of contracts with Connecticut Yankee Atomic Power Company (CYAPC), Yankee Atomic Energy Company (YAEC) and Maine Yankee Atomic Power Company (MYAPC) (Yankee Companies), PSNH is responsible for its proportionate share of the remaining costs of the units, including decommissioning.  These amounts which totaled $63.2 million and $64.4 million at December 31, 2005 and 2004, respectively, are recorded as unrecovered contractual obligations.  These amounts are being recovered along with other stranded costs.  As discussed in Note 4D, "Commitments and Contingencies - Deferred Contractual Obligations," substantial portions of the unrecovered contractual obligations regulatory assets have not yet been approved for recovery.  At this time management believes that these regulatory assets are probable of recovery.

Recoverable Energy Costs:  In conjunction with the implementation of restructuring under the Restructuring Settlement on May 1, 2001, PSNH's fuel and purchased-power adjustment clause (FPPAC) was discontinued.  At December 31, 2005 and 2004, PSNH had $127.5 million and $144.8 million, respectively, of recoverable energy costs deferred under the FPPAC.  Under the Restructuring Settlement, the FPPAC deferrals are recovered as a Part 3 stranded cost through a stranded cost recovery charge (SCRC).  Also included in PSNH's recoverable energy costs are deferred costs associated with certain contractual purchases from Independent Power Producers (IPPs).  These costs are also treated as Part 3 stranded costs and amounted to $44 million and $50.1 million at December 31, 2005 and 2004, respectively.

The majority of recoverable energy costs are currently recovered in rates from the customers of PSNH and are Part 3 stranded costs.  

Regulatory Liabilities:  PSNH had $414.6 million and $323.7 million of regulatory liabilities at December 31, 2005 and 2004, respectively, including revenues subject to refund.  These amounts are comprised of the following:

	At December 31,
(Millions of Dollars)	2005	2004
Cost of removal	$  85.7	$  87.6
Cumulative deferrals - SCRC	303.3	208.6
Other regulatory liabilities	25.6	27.5
Totals	$414.6	$323.7

Cost of Removal:  Under SFAS No. 71, PSNH currently recovers amounts in rates for future costs of removal of plant assets.  These amounts which totaled $85.7 million and $87.6 million at December 31, 2005 and 2004, respectively, are classified as regulatory liabilities on the accompanying consolidated balance sheets.  

Cumulative Deferrals - SCRC:  The cumulative deferrals accrued under the SCRC totaled $303.3 million and $208.6 million at December 31, 2005 and 2004, respectively, and will decrease the amount of non-securitized stranded costs to be recovered from PSNH's customers in the future.

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 NHPUC and SFAS No. 109.

Details of income tax expense are as follows:

	For the Years Ended December 31,
		2005	2004	2003
		(Millions of Dollars)
The components of the federal and state income tax provisions are:
Current income taxes:
Federal	$81.6		$37.2	$27.9
State	(1.0)		-	8.5
Total current	80.6		37.2	36.4
Deferred income taxes, net:
Federal	(60.5)		(17.7)	(3.8)
State	(7.5)		(6.0)	(2.3)
Total deferred	(68.0)		(23.7)	(6.1)
Investment tax credits, net	(0.4)		(0.5)	(0.5)
Total income tax expense	$12.2		$13.0	$29.8

A reconciliation between income tax expense and the expected tax expense at the statutory rate is as follows:

		For the Years Ended December 31,
		2005	2004	2003
	(Millions of Dollars)
Expected federal income tax expense		$18.9	$20.9	$26.3
Tax effect of differences:
Depreciation		0.2	1.3	1.1
Amortization of  regulatory assets		1.8	1.8	1.8
Investment tax credit amortization		(0.4)	(0.5)	(0.5)
State income taxes,     net of federal benefit		(5.5)	(3.9)	4.1
Parent company loss		-	(1.7)	-
Medicare subsidy		(1.1)	(0.2)	-
Other, net		(1.7)	(4.7)	(3.0)
Total income tax expense		$12.2	$13.0	$29.8

NU and its subsidiaries, including PSNH, file a consolidated federal income tax return.  NU and its subsidiaries, including PSNH, are parties to a tax allocation agreement under which taxable subsidiaries pay no more taxes than they would have otherwise paid had they filed a stand-alone tax return.  Subsidiaries generating tax losses are similarly paid for their losses when utilized.

The tax effects of temporary differences that give rise to the current and long-term net accumulated deferred tax obligations are as follows:

	At December 31,
(Millions of Dollars)	2005	2004
Deferred tax liabilities - current:
Property tax accruals	$  2.8	$   2.6
Deferred tax assets - current:
Provision for uncollectible accounts	0.9	0.7
Net deferred tax liabilities - current	1.9	1.9
Deferred tax liabilities - long-term:
Accelerated depreciation and      other plant-related differences	148.8	145.4
Securitized costs	137.0	154.1
Income tax gross-up	14.4	15.0
Deferred fuel and small power     producer costs	71.9	81.8
Other	68.9	68.2
Total deferred tax liabilities - long-term	441.0	464.5
Deferred tax assets - long-term:
Regulatory deferrals	156.2	124.1
Employee benefits	33.2	25.8
Income tax gross-up	0.9	0.9
Other	8.1	1.7
Total deferred tax assets - long-term	198.4	152.5
Net deferred tax liabilities - long-term	242.6	312.0
Net deferred tax liabilities	$244.5	$313.9

I.

Depreciation

The provision for depreciation on utility assets is calculated using the straight-line method based on the estimated remaining useful lives of depreciable plant-in-service, which range primarily from 14 years to 75 years, adjusted for salvage value and removal costs, as approved by the appropriate regulatory agency where applicable.  Depreciation rates are applied to plant-in-service from the time it is placed in service.  When plant is retired from service, the original cost of the plant, including costs of removal less salvage, is charged to the accumulated provision for depreciation.  Cost of removal is classified as a regulatory liability.  The depreciation rates for the several classes of electric utility plant-in-service are equivalent to a composite rate of 2.8 percent in 2005, 2.9 percent in 2004 and 3.0 percent in 2003.

J.

Jointly Owned Electric Utility Plant

At December 31, 2005, PSNH owns common stock in the Yankee Companies.  Each of the remaining Yankee Companies owns a single nuclear generating plant which is being decommissioned.  PSNH’s ownership interests in the Yankee Companies at December 31, 2005, which are accounted for on the equity method, are 5 percent of CYAPC, 7 percent of YAEC and 5 percent of MYAPC.  The total carrying value of CYAPC, MYAPC and YAEC, which is included in deferred debits and other assets - other on the accompanying consolidated balance sheets and the electric distribution reportable segment, totaled $3.8 million and $4 million at December 31, 2005 and 2004, respectively.  Earnings related to these equity investments are included in other income/(loss), net on the accompanying consolidated statements of income.  For further information, see Note 1N, "Other Income/(Loss), Net" to the consolidated financial st atements.  

CYAPC filed with the FERC to recover the increased estimate of decommissioning and plant closure costs.  The FERC proceeding is ongoing.  Management believes that the FERC proceeding has not impaired the value of its investment in CYAPC totaling $2.3 million at December 31, 2005 but will continue to evaluate the impacts that the FERC proceeding has on PSNH's investment.  For further information, see Note 4D, "Commitments and Contingencies - Deferred Contractual Obligations," to the consolidated financial statements.

K.

Allowance for Funds Used During Construction

The allowance for funds used during construction (AFUDC) is a non-cash item that is included in the cost of PSNH plant and represents the cost of borrowed and equity funds used to finance construction.  The portion of AFUDC attributable to borrowed funds is recorded as a reduction of other interest expense and the cost of equity funds is recorded as other income on the accompanying consolidated statements of income as follows:

	For the Years Ended December 31,
(Millions of Dollars, except percentages)	2005		2004		2003
Borrowed funds	$1.9		$ 0.3		$0.6
Equity funds	1.6		(0.1)		0.6
Totals	$3.5		$ 0.2		$1.2
Average AFUDC rate	5.2	%	2.7	%	3.9	%

The average AFUDC rate is based on a FERC-prescribed formula that develops an average rate using the cost of the company's short-term financings as well as the company's capitalization (long-term debt and common equity).  The average rate is applied to eligible construction work in progress amounts to calculate AFUDC.  The increase in the average AFUDC rate during 2005 is primarily due to increases in short-term and long-term debt interest rates.

L.

Asset Retirement Obligations

On January 1, 2003, PSNH implemented SFAS No. 143, "Accounting for Asset Retirement Obligations," requiring legal obligations associated with the retirement of property, plant and equipment to 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.  Management concluded that there were no asset retirement obligations (AROs) to be recorded upon implementation of SFAS No. 143.  

In March of 2005, the FASB issued FIN 47, required to be implemented by December 31, 2005.  FIN 47 requires an entity to recognize a liability for the fair value of an ARO even if it is conditional on a future event and the liability’s fair value can be reasonably estimated.  FIN 47 provides that settlement dates and future costs should be reasonably estimated when sufficient information becomes available, and provides guidance on the definition and timing of sufficient information in determining expected cash flows and fair values.  Management has completed its identification of conditional AROs and has identified various categories of AROs primarily certain assets containing asbestos and hazardous contamination.  A fair value calculation, reflecting expected probabilities for settlement scenarios, and a data consistency review across operating companies have been performed.  

PSNH utilized regulatory accounting in accordance with SFAS No. 71 and the impact of this implementation is included in other regulatory assets at December 31, 2005.  The fair value of the AROs is included in property, plant and equipment and related accretion is recorded as a regulatory asset, with corresponding credits reflecting the ARO liabilities in deferred credits and other liabilities - other, on the accompanying consolidated balance sheet at December 31, 2005.  Depreciation of the ARO asset is also included as a regulatory asset with an offsetting amount in accumulated depreciation.  

The following table presents the fair value of the ARO, the related accumulated depreciation, the regulatory asset, and the ARO liabilities:

	At December 31, 2005
(Millions of Dollars)	Fair Value of ARO Asset	Accumulated Depreciation of ARO Asset	Regulatory Asset	ARO Liabilities
Asbestos	$1.4	$(0.8)	$  8.6	$  (9.2)
Hazardous   contamination	0.5	(0.2)	1.7	(2.0)
Other AROs	0.4	(0.2)	7.0	(7.2)
Total  PSNH AROs	$2.3	$(1.2)	$17.3	$(18.4)

The ARO liabilities as of December 31, 2005, 2004 and January 1, 2004, as if FIN 47 had been applied for all periods affected, were $18.4 million, $18.2 million and $17.9 million, respectively.

M.

Fuel, Materials and Supplies

Fuel, materials and supplies include materials purchased primarily for construction, operation and maintenance (O&M) purposes.  Fuel, materials and supplies are valued at the lower of average cost or market.

N.

Other Income/(Loss), Net

The pre-tax components of PSNH’s other income/(loss) items are as follows:

	For the Years Ended December 31,
(Millions of Dollars)	2005	2004	2003
Other Income:
Investment income	$ 1.0	$ 0.3	$ 0.2
Equity in earnings of     regional nuclear     generating companies	0.2	0.2	0.4
AFUDC - equity funds	1.6	(0.1)	0.6
Gain on sale of property	1.1	2.0	0.3
Conservation and Load    Management Incentive	2.5	1.8	-
Other	0.3	0.3	0.8
Total Other Income	6.7	4.5	2.3
Other Loss:
Charitable donations	(0.5)	(0.5)	(0.4)
Advertising	(1.4)	(1.5)	(1.0)
Administrative fees for     rate reduction bonds	(1.5)	(1.5)	(1.7)
Lobbying costs	(0.6)	(0.5)	(0.6)
Other	(0.7)	(0.6)	(1.6)
Total Other Loss	(4.7)	(4.6)	(5.3)
Total Other     Income/(Loss), Net	$ 2.0	$(0.1)	$(3.0)

None of the amounts in either other income - other or other loss - other are individually significant as defined by the SEC.  

O.

Provision for Uncollectible Accounts

PSNH maintains a provision for uncollectible accounts to record its receivables at an estimated net realizable value.  This provision is determined based upon a variety of factors, including applying an estimated uncollectible account percentage to each receivables aging category, historical collection and write-off experience and management's assessment of collectibility from individual customers.   Management reviews at least quarterly the collectibility of the receivables, and if circumstances change, collectibility estimates are adjusted accordingly.  Receivable balances are written-off against the provision for uncollectible accounts when these balances are deemed to be uncollectible.  

P.

Severance Benefits

As a result of NU’s decision to pursue a fundamentally different business strategy, and align the structure of the company to support this business strategy, PSNH recorded a $0.8 million severance benefits charge in other operating expenses on the accompanying consolidated statement of income for the year ended December 31, 2005.

2.  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, the FERC, or by the NHPUC.  On June 30, 2004, the SEC granted authorization allowing PSNH to incur total short-term borrowings up to a maximum $100 million through June 30, 2007.  The SEC also granted authorization for borrowing through the NU Money Pool (Pool) until June 30, 2007.  Although PUHCA was repealed on February 8, 2006, under FERC's transition rules, all of the existing orders under PUHCA relevant to FERC authority will continue to be in effect until December 31, 2007, except for those related to NU, which will have no borrowing limitations after February 8, 2006. PSNH is authorized by the NHPUC to incur short-term borrowings up to a maximum of $100 million.  As a result of this NHPUC authorization, PSNH is not required to obtain SEC or FERC approval for its short-term debt borrowings.

Credit Agreement:  On December 9, 2005, PSNH amended its 5-year unsecured revolving credit facility by extending the expiration date by one year to November 6, 2010.  The company can borrow up to $100 million on a short-term basis, or subject to regulatory approvals, on a long-term basis.  At December 31, 2005, PSNH had no borrowings outstanding under this credit facility.  At December 31, 2004, there were $10 million in borrowings under this credit facility.  The weighted average interest rate of PSNH’s notes payable to banks outstanding on December 31, 2004 was 5.25 percent.  

Under this credit agreement, PSNH may borrow at variable rates plus an applicable margin based upon certain debt ratings, as rated by the higher of Standard and Poor’s (S&P) or Moody’s Investors Service (Moody's).  

Under this credit agreement, PSNH must comply with certain financial and non-financial covenants, including but not limited to consolidated debt ratios.  PSNH currently is and expects to remain in compliance with these covenants.

Amounts outstanding under this credit facility are classified as current liabilities as notes payable to banks on the accompanying consolidated balance sheets as management anticipates that all borrowings under this credit facility will be outstanding for no more than 364 days at one time.

Pool:  PSNH is a member of the Pool.  The Pool provides a more efficient use of 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, 2005 and 2004, PSNH had borrowings of $15.9 million and $20.4 million from the pool, respectively.  The interest rate on borrowings from the Pool at December 31, 2005 and 2004 was 4.09 percent and 2.24 percent, respectively.

3.   Pension Benefits and Postretirement Benefits Other Than Pensions   

Pension Benefits:  PSNH participates in a uniform noncontributory defined benefit retirement plan (Pension Plan) covering substantially all regular NU employees.  Benefits are based on years of service and the employees’ highest eligible compensation during 60 consecutive months of employment.  PSNH uses a December 31^st measurement date for the Pension Plan.  Pension expense attributable to earnings is as follows:

	For the Years Ended December 31,
(Millions of Dollars)	2005	2004	2003
Total pension expense	$19.2	$12.4	$ 6.8
Amount capitalized as utility plant	(4.9)	(3.4)	(2.0)
Total pension expense, net of   amounts capitalized	$14.3	$9.0	$ 4.8

Amounts above include pension curtailments of $1.1 million in 2005.  Not included in the pension expense above are amounts related to certain intercompany allocations totaling $2.2 million, $0.7 million and $(0.2) million for the years ended December 31, 2005, 2004 and 2003, respectively, including pension curtailment and termination benefit expenses of $0.6 million and $0.1 million for the years ended December 31, 2005 and 2004, respectively.  These amounts are included in other operating expenses on the accompanying consolidated financial statements.

Pension Curtailments:  On December 15, 2005, the NU Board of Trustees approved a benefit for new non-union employees hired on and after January 1, 2006 to receive retirement benefits under a new 401(k) benefit rather than under the Pension Plan.  Non-union employees actively employed on December 31, 2005 will be given the choice in 2006 to elect to continue participation in the Pension Plan or instead receive a new employer contribution under the 401(k) Savings Plan effective January 1, 2007.  If the new benefit is elected, their accrued pension liability in the Pension Plan will be frozen as of December 31, 2006.  Non-union employees will make this election in the second half of 2006.  This decision resulted in the recording of an estimated pre-tax curtailment expense of $1.1 million in 2005, as a certain number of employees are expected to elect the new 401(k) benefit, resulting in a reduction in aggregate esti mated future years of service under the Pension Plan.  Management estimated the amount of the curtailment expense associated with this change based upon actuarial calculations and certain assumptions, including the expected level of transfers to the new 401(k) benefit.

There were no curtailments or termination benefits in 2004 and 2003 that impacted earnings.

Market-Related Value of Pension Plan Assets:  PSNH bases the actuarial determination of pension plan expense or income on a market-related valuation of assets, which reduces year-to-year volatility.  This market-related valuation calculation recognizes investment gains or losses over a four-year period from the year in which they occur.  Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the fair value of assets.  Since the market-related valuation calculation recognizes gains or losses over a four-year period, the future value of the market-related assets will be impacted as previously deferred gains or losses are recognized.

Postretirement Benefits Other Than Pensions (PBOP):  PSNH also provides certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired employees (PBOP Plan).  These benefits are available for employees retiring from PSNH who have met specified service requirements.  For current employees and certain retirees, the total benefit is limited to two times the 1993 per retiree health care cost.  These costs are charged to expense over the estimated work life of the employee.  PSNH uses a December 31^st measurement date for the PBOP Plan.  

PSNH annually funds postretirement costs through external trusts with amounts that have been and will continue to be rate-recovered and which also are tax deductible.  Currently, there are no pending regulatory actions regarding postretirement benefit costs and there are no postretirement benefit costs that are deferred as regulatory assets.

Impact of New Medicare Changes on PBOP:  On December 8, 2003, the President signed into law a bill that expands Medicare, primarily by adding a prescription drug benefit starting in 2006 for Medicare-eligible retirees as well as a federal subsidy to plan sponsors of retiree health care benefit plans who provide a prescription drug benefit at least actuarially equivalent to the new Medicare benefit.

Based on the current PBOP Plan provisions, PSNH qualifies for this federal subsidy because the actuarial value of PSNH’s PBOP Plan exceeds the threshold required for the subsidy.  The Medicare changes decreased the PBOP benefit obligation by $5.4 million.  The total $5.4 million decrease is currently being amortized as a reduction to PBOP expense over approximately 13 years.  For the years ended December 31, 2005 and 2004, this reduction in PBOP expense totaled approximately $0.7 million, including amortization of the actuarial gain of $0.4 million and a reduction in interest cost and service cost based on a lower PBOP benefit obligation of $0.3 million.  

PBOP Curtailments and Termination Benefits:  PSNH had no curtailments or termination benefits in 2005, 2004 or 2003.

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)	2005	2004	2005	2004
Change in benefit obligation
Benefit obligation at beginning of year	$(324.1)	$(289.0)	$ (79.7)	$ (66.8)
Service cost	(8.8)	(7.5)	(1.6)	(1.3)
Interest cost	(19.3)	(17.9)	(4.4)	(4.3)
Transfers	(0.6)	(0.5)	-	(0.1)
Actuarial loss	(24.7)	(23.2)	(7.5)	(12.8)
Benefits paid	15.0	14.0	6.2	5.6
Curtailment/impact of plan changes	7.9	-	-	-
Benefit obligation at end of year	$(354.6)	$(324.1)	$ (87.0)	$ (79.7)
Change in plan assets
Fair value of plan assets at beginning of year	$ 201.6	$  191.9	$  34.6	$   29.7
Actual return on plan assets	15.1	23.2	2.1	2.9
Employer contribution	-	-	9.4	7.5
Transfers	0.6	0.5	-	0.1
Benefits paid	(15.0)	(14.0)	(6.2)	(5.6)
Fair value of plan assets at end of year	$  202.3	$  201.6	$   39.9	$   34.6
Funded status at December 31st	$(152.3)	$(122.5)	$ (47.1)	$ (45.1)
Unrecognized transition obligation	1.2	1.7	17.4	19.8
Unrecognized prior service cost	8.8	11.5	-	-
Unrecognized net loss	65.9	52.1	29.5	25.1
Accrued benefit cost	$ (76.4)	$  (57.2)	$   (0.2)	$   (0.2)

The $7.9 million reduction in the plan's obligation that is included in the curtailment/impact of plan changes relates to the reduction in the future years of service expected to be rendered by plan participants.  This reduction is the result of the transition of employees into the new 401(k) benefit.  This overall reduction in plan obligation serves to reduce the previously unrecognized actuarial losses.

The company amortizes its unrecognized transition obligation over the remaining service lives of its employees as calculated for PSNH on an individual operating company basis.  The company amortizes the unrecognized prior service cost and unrecognized net loss over the remaining service lives of its employees as calculated on an NU consolidated basis.

The accumulated benefit obligation (ABO) for the Pension Plan was $308.9 million and $270.7 million at December 31, 2005 and 2004, respectively.  Total pension plan assets on an NU consolidated basis were approximately $62 million and $225 million more than ABO at December 31, 2005 and 2004, respectively.  Under current accounting rules, if the ABO for the entire NU plan exceeds the entire NU Pension Plan assets at a future plan measurement date, PSNH will record its share of the additional minimum liability.  

The following actuarial assumptions were used in calculating the plans’ year end funded status:

	At December 31,
	Pension Benefits				Postretirement Benefits
Balance Sheets	2005		2004		2005		2004
Discount rate	5.80	%	6.00	%	5.65	%	5.50	%
Compensation/progression rate	4.00	%	4.00	%	N/A		N/A
Health care cost trend rate	N/A		N/A		7.00	%	8.00	%

The components of net periodic expense are as follows:

	For the Years Ended December 31,
	Pension Benefits			Postretirement Benefits
(Millions of Dollars)	2005	2004	2003	2005	2004	2003
Service cost	$ 8.8	$  7.4	$  6.4	$1.6	$1.2	$   1.1
Interest cost	19.3	17.9	17.3	4.4	4.3	4.5
Expected return on plan assets	(16.6)	(17.1)	(18.2)	(2.1)	(2.1)	(2.6)
Amortization of unrecognized net   transition obligation	0.3	0.3	0.3	2.5	2.5	2.5
Amortization of prior service cost	1.5	1.5	1.5	-	-	-
Amortization of actuarial loss/(gain)	4.8	2.4	(0.5)	-	-	-
Other amortization, net	-	-	-	3.0	1.6	0.7
Net periodic expense before curtailments	18.1	12.4	6.8	9.4	7.5	6.2
Curtailment expense	1.1	-	-	-	-	-
Total - net periodic expense	$19.2	$12.4	$ 6.8	$9.4	$7.5	$  6.2

For calculating pension and postretirement benefit expense amounts, the following assumptions were used:

	For the Years Ended December 31,
Statements of Income	Pension Benefits						Postretirement Benefits
	2005		2004		2003		2005		2004		2003
Discount rate	6.00	%	6.25	%	6.75	%	5.50	%	6.25	%	6.75	%
Expected long-term rate of return	8.75	%	8.75	%	8.75	%	N/A		N/A		N/A
Compensation/progression rate	4.00	%	3.75	%	4.00	%	N/A		N/A		N/A
Expected long-term rate of return -
Health assets, net of tax	N/A		N/A		N/A		6.85	%	6.85	%	6.85	%
Life assets and non-taxable     health assets	N/A		N/A		N/A		8.75	%	8.75	%	8.75	%

The following table represents the PBOP assumed health care cost trend rate for the next year and the assumed ultimate trend rate:

	Year Following December 31,
	2005		2004
Health care cost trend rate   assumed for next year	10.00	%	7.00	%
Rate to which health care   cost trend rate is assumed to   decline (the ultimate trend rate)	5.00	%	5.00	%
Year that the rate reaches   the ultimate trend rate	2011		2007

At December 31, 2004, the health care cost trend assumption was assumed to decrease by one percentage point each year through 2007.  For December 31, 2005 disclosure purposes, the health care cost trend assumption was reset for 2006 at 10 percent, decreasing one percentage point per year to an ultimate rate of 5 percent in 2011.  

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:

(Millions of Dollars)	One Percentage Point Increase	One Percentage Point Decrease
Effect on total service and   interest cost components	$0.2	$(0.1)
Effect on postretirement   benefit obligation	$3.2	$(2.8)

PSNH's investment strategy for its Pension Plan and PBOP Plan is to maximize the long-term rate of return on those plans' assets within an acceptable level of risk.  The investment strategy establishes target allocations, which are routinely reviewed and periodically rebalanced.  PSNH's expected long-term rates of return on Pension Plan assets and PBOP Plan assets are based on these target asset allocation assumptions and related expected long-term rates of return.  In developing its expected long-term rate of return assumptions for the Pension Plan and the PBOP Plan, PSNH also evaluated input from actuaries and consultants as well as long-term inflation assumptions and PSNH's historical 20-year compounded return of approximately 11 percent.  The Pension Plan's and PBOP Plan's target asset allocation assumptions and expected long-term rate of return assumptions by asset category are as follows:

	At December 31,
	Pension Benefits		Postretirement Benefits
	2005 and 2004		2005 and 2004
Asset Category	Target Asset Allocation	Assumed Rate of Return	Target Asset Allocation	Assumed Rate of Return
Equity securities:
United States	45%	9.25%	55%	9.25%
Non-United States	14%	9.25%	11%	9.25%
Emerging markets	3%	10.25%	2%	10.25%
Private	8%	14.25%	-	-
Debt Securities:
Fixed income	20%	5.50%	27%	5.50%
High yield fixed     income	5%	7.50%	5%	7.50%
Real estate	5%	7.50%	-	-

The actual asset allocations at December 31, 2005 and 2004, approximated these target asset allocations.  The plans’ actual weighted-average asset allocations by asset category are as follows:  

	At December 31,
	Pension Benefits		Postretirement Benefits
Asset Category	2005	2004	2005	2004
Equity securities:
United States	46%	47%	54%	55%
Non-United States	16%	17%	14%	14%
Emerging markets	4%	3%	1%	1%
Private	5%	4%	-	-
Debt Securities:
Fixed income	19%	19%	29%	28%
High yield fixed     income	5%	5%	2%	2%
Real estate	5%	5%	-	-
Total	100%	100%	100%	100%

Estimated Future Benefit Payments:  The following benefit payments, which reflect expected future service, are expected to be paid for the Pension and PBOP Plans:

(Millions of Dollars)
Year	Pension Benefits	Postretirement Benefits	Government Subsidy
2006	$ 15.3	$ 7.0	$0.7
2007	16.0	7.2	0.7
2008	16.7	7.2	0.8
2009	17.6	7.3	0.8
2010	18.4	7.4	0.8
2011-2015	106.1	37.5	5.2

Government subsidy represents amounts expected to be received from the federal government for the new Medicare prescription drug benefit under the PBOP plan.

Contributions:  PSNH does not expect to make any contributions to the Pension Plan in 2006 and expects to make $9.6 million in contributions to the PBOP Plan in 2006.  

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.

Postretirement health plan assets for non-union employees are subject to federal income taxes.

4.  Commitments and Contingencies   

A.

Regulatory Developments and Rate Matters

SCRC Reconciliation Filings:  The SCRC allows PSNH to recover its stranded costs.  On an annual basis, PSNH files with the NHPUC a SCRC reconciliation filing for the preceding calendar year.  This filing includes the reconciliation of stranded cost revenues and costs and Transition Energy Service Rate and Default Energy Service Rate, collectively referred to as Energy Service Rate (ES) revenues and costs.  The NHPUC reviews the filing, including a prudence review of the operations within PSNH's generation business segment.  The cumulative deferral of SCRC revenues in

excess of costs was $303.3 million at December 31, 2005.  This cumulative deferral will decrease the amount of non-securitized stranded costs to be recovered from PSNH's customers in the future from $368 million to $64.7 million.

The 2004 SCRC reconciliation filing was filed with the NHPUC on May 2, 2005.  In October of 2005, PSNH, the NHPUC staff and the New Hampshire Office of Consumer Advocate (OCA) reached a settlement agreement in this case.  The major provisions of this settlement agreement include the following: 1) PSNH will be allowed to recover its 2004 ES costs and stranded costs without disallowances, 2) PSNH will be allowed to include its cumulative unbilled revenues in its ES and stranded cost reconciliations and 3) the NHPUC will defer any action regarding PSNH’s coal supply and transportation procedures until it completes a review using an outside expert.  The NHPUC issued its order on December 22, 2005, approving the settlement agreement as filed.  While management believes its coal procurement and transportation policies and procedures are prudent and consistent with industry practice, it is unable to determine the impact, if any, of the expected NHPUC review on PSNH's net income or financial position.  

Litigation with IPPs:  Two wood-fired IPPs that sell their output to PSNH under long-term rate orders issued by the NHPUC brought suit against PSNH in state superior court.  The IPPs and PSNH dispute the end dates of the above-market long-term rates set forth in the respective rate orders.  Subsequent to the IPP's court filing, PSNH petitioned the NHPUC to decide this matter, and requested that the court stay its proceeding pending the NHPUC's decision.  By court order dated October 20, 2005, the court granted PSNH's motion to stay indicating that the NHPUC had primary jurisdiction over this matter.  

On November 11, 2005, the IPPs filed motions with the NHPUC seeking to disqualify two of the three NHPUC commissioners from participating in this proceeding.  As a result, the NHPUC chair excused himself from participating in this proceeding.  On December 7, 2005, the IPPs then filed an interlocutory appeal with the New Hampshire Supreme Court (Supreme Court) on the basis that the forum for resolving this dispute is in state superior court.  On December 27, 2005, PSNH and the New Hampshire Attorney General’s Office (representing the NHPUC) each filed motions for summary disposition with the Supreme Court.  On February 7, 2006, the Supreme Court declined to accept the IPP's interlocutory appeal.  As a result, the matter will return to the NHPUC for decision.  PSNH recovers the over market costs of IPP contracts through the SCRC.

Environmental Legislation:  The New Hampshire legislature is considering a bill in its 2006 legislative session that would place strict limitations on the level of mercury that PSNH’s existing generation plants can emit.  Legislation was first proposed in the 2005 session and passed by the New Hampshire senate in 2005 which would require PSNH to achieve fixed annual caps as early as 2009.  The bill was subsequently defeated by the New Hampshire House of Representatives early in 2006.  The legislature will now take up a new bill that requires PSNH to reduce power plant mercury emissions by at least 80 percent by 2013 while providing incentives for early reductions.  Management has been reviewing the proposed legislation.  PSNH's primary long-term alternative is to install wet scrubber equipment at its Merrimack Station at a cost of approximately $250 million.  PSNH’s other alternatives include the use of carbon injection pollution control equipment, reducing operating capacity of its plants and possible retirement or repowering of one or more of its generating units.  While state law and PSNH's restructuring agreement provide for the recovery of its generation costs, including the cost to comply with state environmental regulations, at this time management is unable to determine the impact of any potential new legislation on PSNH's net income or financial position.

B.

Environmental Matters

General:  PSNH is subject to environmental laws and regulations intended to mitigate or remove the effect of past operations and improve or maintain the quality of the environment.  These laws and regulations require the removal or the remedy of the effect on the environment of the disposal or release of certain specified hazardous substances at current and former operating sites.  As such, PSNH has an active environmental auditing and training program and believes that it is substantially in compliance with all enacted laws and regulations.

Environmental reserves are accrued using a probabilistic model approach when assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated.  The probabilistic model approach estimates the liability based on the most likely action plan from a variety of available remediation options, including no action is required or several different remedies ranging from establishing institutional controls to full site remediation and monitoring.  

These estimates are subjective in nature as they take into consideration several different remediation options at each specific site.  The reliability and precision of these estimates can be affected by several factors including new information concerning either the level of contamination at the site, recently enacted laws and regulations or a change in cost estimates due to certain economic factors.  

The amounts recorded as environmental liabilities on the consolidated balance sheets represent management’s best estimate of the liability for environmental costs and takes into consideration site assessment and remediation costs.  Based on currently available information for estimated site assessment and remediation costs at December 31, 2005 and 2004, PSNH had $6.2 million and $7.3 million, respectively, recorded as environmental reserves.  A reconciliation of the activity in these reserves at December 31, 2005 and 2004 is as follows:

	For the Years Ended December 31,
(Millions of Dollars)	2005	2004
Balance at beginning of year	$ 7.3	$9.8
Additions and adjustments	0.7	3.1
Payments	(1.8)	(5.6)
Balance at end of year	$ 6.2	$7.3

PSNH currently has 16 sites included in the environmental reserve.  Of those 16 sites, 10 sites are in the remediation or long-term monitoring phase, 2 sites have had some level of site assessment completed and the remaining 4 sites are in the preliminary stages of site assessment.   

For 2 sites that are included in the company's liability for environmental costs, the information known and nature of the remediation options at those sites allow an estimate of the range of losses to be made.  These sites primarily relate to manufactured gas plant (MGP) sites.  At December 31, 2005, $0.9 million has been accrued as a liability for these sites, which represents management's best estimate of the liability for environmental costs.  This amount differs from an estimated range of loss from $0.1 million to $4.4 million as management utilizes the probabilistic model approach to make its estimate of the liability for environmental costs.  

For the 14 remaining sites for which an estimate is based on the probabilistic model approach, determining an estimated range of estimated losses is not possible.   These liabilities are estimated on an undiscounted basis and do not assume that any amounts are recoverable from insurance companies or other third parties.  The environmental reserve includes sites at different stages of discovery and remediation and does not include any unasserted claims.  

At December 31, 2005, there are 2 sites for which there are unasserted claims; however, any related remediation costs are not probable or estimable at this time.  PSNH's environmental liability also takes into account recurring costs of managing hazardous substances and pollutants, mandated expenditures to remediate previously contaminated sites and any other infrequent and non-recurring clean up costs.

It is possible that new information or future developments could require a reassessment of the potential exposure to related environmental matters.  As this information becomes available, management will continue to assess the potential exposure and adjust the reserves accordingly.  

MGP Sites:  MGP sites comprise the largest portion of PSNH's environmental liability.  MGPs are sites that manufactured gas from coal which produced certain byproducts that may pose risk to human health and the environment.  PSNH currently has 7 MGP sites included in its environmental liability.  Of the 7 MGP sites, 5 sites are currently undergoing or have undergone remediation and 2 sites are in the preliminary stages of site assessment.  At December 31, 2005 and 2004, $5.3 million and $6.3 million, respectively, represents amounts for the site assessment and remediation of MGPs.  At December 31, 2005 and 2004, the 2 largest MGP sites comprise approximately 85 percent and 86 percent, respectively, of the total MGP environmental liability.  

CERCLA Matters:  The Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA) and its amendments or state equivalents impose joint and several strict liabilities, regardless of fault, upon generators of hazardous substances resulting in removal and remediation costs and environmental damages.  Liabilities under these laws can be material and in some instances may be imposed without regard to fault or for past acts that may have been lawful at the time they occurred.  PSNH has 2 superfund sites under CERCLA for which it has been notified that it is a potentially responsible party (PRP).  For sites where there are other PRPs and PSNH is not managing the site assessment and remediation, the liability accrued represents PSNH's estimate of what it will pay to settle its obligations with respect to the site.

It is possible that new information or future developments could require a reassessment of the potential exposure to related environmental matters.  As this information becomes available management will continue to assess the potential exposure and adjust the reserves accordingly.  

Rate Recovery:  PSNH has a rate recovery mechanism for environmental costs.  

C.

Long-Term Contractual Arrangements

Vermont Yankee Nuclear Power Corporation (VYNPC):  Previously under the terms of their agreements, PSNH paid their ownership (or entitlement) shares of costs, which included depreciation, O&M expenses, taxes, the estimated cost of decommissioning, and a return on invested capital to VYNPC and recorded these costs as purchased-power expenses.  On July 31, 2002, VYNPC consummated the sale of its nuclear generating unit to a subsidiary of Entergy Corporation for approximately $180 million.  PSNH has commitments to buy approximately 4 percent of the VYNPC plant’s output through March of 2012 at a range of fixed prices.  The total cost of purchases under contracts with VYNPC amounted to $6.4 million in 2005, $6.7 million in 2004 and $7.5 million in 2003.

Electricity Procurement Obligations:  PSNH has entered into various arrangements for the purchase of electricity.  The total cost of purchases under these arrangements amounted to $125.3 million in 2005, $121.1 million in 2004 and $122.8 million in 2003.  These amounts relate to IPP contracts and do not include PSNH’s short-term power supply management.

Portland Natural Gas Transmission System (PNGTS) Pipeline Commitments:  PSNH has a contract for capacity on the PNGTS pipeline which extends through 2018.  The total cost under this contract amounted to $1.6 million in 2005, $2 million in 2004 and $1.9 million in 2003.  These costs are not recovered from PSNH's retail customers.

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.  The total cost of this agreement amounted to $6.6 million in 2005, $7.4 million in 2004 and $7.9 million in 2003.  

Northern Wood Power Project:    In October of 2004, PSNH received the approvals necessary to begin construction related to the conversion of one of three 50 MW units at the coal-fired Schiller Station to burn wood (Northern Wood Power Project).  Construction of the $75 million Northern Wood Power Project began in 2004 and significant construction has been completed.  Certain other estimated construction expenditures totaling $3.8 million are not included in the contracts signed for the Northern Wood Power Project and are not included in the table of estimated future annual costs below.

Yankee Companies FERC-Approved Billings, Subject to Refund:  PSNH has significant decommissioning and plant closure cost obligations to the Yankee Companies.  Each plant has been shut down and is undergoing decommissioning.  The Yankee Companies collect decommissioning and closure costs through wholesale, FERC-approved rates charged under power purchase agreements with several New England utilities, including PSNH.  PSNH in turn passes these costs on to its customers through NHPUC approved retail rates.  YAEC and MYAPC received FERC approval to collect all presently estimated decommissioning and closure costs.  On November 23, 2005, YAEC submitted an application to the FERC to increase YAEC's wholesale decommissioning charges.  On January 31, 2006, the FERC issued an order accepting the rate increase, effective February 1, 2006, subject to refund after hearings and settlement judge proceedings.  CY APC received an order on August 30, 2004 from the FERC allowing collection of its decommissioning and closure costs, subject to refund.  The table of estimated future annual costs below includes the decommissioning and closure costs for YAEC, MYAPC and CYAPC.

Estimated Future Annual Costs:  The estimated future annual costs of PSNH’s significant long-term contractual arrangements are as follows:

(Millions of Dollars)	2006	2007	2008	2009	2010	Thereafter
VYNPC	$  7.1	$   6.9	$ 7.0	$ 7.6	$  7.3	$   9.3
Electricity procurement   contracts	122.5	52.6	27.6	27.8	28.0	185.0
PNGTS pipeline   commitments	2.0	2.0	2.0	2.0	2.0	15.9
Hydro-Quebec	7.3	6.9	6.8	6.7	6.7	66.7
Northern Wood   Power Project	6.5	- -	- -	-	- -	- -
Yankee Companies     FERC-approved billings,    subject to refund	13.2	10.2	9.0	8.1	7.8	- -
Totals	$158.6	$ 78.6	$52.4	$52.2	$51.8	$276.9

D.

Deferred Contractual Obligations

FERC Proceedings:  In 2003 the Connecticut Yankee Atomic Power Company (CYAPC) increased the estimated decommissioning and plant closure costs for the period 2000 through 2023 by approximately $395 million over the April 2000 estimate of $436 million approved by the FERC in a 2000 rate case settlement.  The revised estimate reflects the increases in the projected costs of spent fuel storage, increased security and liability and property insurance costs, and the fact that CYAPC is now self performing all work to complete the decommissioning of the plant due to the termination of the decommissioning contract with Bechtel Power Corporation (Bechtel) in July of 2003.  PSNH's share of CYAPC's increase in decommissioning and plant closure costs is approximately $20 million.  On July 1, 2004, CYAPC filed with the FERC for recovery seeking to increase its annual decommissioning collections from $16.7 million to $93 million for a six-year period beginning on January 1, 2005.  On August 30, 2004, the FERC issued an order accepting the rates, with collection beginning on February 1, 2005, subject to refund.

Both the Connecticut Department of Public Utility Control  (DPUC) and Bechtel filed testimony in the FERC proceeding claiming that CYAPC was imprudent in its management of the decommissioning project.  In its testimony, the DPUC recommended a disallowance of $225 million to $234 million out of CYAPC's requested rate increase of approximately $395 million.  PSNH's share of the DPUC's recommended disallowance would be between $11 million to $12 million.  The FERC staff also filed testimony that recommended a $38 million decrease in the requested rate increase claiming that CYAPC should have used a different gross domestic product (GDP) escalator.  PSNH's share of this recommended decrease is $1.9 million.  

On November 22, 2005, a FERC administrative law judge (ALJ) issued an initial decision finding no imprudence on CYAPC's part.  However, the ALJ did agree with the FERC staff’s position that a lower GDP escalator should be used for calculating the rate increase and found that CYAPC should recalculate its decommissioning charges to reflect the lower escalator.  Briefs to the full FERC addressing these issues were filed in January and February of 2006, and a final order is expected later in 2006.  Management expects that if the FERC staff's position on the decommissioning GDP cost escalator is found by the FERC to be more appropriate than that used by CYAPC to develop its proposed rates, then CYAPC would review whether to reduce its estimated decommissioning obligation and reduce the customers' obligation, including PSNH.

The company cannot at this time predict the timing or outcome of the FERC proceeding required for the collection of the increased CYAPC decommissioning costs.  The company believes that the costs have been prudently incurred and will ultimately be recovered from the customers of PSNH.  However, there is a risk that some portion of these increased costs may not be recovered, or will have to be refunded if recovered, as a result of the FERC proceedings.  

On June 10, 2004, the DPUC and the Connecticut Office of Consumer Counsel (OCC) filed a petition seeking a declaratory order that CYAPC be allowed to recover all decommissioning costs from its wholesale purchasers, including PSNH, but that such purchasers may not be allowed to recover in their retail rates any costs that the FERC might determine to have been imprudently incurred.  On August 30, 2004, the FERC denied this petition.  On September 29, 2004, the DPUC and OCC asked the FERC to reconsider the petition and on October 20, 2005, the FERC denied the reconsideration, holding that the sponsor companies are only obligated to pay CYAPC for prudently incurred decommissioning costs and the FERC has no jurisdiction over the sponsors' rates to their retail customers.  On December 12, 2005, the DPUC sought review of these orders by the United States Court of Appeals for the D.C. Circuit.  The FERC and the CYAPC have asked the court to d ismiss the case and the DPUC has objected to a dismissal.  PSNH cannot predict the timing or the outcome of these proceedings.  

Bechtel Litigation:  CYAPC and Bechtel commenced litigation in Connecticut Superior Court over CYAPC's termination of Bechtel's contract for the decommissioning of CYAPC's nuclear generating plant.  After CYAPC terminated the contract, responsibility for decommissioning was transitioned to CYAPC, which recommenced the decommissioning process.

On March 7, 2006, CYAPC and Bechtel executed a settlement agreement terminating this litigation.  Bechtel has agreed to pay CYAPC $15 million, and CYAPC will withdraw its termination of the contract for default and deem it terminated by agreement.

Spent Nuclear Fuel Litigation:  CYAPC, Yankee Atomic Energy Company (YAEC) and Maine Yankee Atomic Power Company (MYAPC) (Yankee Companies) also commenced litigation in 1998 charging that the federal government breached contracts it entered into with each company in 1983 under the Act.  Under the Act, the Department of Energy (DOE) was to begin removing spent nuclear fuel from the nuclear plants of the Yankee Companies no later than January 31, 1998 in return for payments by each company into the nuclear waste fund.  No fuel has been collected by the DOE, and spent nuclear fuel is stored on the sites of the Yankee Companies' plants.  The Yankee Companies collected the funds for payments into the nuclear waste fund from wholesale utility customers under FERC-approved contract rates.  The wholesale utility customers in turn collect these payments from their retail electric customers.  The Yankee Companies' individual da mage claims attributed to the government's breach ranging between $523 million and $543 million are specific to each plant and include incremental storage, security, construction and other costs through 2010.  The CYAPC damage claim ranges from $186 million to $198 million, the YAEC damage claim ranges from $177 million to $185 million and the MYAPC damage claim is $160 million.  The DOE trial ended on August 31, 2004 and a verdict has not been reached.  Post-trial findings of facts and final briefs were filed by the parties in January of 2005.  The Yankee Companies' current rates do not include an amount for recovery of damages in this matter.  Management can predict neither the outcome of this matter nor its ultimate impact on PSNH.

YAEC:   In November of 2005, YAEC established an updated estimate of the cost of completing the decommissioning of its plant resulting in an increase of approximately $85 million.  PSNH’s share of the increase in estimated costs is $6 million.  This estimate reflects the cost of completing site closure activities from October of 2005 forward and storing spent nuclear fuel and other high level waste on site until 2020.  This estimate projects a total cost of $192.1 million for the completion of decommissioning and long-term fuel storage.  To fund these costs, on November 23, 2005, YAEC submitted an application to the FERC to increase YAEC’s wholesale decommissioning charges.  The DPUC and the Massachusetts attorney general protested these increases.  On January 31, 2006, the FERC issued an order accepting the rate increase, effective February 1, 2006, subject to refund after hearings and s ettlement judge proceedings.  The hearings have been suspended pending settlement discussions between YAEC, the FERC and other intervenors in the case.  PSNH has a 7 percent ownership interest in YAEC and can predict neither the outcome of this matter nor its ultimate impact on PSNH.

5.  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, 2005
(Millions of Dollars)	Carrying Amount	Fair Value
Long-term debt -
First mortgage bonds	$100.0	$100.8
Other long-term debt	407.3	421.5
Rate reduction bonds	382.7	402.8

	At December 31, 2004
(Millions of Dollars)	Carrying Amount	Fair Value
Long-term debt -
First mortgage bonds	$ 50.0	$ 51.0
Other long-term debt	407.3	427.5
Rate reduction bonds	428.8	464.8

Other Financial Instruments:  The carrying value of financial instruments included in current assets and current liabilities approximates their fair value.  

6.  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.  Certain lease agreements contain contingent lease payments.  The contingent lease payments are based on various factors, such as the commercial paper rate plus a credit spread or the consumer price index.

Capital lease rental payments were $0.4 million in 2005 and 2004 and $0.5 million in 2003.  Interest included in capital lease rental payments was $0.2 million in 2005 and 2004 and $0.3 million in 2003.  Capital lease asset amortization was $0.2 million for the years ended December 31, 2005, 2004 and 2003.  

Operating lease rental payments charged to expense were $4.1 million in 2005, $3.6 million in 2004 and $3.3 million in 2003.  The capitalized portion of operating lease payments was approximately $1.8 million for the year ended December 31, 2005 and $1.7 million for the years ended December 31, 2004 and 2003.  

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, 2005 are as follows:

(Millions of Dollars)	Capital Leases	Operating Leases
2006	$ 0.3	$ 6.4
2007	0.2	5.3
2008	0.2	4.4
2009	-	2.8
2010	-	2.2
Thereafter	-	7.1
Future minimum lease payments	0.7	$28.2
Less amount representing interest	(0.2)
Present value of future minimum    lease payments	$ 0.5

7.  Dividend Restrictions  

The Federal Power Act and certain state statutes limit the payment of dividends by PSNH to its retained earnings balance.  At December 31, 2005, retained earnings available for payment of dividends is restricted to $232 million.

8.  Accumulated Other Comprehensive Income/(Loss)  

The accumulated balance for each other comprehensive income/(loss) item is as follows:

(Millions of Dollars)	December 31, 2004	Current Period Change	December 31, 2005
Unrealized gains   on securities	$  0.2	$   -	$  0.2
Minimum supplemental   executive retirement   pension liability   adjustments	(0.3)	0.2	(0.1)
Accumulated other   comprehensive   (loss)/income	$(0.1)	$0.2	$ 0.1

(Millions of Dollars)	December 31, 2003	Current Period Change	December 31, 2004
Unrealized gains    on securities	$0.1	$0.1	$  0.2
Minimum supplemental   executive retirement   pension liability   adjustments	(0.2)	(0.1)	(0.3)
Accumulated other   comprehensive loss	$(0.1)	$   -	$(0.1)

The changes in the components of other comprehensive (loss)/income are reported net of the following income tax effects:

(Millions of Dollars)	2005	2004	2003
Unrealized gains   on securities	$    -	$(0.1)	$(0.1)
Minimum supplemental   executive retirement   pension liability   adjustments	(0.1)	-	0.2
Accumulated other   comprehensive   (loss)/income	$(0.1)	$(0.1)	$ 0.1

The unrealized gains on securities above relate to $3.4 million and $3.3 million of Supplemental Executive Retirement Plan securities at December 31, 2005 and 2004, respectively, that are included in prepayments and other on the accompanying consolidated balance sheets.

9.  Long-Term Debt  

Details of long-term debt outstanding are as follows:

At December 31,	2005	2004
	(Millions of Dollars)
First Mortgage Bonds:
5.25% Series L, due 2014	$  50.0	$  50.0
5.60% Series M, due 2035	50.0	-
Total First Mortgage Bonds	$100.0	$ 50.0
Pollution Control Revenue Bonds:
6.00% Tax-Exempt, Series D,     due 2021	75.0	75.0
6.00% Tax-Exempt due 2021,      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
Total Pollution Control Revenue Bonds	$407.3	$407.3
Less amounts due within a year	-	-
Unamortized premiums and   discounts, net	(0.2)	(0.1)
Long-term debt	$507.1	$457.2

There are no cash sinking fund requirements or debt maturities for the years 2006 through 2010.  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) and loaned the proceeds to PSNH.  At both December 31, 2005 and 2004, $407.3 million of the PCRBs were outstanding.  PSNH’s obligation to repay each series of PCRBs is secured by bond insurance and by 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 weighted-average effective interest rate on PSNH's variable-rate pollution control notes was 2.51 percent for 2005 and 1.25 percent for 2004.  

PSNH's long-term debt agreements provide that it must comply with certain financial and non-financial covenants as are customarily included in such agreements.  PSNH currently is and expects to remain in compliance with these covenants.

On October 5, 2005, PSNH issued $50 million of first mortgage bonds with a fixed coupon of 5.60 percent and a maturity of October 5, 2035.  The proceeds of this issuance were used to refinance the company's short-term debt and to fund its capital needs.

10. Segment Information   

Segment information related to the distribution (including generation) and transmission businesses for PSNH for the years ended December 31, 2005, 2004, and 2003 is as follows (millions of dollars):

	For the Year Ended December 31, 2005
	Distribution	Transmission	Totals
Operating revenues	$1,091.9	$36.5	$1,128.4
Depreciation and   amortization	(233.6)	(4.3)	(237.9)
Other operating expenses	(774.6)	(17.7)	(792.3)
Operating income	83.7	14.5	98.2
Interest expense,   net of AFUDC	(43.9)	(2.4)	(46.3)
Interest income	0.3	0.1	0.4
Other income, net	1.6	-	1.6
Income tax expense	(7.8)	(4.4)	(12.2)
Net income	$     33.9	$  7.8	$      41.7
Total assets  (1)	$2,294.6	$      -	$2,294.6
Cash flows for total   investments in plant	$  131.9	$26.9	$   158.8

	For the Year Ended December 31, 2004
	Distribution	Transmission	Totals
Operating revenues	$ 937.9	$30.8	$   968.7
Depreciation and   amortization	(180.5)	(4.4)	(184.9)
Other operating expenses	(662.7)	(15.8)	(678.5)
Operating income	94.7	10.6	105.3
Interest expense,   net of AFUDC	(43.5)	(2.0)	(45.5)
Interest income	0.3	-	0.3
Other (loss)/income, net	(1.0)	0.5	(0.5)
Income tax expense	(10.6)	(2.4)	(13.0)
Net income	$     39.9	$   6.7	$     46.6
Total assets  (1)	$2,205.4	$       -	$2,205.4
Cash flows for total   investments in plant	$   123.1	$ 30.1	$   153.2

	For the Year Ended December 31, 2003
	Distribution	Transmission	Totals
Operating revenues	$   863.0	$25.2	$   888.2
Depreciation and   amortization	(118.2)	(3.0)	(121.2)
Other operating expenses	(633.1)	(10.3)	(643.4)
Operating income	111.7	11.9	123.6
Interest expense,   net of AFUDC	(44.8)	(0.4)	(45.2)
Interest income	0.2	-	0.2
Other loss, net	(3.0)	(0.2)	(3.2)
Income tax expense	(25.8)	(4.0)	(29.8)
Net income	$     38.3	$  7.3	$     45.6
Cash flows for total   investments in plant	$     78.2	$26.9	$  105.1

(1) Information for segmenting total assets between distribution and transmission is not available at December 31, 2005 or 2004.  The distribution and transmission assets are disclosed in the distribution columns above.  

Consolidated Quarterly Financial Data (Unaudited)
	Quarter Ended (a) (b)
(Thousands of Dollars)	March 31,	June 30,	September 30,	December 31,
2005
Operating Revenues	$268,891	$259,586	$307,305	$292,645
Operating Income	25,439	24,264	26,312	22,224
Net Income	8,788	9,063	11,921	11,967
2004
Operating Revenues	$244,148	$226,448	$258,876	$239,277
Operating Income	31,259	20,022	30,066	23,915
Net Income	11,760	6,025	18,239	10,617

Selected Consolidated Financial Data (Unaudited)
(Thousands of Dollars)	2005	2004	2003	2002	2001
Operating Revenues	$1,128,427	$   968,749	$   888,186	$   947,178	$   964,415
Net Income	41,739	46,641	45,624	62,897	81,776
Cash Dividends on Common Stock	42,383	27,186	16,800	45,000	27,000
Property, Plant and Equipment, net (c)	1,155,423	1,031,703	925,592	839,716	809,740
Total Assets (d)	2,294,583	2,205,374	2,171,181	2,155,447	2,094,514
Rate Reduction Bonds	382,692	428,769	472,222	510,841	507,381
Long-Term Debt (e)	507,086	457,190	407,285	407,285	407,285
Obligations Under Seabrook Power Contracts and   Other Capital Leases (e)	498	712	986	1,192	110,275

(a)

Certain reclassifications of prior years' data have been made to conform with the current year's presentation.

(b)

Quarterly operating income amounts differ from those previously reported as a result of the change in classification of certain costs that were not recoverable from regulated customers.  These amounts, previously presented in other income, net, have been reclassified to other operation expenses and are summarized as follows (thousands of dollars):  

Quarter Ended	2005	2004
March 31,	$110	$225
June 30,	254	212
September 30,	247	320

(c)

Amount includes construction work in progress.

(d)

Total assets were not adjusted for cost of removal prior to 2002.

(e)

Includes portions due within one year.  

Consolidated Statistics (Unaudited)
	2005	2004	2003	2002	2001
Revenues:  (Thousands)
Residential	$  450,230	$384,667	$351,622	$325,912	$323,642
Commercial	423,884	361,603	318,081	297,196	297,632
Industrial	190,299	175,921	159,560	150,582	175,575
Other Utilities	34,688	19,712	38,622	152,131	144,350
Streetlighting and Railroads	5,685	5,297	4,801	4,820	5,227
Miscellaneous	23,641	21,549	15,500	16,537	17,989
Total	$1,128,427	$968,749	$888,186	$947,178	$964,415
Sales:  (kWh - Millions)
Residential	3,162	3,015	2,944	2,765	2,592
Commercial	3,342	3,235	3,100	2,969	2,873
Industrial	1,612	1,716	1,684	1,646	1,926
Other Utilities	501	242	674	4,034	4,086
Streetlighting and Railroads	24	25	23	23	23
Total	8,641	8,233	8,425	11,437	11,500
Customers:  (Average)
Residential	408,959	403,088	388,133	382,481	376,832
Commercial	68,232	66,572	63,324	61,775	59,538
Industrial	2,768	2,783	2,758	2,818	2,863
Other	600	572	554	540	517
Total	480,559	473,015	454,769	447,614	439,750
Average Annual Use Per Residential Customer (kWh)	7,733	7,484	7,584	7,208	6,868
Average Annual Bill Per Residential Customer	$1,100.95	$954.96	$905.52	$849.10	$859.87
Average Revenue Per kWh:
Residential	14.24¢	12.76¢	11.94¢	11.78¢	12.52¢
Commercial	12.68	11.18	10.26	10.01	10.36
Industrial	11.81	10.25	9.48	9.15	9.12

EX-21

Exhibit 21

SUBSIDIARIES OF THE REGISTRANT

	State of Incorporation
Northeast Utilities (a Massachusetts business trust)	MA
The Connecticut Light and Power Company	CT
CL&P Funding LLC	DE
CL&P Receivables Corporation	CT
Holyoke Water Power Company	MA
Holyoke Power and Electric Company	MA
North Atlantic Energy Corporation	NH
North Atlantic Energy Service Corporation	NH
Northeast Nuclear Energy Company	CT
Northeast Utilities Service Company	CT
NU Enterprises, Inc.	CT
Select Energy Services, Inc.	MA
Select Energy Contracting, Inc.	MA
Mode 1 Communications, Inc.	CT
Northeast Generation Company	CT
Northeast Generation Services Company	CT
E. S. Boulos Company	CT
Woods Electrical Co., Inc.	CT
Select Energy, Inc.	CT
Select Energy New York, Inc.	DE
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

EX-23

Exhibit 23

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement Nos. 33-34622, 33-40156 and 333-128811 on Forms S-3 and Registration Statement Nos. 33-63023, 333-52413, 333-63144 and 333-123164 on Forms S-8 of our reports dated March 7, 2006 relating to the consolidated financial statements and consolidated financial statement schedules of Northeast Utilities (which reports express an unqualified opinion and include an explanatory paragraph regarding the Company’s recording of significant charges in connection with its decision to exit certain business lines and the reporting of certain components of the Company’s energy services businesses as discontinued operations), and our report dated March 7, 2006 on management's report on the effectiveness of internal control over financial reporting as of December 31, 2005, all appearing in and incorporated by reference in the Annual Report on Form 10-K of Northeast Utilities for the year ended December 31, 2005.

We consent to the incorporation by reference in Registration Statement Nos. 333-118276 of The Connecticut Light and Power Company, 333-116725 of Public Service Company of New Hampshire, and 333-126456 of Western Massachusetts Electric Company on Forms S-3 of our reports dated March 7, 2006, relating to the consolidated financial statements and consolidated financial statement schedules of The Connecticut Light and Power Company, Public Service Company of New Hampshire, and Western Massachusetts Electric Company (collectively, the "Companies"), all appearing in and incorporated by reference in the Annual Report on Form 10-K of the Companies for the year ended December 31, 2005.  

/s/	DELOITTE & TOUCHE LLP
	DELOITTE & TOUCHE LLP

Hartford, Connecticut

March 7, 2006

EX-31

Exhibit 31

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Charles W. Shivery, certify that:

1.

I have reviewed this Annual Report on Form 10-K of Northeast Utilities (the registrant);

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)

all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:  March 7, 2006

/s/	Charles W. Shivery
	(Signature)
	Charles W. Shivery
	Chairman, President and Chief Operating Officer
	(Principal Executive Officer)

EX-31

Exhibit 31

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Cheryl W. Grisé, certify that:

1.

I have reviewed this Annual Report on Form 10-K of The Connecticut Light and Power Company (the registrant);

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)

all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:  March 7, 2006

/s/	Cheryl W. Grisé
	(Signature)
	Cheryl W. Grisé
	Chief Executive Officer
	(Principal Executive Officer)

EX-31

Exhibit 31

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Cheryl W. Grisé, certify that:

1.

I have reviewed this Annual Report on Form 10-K of Public Service Company of New Hampshire (the registrant);

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)

all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:  March 7, 2006

/s/	Cheryl W. Grisé
	(Signature)
	Cheryl W. Grisé
	Chief Executive Officer
	(Principal Executive Officer)

EX-31

Exhibit 31

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Cheryl W. Grisé, certify that:

1.

I have reviewed this Annual Report on Form 10-K of Western Massachusetts Electric Company (the registrant);

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)

all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:  March 7, 2006

/s/	Cheryl W. Grisé
	(Signature)
	Cheryl W. Grisé
	Chief Executive Officer
	(Principal Executive Officer)

EX-31.1

Exhibit 31.1

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, David R. McHale, certify that:

1.

I have reviewed this Annual Report on Form 10-K of Northeast Utilities (the registrant);

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)

all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:  March 7, 2006

/s/	David R. McHale
	(Signature)
	David R. McHale
	Senior Vice President and Chief Financial Officer
	(Principal Executive Officer)

EX-31.1

Exhibit 31.1

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, David R. McHale, certify that:

1.

I have reviewed this Annual Report on Form 10-K of The Connecticut Light and Power Company (the registrant);

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)

all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:  March 7, 2006

/s/	David R. McHale
	(Signature)
	David R. McHale
	Senior Vice President and Chief Financial Officer
	(Principal Executive Officer)

EX-31.1

Exhibit 31.1

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, David R. McHale, certify that:

1.

I have reviewed this Annual Report on Form 10-K of Public Service Company of New Hampshire (the registrant);

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)

all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:  March 7, 2006

/s/	David R. McHale
	(Signature)
	David R. McHale
	Senior Vice President and Chief Financial Officer
	(Principal Executive Officer)

EX-31.1

Exhibit 31.1

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, David R. McHale, certify that:

1.

I have reviewed this Annual Report on Form 10-K of Western Massachusetts Electric Company (the registrant);

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)

all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:  March 7, 2006

/s/	David R. McHale
	(Signature)
	David R. McHale
	Senior Vice President and Chief Financial Officer
	(Principal Executive Officer)

EX-32

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Northeast Utilities (the registrant) on Form 10-K for the period ending December 31, 2005 as filed with the Securities and Exchange Commission (the Report), we, Charles W. Shivery, Chairman, President and Chief Executive Officer of the registrant and David R. McHale, Senior Vice President and Chief Financial Officer of the registrant, certify, pursuant to 18 U.S.C. Sec. 1350, as adopted pursuant to Sec. 906 of the Sarbanes-Oxley Act of 2002, that:

1)

The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2)

The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the registrant.

/s/	Charles W. Shivery
	(Signature)
	Charles W. Shivery
	Chairman, President and Chief Executive Officer

/s/	David R. McHale
	(Signature)
	David R. McHale
	Senior Vice President and Chief Financial Officer

Date:  March 7, 2006

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the registrant and will be retained by the registrant and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of The Connecticut Light and Power Company (the registrant) on Form 10-K for the period ending December 31, 2005 as filed with the Securities and Exchange Commission (the Report), we, Cheryl W. Grisé, Chief Executive Officer of the registrant and David R. McHale, Senior Vice President and Chief Financial Officer of the registrant, certify, pursuant to 18 U.S.C. Sec. 1350, as adopted pursuant to Sec. 906 of the Sarbanes-Oxley Act of 2002, that:

1)

The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2)

The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the registrant.

/s/	Cheryl W. Grisé
	(Signature)
	Cheryl W. Grisé
	Chief Executive Officer
	(Principal Executive Officer)

/s/	David R. McHale
	(Signature)
	David R. McHale
	Senior Vice President and Chief Financial Officer

Date:  March 7, 2006

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the registrant and will be retained by the registrant and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Public Service Company of New Hampshire (the registrant) on Form 10-K for the period ending December 31, 2005 as filed with the Securities and Exchange Commission (the Report), we, Cheryl W. Grisé, Chief Executive Officer of the registrant, and David R. McHale, Senior Vice President and Chief Financial Officer of the registrant, certify, pursuant to 18 U.S.C. Sec. 1350, as adopted pursuant to Sec. 906 of the Sarbanes-Oxley Act of 2002, that:

1)

The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2)

The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the registrant.

/s/	Cheryl W. Grisé
	(Signature)
	Cheryl W. Grisé
	Chief Executive Officer

/s/	David R. McHale
	(Signature)
	David R. McHale
	Senior Vice President and Chief Financial Officer

Date:  March 7, 2006

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the registrant and will be retained by the registrant and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Western Massachusetts Electric Company (the registrant) on Form 10-K for the period ending December 31, 2005 as filed with the Securities and Exchange Commission (the Report), we, Cheryl W. Grisé, Chief Executive Officer of the registrant, and David R. McHale, Senior Vice President and Chief Financial Officer of the registrant, certify, pursuant to 18 U.S.C. Sec. 1350, as adopted pursuant to Sec. 906 of the Sarbanes-Oxley Act of 2002, that:

1)

The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2)

The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the registrant.

/s/	Cheryl W. Grisé
	(Signature)
	Cheryl W. Grisé
	Chief Executive Officer

/s/	David R. McHale
	(Signature)
	David R. McHale
	Senior Vice President and Chief Financial Officer

Date:  March 7, 2006

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the registrant and will be retained by the registrant and furnished to the Securities and Exchange Commission or its staff upon request.

EX-99.1

		Exhibit 99.1
NORTHEAST GENERATION COMPANY
BALANCE SHEETS
At December 31,	2005	2004
	(Thousands of Dollars)
ASSETS
Current Assets:
Cash and cash equivalents	$             16,117	$             13,634
Accounts receivable from affiliated companies	14,102	14,060
Notes receivable from affiliated companies	10,000	10,000
Taxes receivable	2,958	1,977
Materials and supplies, at average cost	2,505	2,359
Prepayments and other	1,274	1,761
	46,956	43,791
Property, Plant and Equipment:
Competitive energy	845,524	839,927
Less: Accumulated depreciation	47,286	37,077
	798,238	802,850
Construction work in progress	8,083	3,563
	806,321	806,413
Deferred Debits and Other Assets:
Debt service special deposits	-	31,819
Other	4,698	6,751
	4,698	38,570
Total Assets	$           857,975	$           888,774

NORTHEAST GENERATION COMPANY
BALANCE SHEETS
At December 31,	2005	2004
	(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION
Current Liabilities:
Long-term debt - current portion	$                  -	$             37,500
Accounts payable	2,414	2,662
Accounts payable to affiliated companies	2,800	2,160
Accrued taxes	2,372	648
Accrued interest	5,875	6,341
Other	4,831	3,752
	18,292	53,063
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	84,620	62,983
Other	866	-
	85,486	62,983
Capitalization:
Long-Term Debt	320,000	320,000
Common Stockholder's Equity:
Common stock, $1 par value - authorized
20,000 shares; 6 shares outstanding
in 2005 and 2004	-	-
Capital surplus, paid in	408,023	408,094
Retained earnings	27,113	45,782
Accumulated other comprehensive loss	(939)	(1,148)
Common Stockholder's Equity	434,197	452,728
Total Capitalization	754,197	772,728
Total Liabilities and Capitalization	$       857,975	$           888,774

NORTHEAST GENERATION COMPANY
STATEMENTS OF INCOME
For the Years Ended December 31,	2005	2004
	(Thousands of Dollars)
Operating Revenues	$        154,934	$         153,891
Operating Expenses:
Operation -
Operation, maintenance and fuel	29,633	31,864
Depreciation and amortization	10,584	10,286
Taxes other than income taxes	9,484	9,487
Total operating expenses	49,701	51,637
Operating Income	105,233	102,254
Interest Expense:
Interest on long-term debt	31,143	32,623
Other interest	28	38
Interest expense, net	31,171	32,661
Other Income, Net	1,743	1,074
Income Before Income Tax Expense	75,805	70,667
Income Tax Expense	29,959	28,651
Income Before Cumulative Effect of
Accounting Change, Net of Tax Benefit	45,846	42,016
Cumulative effect of accounting change,
net of tax benefit $346	(515)	-
Net Income	$          45,331	$          42,016
STATEMENTS OF COMPREHENSIVE INCOME
Net Income	$          45,331	$          42,016
Other comprehensive income from
qualified cash flow hedging instruments, net of tax	209	264
Comprehensive Income	$          45,540	$          42,280

NORTHEAST GENERATION COMPANY
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
					Accumulated
			Capital		Other
	Common Stock		Surplus,	Retained	Comprehensive
	Shares	Amount	Paid In	Earnings	(Loss)/Income	Total
		(Thousands of Dollars, except share information)
Balance at January 1, 2004	6	$               -	$     408,095	$        31,766	$              (1,412)	$      438,449
Net income for 2004				42,016		42,016
Cash dividends on common stock				(28,000)		(28,000)
Allocation of benefits - ESOP			(1)			(1)
Other comprehensive income					264	264
Balance at December 31, 2004	6	-	408,094	45,782	(1,148)	452,728
Net income for 2005				45,331		45,331
Cash dividends on common stock				(64,000)		(64,000)
Allocation of benefits - ESOP			(1)			(1)
Allocation of NU parent company tax benefit			(70)			(70)
Other comprehensive income					209	209
Balance at December 31, 2005	6	$               -	$     408,023	$        27,113	$                 (939)	$      434,197

NORTHEAST GENERATION COMPANY
STATEMENTS OF CASH FLOWS
For the Years Ended December 31,	2005	2004
	(Thousands of Dollars)
Operating Activities:
Net income	$               45,331	$              42,016
Adjustments to reconcile to net cash flows
provided by operating activities:
Depreciation and amortization	10,584	10,286
Deferred income taxes	21,823	22,184
Other non-cash adjustments	2,550	(1,432)
Other sources of cash	3	-
Changes in current assets and liabilities:
Accounts receivable	(42)	(1,072)
Materials and supplies	(146)	(48)
Other current assets	487	(1,012)
Accounts payable	342	1,282
Accrued taxes	743	(1,775)
Accrued interest	(466)	-
Other current liabilities	1,288	3,245
Net cash flows provided by operating activities	82,497	73,674
Investing Activities:
Investments in competitive energy plant	(10,333)	(11,788)
Investment in debt service special deposits	31,819	(1,615)
Net cash flows provided by/(used in) investing activities	21,486	(13,403)
Financing Activities:
Retirement of long-term debt	(37,500)	(31,500)
Cash dividends on common stock	(64,000)	(28,000)
Net cash flows used in financing activities	(101,500)	(59,500)
Net increase in cash and cash equivalents	2,483	771
Cash and cash equivalents - beginning of year	13,634	12,863
Cash and cash equivalents - end of year	$               16,117	$              13,634
Supplemental Cash Flow Information:
Cash paid during the year for:
Interest, net of amounts capitalized of $395 in 2005
and $599 in 2004	$               30,495	$              32,506
Income taxes	$                 8,427	$                9,798