10-Q

____________________________________________________________________________________

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-Q

[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE      SECURITIES EXCHANGE ACT OF 1934
	For the Quarterly Period Ended March 31, 2006
	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

____________________________________________________________________________________

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

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

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

Company - Class of Stock	Outstanding at April 30, 2006
Northeast Utilities Common stock, $5.00 par value	153,564,466 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

GLOSSARY OF TERMS
The following is a glossary of frequently used abbreviations or acronyms that are found in this report.
NU COMPANIES,  SEGMENTS OR INVESTMENTS:
CL&P	The Connecticut Light and Power Company
CRC	CL&P Receivables Corporation
HWP	Holyoke Water Power Company
Mt. Tom	Mount Tom generating plant
NGC	Northeast Generation Company
NGS	Northeast Generation Services Company
NU or the company	Northeast Utilities
NU Enterprises	At March 31, 2006, NU’s competitive subsidiaries including the merchant energy segment, which is comprised of Select Energy, NGC, NGS and the generation operations of Mt. Tom and the energy services segment, which is comprised of E.S. Boulos Company, Woods Electrical Co. Inc., and NGS Mechanical, Inc., which are subsidiaries of NGS, SESI, SECI, HEC/Tobyhanna Energy Project, Inc. and HEC/CJTS Energy Center LLC.  For further information, see Note 12, "Segment Information," to the condensed consolidated financial statements.
PSNH	Public Service Company of New Hampshire
SECI	Select Energy Contracting, Inc.
Select Energy	Select Energy, Inc. (including its wholly owned subsidiary SENY)
SENY	Select Energy New York, Inc.
SESI	Select Energy Services, Inc.
Utility Group	NU’s regulated utilities comprised of the electric distribution and transmission businesses of CL&P, PSNH, WMECO, the generation business of PSNH and the gas distribution business of Yankee Gas.  For further information, see Note 12 "Segment Information," to the condensed consolidated financial statements.
WMECO	Western Massachusetts Electric Company
Yankee	Yankee Energy System, Inc.
Yankee Gas	Yankee Gas Services Company
THIRD PARTIES:
Bechtel	Bechtel Power Corporation
CYAPC	Connecticut Yankee Atomic Power Company
Globix	Globix Corporation
NRG	NRG Energy, Inc.
REGULATORS:
CSC	Connecticut Siting Council
DPUC	Connecticut Department of Public Utility Control
DTE	Massachusetts Department of Telecommunications and Energy
FERC	Federal Energy Regulatory Commission
NHPUC	New Hampshire Public Utilities Commission
SEC	Securities and Exchange Commission

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OTHER:
AFUDC	Allowance For Funds Used During Construction
CTA	Competitive Transition Assessment
EPS	Earnings Per Share
FASB	Financial Accounting Standards Board
FMCC	Federally Mandated Congestion Cost
GSC	Generation Service Charge
ISO-NE	New England Independent System Operator
KWh	Kilowatt-Hour
Kv	Kilovolt
LICAP	Locational Installed Capacity
LMP	Locational Marginal Pricing
LOCs	Letters of Credit
MW	Megawatt/Megawatts
NU 2005 Form 10-K	The Northeast Utilities and Subsidiaries combined 2005 Form 10-K as filed with the SEC
NYMEX	New York Mercantile Exchange
OCC	Connecticut Office of Consumer Counsel
RMR	Reliability Must Run
ROE	Return on Equity
RTO	Regional Transmission Organization
SBC	System Benefits Charge
SCRC	Stranded Cost Recovery Charge
SFAS	Statement of Financial Accounting Standards
ES	Transition Energy Service/Default Energy Service
TSO	Transitional Standard Offer

ii

NORTHEAST UTILITIES AND SUBSIDIARIES
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

TABLE OF CONTENTS

	Page
PART I - FINANCIAL INFORMATION
ITEM 1 - Condensed Consolidated Financial Statements for the Following Companies:
Northeast Utilities and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited) – March 31, 2006 and December 31, 2005	2
Condensed Consolidated Statements of Loss (Unaudited) - Three Months Ended March 31, 2006 and 2005	4
Condensed Consolidated Statements of Cash Flows (Unaudited) - Three Months Ended March 31, 2006 and 2005	5
Notes to Condensed Consolidated Financial Statements (unaudited - all companies)	6
Report of Independent Registered Public Accounting Firm	34
The Connecticut Light and Power Company and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited) - March 31, 2006 and December 31, 2005	36
Condensed Consolidated Statements of Income (Unaudited) - Three Months Ended March 31, 2006 and 2005	38
Condensed Consolidated Statements of Cash Flows (Unaudited) - Three Months Ended March 31, 2006 and 2005	39
Public Service Company of New Hampshire and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited) - March 31, 2006 and December 31, 2005	42
Condensed Consolidated Statements of Income (Unaudited) - Three Months Ended March 31, 2006 and 2005	44
Condensed Consolidated Statements of Cash Flows (Unaudited) - Three Months Ended March 31, 2006 and 2005	45
Western Massachusetts Electric Company and Subsidiary
Condensed Consolidated Balance Sheets (Unaudited) - March 31, 2006 and December 31, 2005	48
Condensed Consolidated Statements of Income (Unaudited) - Three Months Ended March 31, 2006 and 2005	50
Condensed Consolidated Statements of Cash Flows (Unaudited) - Three Months Ended March 31, 2006 and 2005	51

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	Page
ITEM 2 - Management's Discussion and Analysis of Financial Condition and Results of Operations for the Following  Companies:
Northeast Utilities and Subsidiaries		52
The Connecticut Light and Power Company and Subsidiaries		78
Public Service Company of New Hampshire and Subsidiaries		81
Western Massachusetts Electric Company and Subsidiary		83
ITEM 3 - Quantitative and Qualitative Disclosures About Market Risk		85
ITEM 4 - Controls and Procedures		87
PART II - OTHER INFORMATION
ITEM 1 - Legal Proceedings		88
ITEM 1A - Risk Factors		88
ITEM 2 - Unregistered Sales of Equity Securities and Use of Proceeds		92
ITEM 6 – Exhibits		92
SIGNATURES		94

iv

NORTHEAST UTILITIES AND SUBSIDIARIES

1

NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,	December 31,
	2006	2005
	(Thousands of Dollars)
ASSETS
Current Assets:
Cash and cash equivalents	$             36,268	$             45,782
Special deposits	54,832	103,789
Investments in securitizable assets	241,652	252,801
Receivables, less provision for uncollectible
accounts of $22,425 in 2006 and $24,444 in 2005	544,547	901,516
Unbilled revenues	172,188	175,853
Taxes receivable	146,703	-
Fuel, materials and supplies	134,738	206,557
Marketable securities	65,730	56,012
Derivative assets - current	198,071	403,507
Prepayments and other	88,371	129,242
Assets held for sale	992,109	101,784
	2,675,209	2,376,843
Property, Plant and Equipment:
Electric utility	6,491,305	6,378,838
Gas utility	835,449	825,872
Competitive energy	11,050	908,776
Other	267,977	254,659
	7,605,781	8,368,145
Less: Accumulated depreciation	2,501,402	2,551,322
	5,104,379	5,816,823
Construction work in progress	624,095	600,407
	5,728,474	6,417,230
Deferred Debits and Other Assets:
Regulatory assets	2,523,165	2,483,851
Goodwill	287,591	287,591
Prepaid pension	285,856	298,545
Marketable securities	52,705	56,527
Derivative assets - long-term	350,529	425,049
Other	231,047	223,439
	3,730,893	3,775,002
Total Assets	$      12,134,576	$      12,569,075
The accompanying notes are an integral part of these condensed consolidated financial statements.

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NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,	December 31,
	2006	2005
	(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION
Current Liabilities:
Notes payable to banks	$           270,000	$             32,000
Long-term debt - current portion	26,995	22,673
Accounts payable	691,103	972,368
Accrued taxes	842	95,210
Accrued interest	44,836	47,742
Derivative liabilities - current	241,553	402,530
Counterparty deposits	12,906	28,944
Other	271,869	272,252
Liabilities of assets held for sale	504,814	101,511
	2,064,918	1,975,230
Rate Reduction Bonds	1,296,693	1,350,502
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	1,422,314	1,306,340
Accumulated deferred investment tax credits	94,526	95,444
Deferred contractual obligations	333,144	358,174
Regulatory liabilities	1,181,883	1,273,501
Derivative liabilities - long-term	198,794	272,995
Other	347,994	364,157
	3,578,655	3,670,611
Capitalization:
Long-Term Debt	2,699,981	3,027,288
Preferred Stock of Subsidiary - Non-Redeemable	116,200	116,200
Common Shareholders' Equity:
Common shares, $5 par value - authorized
225,000,000 shares; 175,078,083 shares issued
and 153,534,829 shares outstanding in 2006 and
174,897,704 shares issued and 153,225,892 shares
outstanding in 2005	875,390	874,489
Capital surplus, paid in	1,439,180	1,437,561
Deferred contribution plan - employee stock
ownership plan	(43,280)	(46,884)
Retained earnings	466,954	504,301
Accumulated other comprehensive income	621	19,987
Treasury stock, 19,672,653 shares in 2006
and 19,645,511 shares in 2005	(360,736)	(360,210)
Common Shareholders' Equity	2,378,129	2,429,244
Total Capitalization	5,194,310	5,572,732
Commitments and Contingencies (Note 7)
Total Liabilities and Capitalization	$      12,134,576	$      12,569,075
The accompanying notes are an integral part of these condensed consolidated financial statements.

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NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF LOSS
(Unaudited)
	Three Months Ended
	March 31,
	2006	2005
	(Thousands of Dollars,
	except share information)
Operating Revenues	$        2,147,388	$        2,232,964
Operating Expenses:
Operation -
Fuel, purchased and net interchange power	1,537,200	1,669,162
Other	308,771	245,099
Wholesale contract market changes, net	6,830	188,892
Restructuring and impairment charges	5,143	21,534
Maintenance	38,421	36,303
Depreciation	58,766	55,134
Amortization	59,717	23,093
Amortization of rate reduction bonds	48,678	45,790
Taxes other than income taxes	76,425	74,194
Total operating expenses	2,139,951	2,359,201
Operating Income/(Loss)	7,437	(126,237)
Interest Expense:
Interest on long-term debt	35,351	30,223
Interest on rate reduction bonds	19,881	23,038
Other interest	6,000	3,084
Interest expense, net	61,232	56,345
Other Income, Net	16,205	5,906
Loss from Continuing Operations Before
Income Tax Benefit	(37,590)	(176,676)
Income Tax Benefit	(18,305)	(64,770)
Loss from Continuing Operations Before
Preferred Dividends of Subsidiary	(19,285)	(111,906)
Preferred Dividends of Subsidiary	1,390	1,390
Loss from Continuing Operations	(20,675)	(113,296)
Discontinued Operations:
Income/(Loss) from Discontinued Operations,
Before Income Taxes	17,583	(7,005)
Income Tax Expense/(Benefit)	7,014	(2,582)
Income/(Loss) from Discontinued Operations	10,569	(4,423)
Net Loss	$           (10,106)	$         (117,719)
Basic and Fully Diluted Loss Per Common Share:
Loss from Continuing Operations	$               (0.13)	$              (0.88)
Income/(Loss) from Discontinued Operations	0.06	(0.03)
Basic and Fully Diluted Loss Per Common Share	$               (0.07)	$               (0.91)
Basic Common Shares Outstanding (average)	153,442,640	129,278,505
Fully Diluted Common Shares Outstanding (average)	153,442,640	129,278,505
The accompanying notes are an integral part of these condensed consolidated financial statements.

4

NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Three Months Ended
	March 31,
	2006	2005
	(Thousands of Dollars)
Operating Activities:
Net loss	$                (10,106)	$              (117,719)
Adjustments to reconcile to net cash flows
provided by operating activities:
Wholesale contract market changes, net	4,313	174,692
Restructuring and impairment charges	1,228	45,547
Bad debt expense	8,766	9,029
Depreciation	61,720	57,998
Deferred income taxes	171,578	(16,306)
Amortization	59,717	23,093
Amortization of rate reduction bonds	48,678	45,790
(Deferral)/amortization of recoverable energy costs	(52,085)	1,094
Pension expense	10,256	8,030
Regulatory refunds	(124,048)	(26,256)
Derivative assets and liabilities	(33,372)	(16,476)
Deferred contractual obligations	(25,030)	(19,996)
Other non-cash adjustments	(14,288)	(75,296)
Other sources of cash	2,863	4,766
Other uses of cash	(17,650)	(4,384)
Changes in current assets and liabilities:
Receivables and unbilled revenues, net	358,108	(72,195)
Fuel, materials and supplies	50,728	41,941
Investments in securitizable assets	11,149	(50,288)
Other current assets	56,300	92,611
Accounts payable	(255,189)	64,701
Counterparty deposits	(16,038)	37,998
(Taxes receivable)/accrued taxes	(239,525)	3,655
Other current liabilities	(15,347)	(22,922)
Net cash flows provided by operating activities	42,726	189,107
Investing Activities:
Investments in property and plant:
Electric, gas and other utility plant	(198,809)	(161,060)
Competitive energy assets	(5,016)	(5,760)
Cash flows used for investments in property and plant	(203,825)	(166,820)
Proceeds from sales of investment securities	18,335	18,738
Purchases of investment securities	(19,153)	(19,391)
Other investing activities	(5,501)	(6,036)
Net cash flows used in investing activities	(210,144)	(173,509)
Financing Activities:
Issuance of common shares	3,202	3,984
Retirement of rate reduction bonds	(53,809)	(50,338)
Increase in short-term debt	238,000	87,000
Reacquisitions and retirements of long-term debt	(2,649)	(9,121)
Cash dividends on common shares	(27,241)	(21,005)
Other financing activities	401	914
Net cash flows provided by financing activities	157,904	11,434
Net (decrease)/increase in cash and cash equivalents	(9,514)	27,032
Cash and cash equivalents - beginning of period	45,782	46,989
Cash and cash equivalents - end of period	$                 36,268	$                 74,021
The accompanying notes are an integral part of these condensed consolidated financial statements.

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NORTHEAST UTILITIES AND SUBSIDIARIES

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

1.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (All Companies)

A.

Presentation

Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission (SEC).  The accompanying unaudited condensed consolidated financial statements should be read in conjunction with this complete report on Form 10-Q and the Annual Reports of Northeast Utilities (NU or the company), The Connecticut Light and Power Company (CL&P), Public Service Company of New Hampshire (PSNH), and Western Massachusetts Electric Company (WMECO), which were filed as part of the Northeast Utilities and subsidiaries combined 2005 Form 10-K (NU 2005 Form 10-K) with the SEC.  The accompanying condensed consolidated financial statements contain, in the opinion of management, all adjustments (including normal, recurring adjustments) necessary to present fairly NU's and the above companies' financial position at March 31, 2006, and the results of operations and cash flows for the three months ended March 31, 2006 and 2005.  The results of operations and statements of cash flows for the three months ended March 31, 2006 and 2005 are not necessarily indicative of the results expected for a full year.  

The condensed 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 condensed 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 condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.

In NU’s condensed consolidated statement of loss and CL&P's, PSNH's and WMECO's condensed consolidated statements of income for the three months ended March 31, 2005, the classification of certain expense amounts previously included in other income, net was changed.  These expense amounts which were reclassified to other operation expense for the three months ended March 31, 2005 for NU, CL&P, PSNH and WMECO totaled $5.1 million, $0.8 million, $0.9 million, and $0.1 million, respectively.

NU’s condensed consolidated statements of loss for the three months ended March 31, 2006 and 2005 present the operations for the following as discontinued operations:

·

Northeast Generation Company (NGC),

·

The Mt. Tom generating plant (Mt. Tom) owned by Holyoke Water Power Company (HWP),

·

Select Energy Service, Inc. (SESI) and its wholly owned subsidiaries HEC/Tobyhanna Energy Project, Inc. and HEC/CJTS Energy Center LLC,

·

Woods Electrical Co., Inc. (Woods Electrical),

·

Select Energy Contracting, Inc. - New Hampshire (SECI-NH) (including Reeds Ferry Supply Co., Inc. (Reeds Ferry)), a division of Select Energy Contracting, Inc.  (SECI), and

·

Woods Network Services, Inc. (Woods Network).

At March 31, 2006, certain assets and liabilities of NGC, Mt. Tom, SESI and Woods Electrical, as well as the retail business of Select Energy, Inc. (Select Energy), have been classified as assets held for sale and liabilities of assets held for sale on the accompanying condensed consolidated balance sheet.  At December 31, 2005, assets held for sale and liabilities of assets held for sale consisted of certain assets and liabilities of SESI and Woods Electrical.  For further information regarding these companies, see Note 4, "Assets Held for Sale and Discontinued Operations" to the condensed consolidated financial statements.

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B.

Accounting Standards Issued But Not Yet Adopted

Accounting for Servicing of Financial Assets:  In March of 2006, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standard (SFAS) No. 156, "Accounting for Servicing of Financial Assets - An Amendment of FASB Statement No. 140."  SFAS No. 156 requires an entity to recognize a servicing asset or liability at fair value each time it undertakes an obligation to service a financial asset by entering into a servicing contract in a transfer of the servicer's financial assets that meets the requirements for sale accounting and in other circumstances.  Servicing assets and liabilities may be subsequently measured through either amortization or recognition of fair value changes in earnings.  SFAS No. 156 is required to be applied prospectively to transactions beginning on January 1, 2007.  The company is evaluating the effect of this statement on its accounting for the sale and servi cing of certain CL&P accounts receivable.  

C.

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 March 31, 2006, 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 $892.9 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 $221.4 million of LOCs issued, the majority of which were issued for the benefit of NU Enterprises at March 31, 2006.  NU has no guarantees of the performance of third parties.  

At March 31, 2006, NU had outstanding guarantees on behalf of the Utility Group and The Rocky River Realty Company (RRR) of $11 million and $11.6 million, respectively.  These amounts are included in the total outstanding NU guarantee exposure amount of $892.9 million.  The guarantee amount of $870.3 million for NU Enterprises includes $557.2 million for Select Energy and $313.1 million for other NU Enterprises businesses.  The $313.1 million in guarantees related to the other NU Enterprises businesses is comprised of $89.5 million for SESI's obligations under certain financing arrangements, $209.5 million for performance obligations of the energy services businesses, including SESI, and $14.1 million for the guarantee of NGC's debt obligations.

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 the Public Utility Holding Company Act (PUHCA) on February 8, 2006, NU's level of guarantees was subject to certain authorization levels by the SEC.  With the repeal of PUHCA, there are no regulatory limits on NU's ability to guarantee the obligation of its subsidiaries.

D.

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 Services Company's (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 that it is probable that the Utility Group 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.   

7

Regulatory Assets:  The components of regulatory assets are as follows:  

	At March 31, 2006
(Millions of Dollars)	NU Consolidated	CL&P	PSNH	WMECO	Yankee Gas and Other
Recoverable nuclear costs	$      42.1	$           -	$  25.3	$   16.8	$      -
Securitized assets	1,286.6	816.5	362.8	107.3	-
Income taxes, net	332.0	229.4	35.1	50.0	17.5
Unrecovered contractual obligations	309.8	186.7	61.1	62.0	-
Recoverable energy costs	247.9	79.9	165.7	2.3	-
Other regulatory assets/(overrecoveries)	304.8	109.9	145.5	(4.2)	53.6
Totals	$2,523.2	$1,422.4	$795.5	$234.2	$71.1

	At December 31, 2005
(Millions of Dollars)	NU Consolidated	CL&P	PSNH	WMECO	Yankee Gas and Other
Recoverable nuclear costs	$    44.1	$           -	$ 26.1	$  18.0	$     -
Securitized assets	1,340.9	855.6	375.0	110.3	-
Income taxes, net	332.5	227.6	35.9	51.6	17.4
Unrecovered contractual obligations	327.5	197.7	63.2	66.6	-
Recoverable energy costs	193.0	7.3	171.5	2.5	11.7
Other regulatory assets/(overrecoveries)	245.9	69.8	150.3	(25.8)	51.6
Totals	$2,483.9	$1,358.0	$822.0	$223.2	$80.7

Included in NU's other regulatory assets/(overrecoveries) above of $304.8 million at March 31, 2006 and $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 $48.8 million at March 31, 2006 and $47.3 million at December 31, 2005.  A portion of these regulatory assets totaling $17.6 million at March 31, 2006 and $17.3 million at December 31, 2005 has been approved for deferred accounting treatment.  At this time, management believes that the remaining regulatory assets are probable of recovery.  

Included in WMECO's other regulatory assets/(overrecoveries) are $31.8 million and $37.8 million at March 31, 2006 and December 31, 2005, respectively, of amounts related to WMECO's rate cap deferral.  The rate cap deferral allows WMECO to recover stranded costs, and these amounts represent the cumulative excess of transition cost revenues over transition cost expenses.

Additionally, the Utility Group had $12.6 million and $11.2 million of regulatory costs at March 31, 2006 and December 31, 2005, respectively, that are included in deferred debits and other assets - other on the accompanying condensed consolidated balance sheets.  These amounts represent regulatory costs that have not yet been approved by the applicable regulatory agency.  Management believes these assets are recoverable in future cost of service regulated rates.

As discussed in Note 7D, "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.

Regulatory Liabilities:  The Utility Group had $1.2 billion of regulatory liabilities at March 31, 2006 and $1.3 billion at December 31, 2005, including revenues subject to refund.  These amounts are comprised of the following:

	At March 31,  2006
(Millions of Dollars)	NU Consolidated	CL&P	PSNH	WMECO	Yankee Gas
Cost of removal	$  306.8	$140.5	$  86.2	$23.9	$56.2
CL&P GSC and SBC overcollections	55.2	55.2	-	-	-
PSNH cumulative deferral - SCRC	330.0	-	330.0	-	-
Regulatory liabilities offsetting   Utility Group derivative assets	333.5	333.5	- -	- -	- -
Other regulatory liabilities	156.4	73.3	46.7	0.2	36.2
Totals	$1,181.9	$602.5	$462.9	$24.1	$92.4

8

	At December 31, 2005
(Millions of Dollars)	NU Consolidated	CL&P	PSNH	WMECO	Yankee Gas
Cost of removal	$  305.5	$139.4	$ 85.7	$23.6	$56.8
CL&P CTA, GSC and SBC   overcollections	154.0	154.0	-	-	-
PSNH cumulative deferral - SCRC	303.3	-	303.3	-	-
Regulatory liabilities offsetting   Utility Group derivative assets	391.2	391.2	-	-	-
Other regulatory liabilities	119.5	58.4	25.6	0.2	35.3
Totals	$1,273.5	$743.0	$414.6	$23.8	$92.1

E.

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 in other interest expense and the cost of equity funds is recorded as other income on the condensed consolidated statements of loss, as follows:

	For the Three Months Ended
(Millions of Dollars)	March 31, 2006	March 31, 2005
Borrowed funds	$3.4	$1.8
Equity funds	4.5	1.9
Totals	$7.9	$3.7
Average AFUDC rates	6.6%	4.5%

The average Utility Group AFUDC rate is based on a Federal Energy Regulatory Commission (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.  Fifty percent of construction work in progress associated with CL&P's four major transmission projects in southwest Connecticut is recovered currently in rates.  The increase in the average AFUDC rate in 2006 is primarily due to lower levels of short-term debt outstanding and higher equity levels in the first quarter of 2006 as compared to 2005.  

F.

Share-Based Payments

NU maintains an Employee Stock Purchase Plan (ESPP) and other long-term equity-based incentive plans under the Northeast Utilities Incentive Plan (Incentive Plan).  Effective January 1, 2006, NU adopted SFAS No. 123(R), "Share-Based Payments," under the modified prospective method.  Adoption of SFAS No. 123(R) had a de minimus effect on NU’s net loss, no effect on NU’s loss per share and a tax benefit in excess of compensation cost that (decreased)/increased NU’s cash flows from operating activities and cash flows from financing activities by $(0.2) million and $0.2 million, respectively.   

SFAS No. 123(R) requires that share-based payments be recorded using the fair value-based method based on the fair value at the date of grant and applies to share-based compensation awards granted on or after January 1, 2006 or to awards for which the requisite service period has not been completed.  For prior periods, as permitted by SFAS No. 123, "Accounting for Stock-Based Compensation," and related guidance, NU used the intrinsic value method and disclosed the pro forma effects of recording equity-based compensation under the fair value-based method.  In 2006, NU began accounting for its various share-based plans as follows:

·

For grants of restricted stock and restricted stock units (RSUs), NU continues to record compensation expense over the vesting period based upon the fair value of NU's common stock at the date of grant, but records this expense net of estimated forfeitures.  Previously, forfeitures were recorded as incurred.  Dividend equivalents on RSUs, previously included in compensation expense, are charged to retained earnings net of estimated forfeitures.  

·

For shares granted under the Employee Stock Purchase Plan (ESPP), an immaterial amount of compensation expense was recorded in the first quarter of 2006 and no future compensation expense will be recorded as a result of a plan amendment that was effective on February 1, 2006.  

·

For stock options, NU has not granted any stock options since 2002 and no compensation expense is recorded, as all options were fully vested prior to January 1, 2006.

9

Incentive Plans:  Under the Incentive Plan, NU is authorized to grant new shares for various types of awards, including restricted shares, restricted share units, performance units, and stock options to eligible employee 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 plus the shares not utilized in previous years.

Restricted Shares and Restricted Share Units:  NU has granted restricted shares under the 2004, 2003 and 2002 incentive programs which are subject to three and four-year graded vesting schedules.  NU has granted RSUs under the 2004, 2005 and 2006 incentive programs which are subject to three-year and four-year graded vesting schedules.  RSUs are paid in shares plus cash sufficient to satisfy withholding subsequent to vesting, in accordance with the payment schedule as defined in the plan.  A summary of restricted shares and RSUs for the three months ended March 31, 2006 is as follows:

	Outstanding December 31, 2005	Granted	Vested	Paid	Forfeited	Outstanding March 31, 2006
Restricted Shares	152,901	-	(74,243)	N/A	(1,388)	77,270
Weighted average grant-date fair value		-	$14.52	N/A	$14.17	$14.87
RSUs (units)	521,273	352,783	N/A	(109,579)	(5,604)	758,873
Weighted average grant-date fair value		$19.66	N/A	$18.43	$18.93	$19.27

The weighted average grant date fair value per share for RSUs granted during the three months ended March 31, 2005 was $18.76.  The weighted average grant date fair value per share for restricted shares vested and RSUs paid during the three months ended March 31, 2005 was $14.57 and $19.07, respectively.  

The total fair value of restricted shares vested during the three months ended March 31, 2006 and 2005 was $1.1 million and $1.2 million, respectively.  The total aggregate fair value of restricted shares outstanding at March 31, 2006 was $1.1 million   As of March 31, 2006, the remaining compensation cost related to these shares to be recognized was $1 million, which is expected to be recognized over a weighted average period of one year.  The total compensation cost recognized during the three months ended March 31, 2006 and March 31, 2005 was $0.2 million in each period, net of taxes of approximately $0.1 million.  

The total fair value of RSUs paid during the three months ended March 31, 2006 and 2005 was $2 million and $1.2 million, respectively.  The total aggregate fair value of RSUs outstanding at March 31, 2006 was $14.6 million   As of March 31, 2006, the remaining compensation cost related to these units to be recognized was $11.6 million, which is expected to be recognized over a weighted average period of 2.4 years.  The total compensation cost recognized for the three months ended March 31, 2006 and 2005 was $0.6 million and $0.2 million, respectively, net of taxes of approximately $0.4 million and $0.1 million, respectively.  

Stock Options:  Prior to 2003, NU granted stock options to certain employees.  These options were fully vested as of January 1, 2006.  The fair value of each stock option grant has been estimated on the date of grant using the Black-Scholes option pricing model.  The weighted average remaining contractual lives for the options outstanding at March 31, 2006 is 4.6 years.

A summary of stock option transactions is as follows:

		Exercise Price Per Share
	Options	Range			Weighted Average
Outstanding - December 31, 2005	1,122,541	$14.9375	-	$22.2500	$18.4484
Exercised	8,166	$16.3100	-	$19.5000	$17.7861
Forfeited and cancelled	18,750	$21.0300	-	$21.0300	$21.0300
Outstanding and Exercisable – March 31, 2006	1,095,625	$14.9375	-	$22.2500	$18.4091

Cash received for options exercised during the three months ended March 31, 2006 totaled $0.1 million.  

Employee Share Purchase Plan (ESPP):  NU maintains an ESPP for all eligible employees.  Prior to February 1, 2006, 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 were permitted to purchase shares having a value not exceeding 25 percent of their compensation as of the beginning of the purchase period.  Effective February 1, 2006, the ESPP was amended to change the discount rate to five percent of the market price and the pricing date to the last day of the purchase period.  As a result, the ESPP qualifies as a non-compensatory plan under SFAS No. 123R.

10

The following table illustrates the pro forma effect if NU had applied the recognition provisions of SFAS No. 123 to share-based compensation for the three months ended March 31, 2005:

(Millions of Dollars, except per share amounts)
Net loss, as reported	$(117.7)
Add:  share-based payments included in reported net loss,   net of related tax effects	0.6
Net loss before share-based payments	(117.1)
Deduct: Total share-based payments determined under the fair   value-based  method for all awards, net of related tax effects	(0.8)
Pro forma net loss	$(117.9)
Loss Per Share:
Basic and fully diluted – as reported	$ (0.91)
Basic and fully diluted – pro forma	$ (0.91)

NU assumes an income tax rate of 40 percent to estimate the tax effect on total share-based payments determined under the fair value-based method for all awards.  

G.

Sale of Customer Receivables

At March 31, 2006 and December 31, 2005, CL&P had sold an undivided interest in its accounts receivable of $100 million and $80 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 March 31, 2006 and December 31, 2005, the reserve requirements calculated in accordance with the Receivables Purchase and Sale Agreement were $30.7 million and $21 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 March 31, 2006 and December 31, 2005, amounts sold to CRC by CL&P but not sold to the financial institution totaling $241.7 million and $252.8 million, respectively, are included in investments in securitizable assets on the accompanying condensed 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 servicing 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."

H.

Other Investments

The operating subsidiaries of NU collectively own 49 percent of the common stock of Connecticut Yankee Atomic Power Company (CYAPC) with a carrying value of $23 million at March 31, 2006.  This amount is included in deferred debits and other assets – other on the accompanying condensed consolidated balance sheets.  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 at March 31, 2006 but will continue to evaluate the impacts, if any, that the FERC proceeding has on this investment.  For further information, see Note 7D, "Commitments and Contingencies - Deferred Contractual Obligations," to the condensed consolidated financial statements.  

I.

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.

J.

Special Deposits

Special deposits represent amounts Select Energy has on deposit with unaffiliated counterparties and brokerage firms in the amounts of $54.8 million and $103.8 million at March 31, 2006 and December 31, 2005, respectively.  SESI special deposits totaling $11.2

11

million and $10.2 million are included in assets held for sale on the accompanying condensed consolidated balance sheets at March 31, 2006 and December 31, 2005, respectively.

K.

Counterparty Deposits

Balances collected from counterparties resulting from Select Energy’s credit management activities totaled $12.9 million at March 31, 2006 and $28.9 million at December 31, 2005.  These amounts are recorded as current liabilities and included as counterparty deposits on the accompanying condensed 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 use 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.

L.

Other Income, Net

The pre-tax components of other income/(loss) items are as follows:

NU	For the Three Months Ended
(Millions of Dollars)	March 31, 2006	March 31, 2005
Other Income:
Investment income	$ 9.2	$   3.6
CL&P procurement fee	2.9	3.0
AFUDC - equity funds	4.5	1.9
Other	1.9	2.0
Total Other Income	$18.5	$ 10.5
Other Loss:
Charitable donations	$(0.7)	$  (0.8)
Lobbying costs	(0.8)	(0.8)
Loss on investments in securitizable assets	(0.4)	(0.4)
Other	(0.4)	(2.6)
Total Other Loss	$(2.3)	$  (4.6)
Total Other Income, Net	$16.2	$    5.9

CL&P	For the Three Months Ended
(Millions of Dollars)	March 31, 2006	March 31, 2005
Other Income:
Investment income	$   5.8	$  2.3
CL&P procurement fee	2.9	3.0
AFUDC - equity funds	3.3	1.6
Other	1.3	1.2
Total Other Income	$13.3	$  8.1
Other Loss:
Lobbying costs	$(0.4)	$(0.4)
Loss on investments in securitizable assets	(0.4)	(0.4)
Charitable donations	(0.3)	(0.6)
Other	(0.2)	(1.5)
Total Other Loss	$(1.3)	$(2.9)
Total Other Income, Net	$12.0	$  5.2

12

PSNH	For the Three Months Ended
(Millions of Dollars)	March 31, 2006	March 31, 2005
Other Income:
Investment income	$  0.2	$  0.2
AFUDC - equity funds	1.1	0.3
Other	-	0.1
Total Other Income	$  1.3	$  0.6
Other Loss:
Charitable donations	$ (0.2)	$ (0.2)
Lobbying costs	(0.1)	(0.1)
Other	(0.1)	(0.2)
Total Other Loss	$(0.4)	$(0.5)
Total Other Income, Net	$  0.9	$  0.1

WMECO	For the Three Months Ended
(Millions of Dollars)	March 31, 2006	March 31, 2005
Other Income:
Investment income	$  0.3	$      -
Gain on disposition of property	-	0.1
Conservation and load management incentive	0.4	0.1
Millstone 1 recovery amortization	0.2	0.2
Other	0.1	-
Total Other Income	$  1.0	$ 0.4
Other Loss:
Charitable donations	$ (0.1)	$     -
Lobbying costs	(0.1)	(0.2)
Other	-	(0.1)
Total Other Loss	$(0.2)	$(0.3)
Total Other Income, Net	$  0.8	$ 0.1

Investment income for NU includes equity in earnings of regional nuclear generating and transmission companies of $0.9 million of income for the three months ended March 31, 2006 and 2005.  Equity in earnings relates to NU’s investment in CYAPC, Maine Yankee Atomic Power Company (MYAPC), and Yankee Atomic Electric Company (YAEC) (Yankee companies) and the Hydro-Quebec transmission system.

None of the amounts in either other income - other or other loss - other are individually significant.  

2.

WHOLESALE CONTRACT MARKET CHANGES (NU, NU Enterprises)

NU recorded $6.8 million and $188.9 million of pre-tax wholesale contract market changes for the three months ended March 31, 2006 and 2005, respectively, 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 condensed consolidated statements of loss.  These changes comprised the following items:

·

Charges of $6.8 million and $294.3 million for the three months ended March 31, 2006 and 2005, respectively, associated with the mark-to-market on certain long-dated wholesale electricity contracts in New England and New York with municipal and other customers.  Included in the $294.3 million are changes in the fair value of wholesale contracts of $167.9 million that became marked-to-market as a result of the decision to exit the wholesale marketing business, offset by a benefit of $30 million related to previously designated wholesale contracts that were redesignated to help support the retail business.  The decision in March of 2005 to exit the wholesale marketing business changed management’s conclusion regarding the likelihood that these wholesale marketing contracts would result in physical delivery to customers and in turn resulted in a change in the first quarter of 2005 from accrual accounting to fair value accountin g for the wholesale marketing contracts.  The charges for the three months ended March 31, 2006 and 2005 reflect mark-to-market movements on these contracts during these periods.

·

A charge of $14.4 million for the three months ended March 31, 2005 for mark-to-market contract asset write-offs and a contract termination payment in March of 2005.

13

·

A benefit of $94 million for the three months ended March 31, 2005 for mark-to-market gains primarily related to retail supply contracts by the wholesale business that were previously held to serve retail electric load.  The company has exited or settled many of these contracts but retains certain contracts to source retail sales.  For the three months ended March 31, 2006, retail supply contract mark-to-market charges are included in fuel, purchased and net interchange power.

·

A benefit of $25.8 million for the three months ended March 31, 2005 for other wholesale contracts related to electricity that would have been delivered to customers primarily in 2005 and 2006.  As a result of exiting the wholesale marketing business, these contracts were also required to be marked-to-market.  Prior to the decision to exit the wholesale marketing business, it was management's intention to deliver the electricity to the customer and accrual accounting was used.

Included in the charge of $188.9 million for the three months ended March 31, 2005 is a $54.5 million pre-tax mark-to-market charge related to an inter-company contract between Select Energy and CL&P.  This contract was included in the portfolio of contracts Select Energy assigned to a third party wholesale power marketer, and Select Energy stopped serving CL&P on December 31, 2005.  This contract was part of CL&P’s stranded costs, and benefits received by CL&P under this contract were provided to CL&P’s ratepayers.  A $2.8 million pre-tax mark-to-market charge for the three months ended March 31, 2005 was recorded as wholesale contract market changes by Select Energy for an intercompany contract between Select Energy and WMECO for default service.  WMECO’s benefits under this contract were provided to ratepayers in the form of lower than market default service rates.  These charges were not eliminated in consolidation because on a consolidated basis NU retained the over-market obligation to the ratepayers of CL&P and WMECO.  As of December 31, 2005, these contracts expired or were fully assigned.

For further information regarding derivative assets and liabilities that are being exited, see Note 5, "Derivative Instruments," to the condensed consolidated financial statements.

3.

RESTRUCTURING AND IMPAIRMENT CHARGES (NU, NU Enterprises)

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 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 $6.1 million and $45.5 million of pre-tax restructuring and impairment charges for the three months ended March 31, 2006 and 2005, respectively, related to exiting the merchant energy businesses and its energy services businesses.  The amounts related to continuing operations are included as restructuring and impairment charges on the condensed consolidated statements of loss with the remainder included in discontinued operations.  These charges are included as part of the NU Enterprises reportable segment in Note 12, "Segment Information," to the condensed consolidated financial statements.  A summary of these pre-tax charges is as follows:  

14

	For the Three Months Ended
(Millions of Dollars)	March 31, 2006	March 31, 2005
Merchant Energy:
Retail Marketing:  (1)
Impairment charges	$   -	$ 7.2
Restructuring charges	4.8	-
Subtotal	4.8	7.2
Competitive Generation:  (1)
Restructuring charges	1.7	-
Subtotal - Merchant Energy	6.5	7.2

Energy Services and Other:
Impairment charges	(0.7)	38.3
Restructuring charges	0.3	-
Subtotal - Energy Services and Other	(0.4)	38.3
Total restructuring and impairment charges	6.1	45.5
Restructuring and impairment charges   included in discontinued operations	1.0	24.0
Total restructuring and impairment charges   included in continuing operations	$5.1	$21.5

(1)

For segment reporting purposes, $1.8 million of retail restructuring charges and $1.7 million of competitive generation restructuring charges are included in the NU Enterprises - Services and other reportable segment as these amounts were recorded by NU Enterprises parent.  

In the first quarter of 2006, restructuring charges totaling $6.8 million were recorded for consulting fees, legal fees, employee-related costs and other costs.  Additional restructuring costs may be recognized, including professional fees and employee-related and other costs.

In the first quarter of 2006, a benefit of $0.7 million was included in impairment charges.  The $0.7 million recorded to the energy services businesses consists of a gain on the sale of the Massachusetts service location of Select Energy Contracting, Inc. - Connecticut (SECI-CT) that was offset by costs related to the sale of SESI.  

In the first quarter of 2005, an exclusivity agreement intangible asset totaling $7.2 million related to the retail marketing business was written off.

In 2005, NU Enterprises hired an outside firm to assist in valuing its energy services business 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 as of March 31, 2005.  An impairment charge of $38.3 million was recorded for the three months ended March 31, 2005.

The following table summarizes the liabilities related to restructuring costs which are recorded in accounts payable and other current liabilities on the accompanying condensed consolidated balance sheets at March 31, 2006 and December 31, 2005:  

(Millions of Dollars)	Employee- Related 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
Costs incurred	0.3	6.5	6.8
Cash payments	(0.3)	(4.6)	(4.9)
Restructuring liability as of March 31, 2006	$ 1.8	$ 7.2	$ 9.0

15

4.

ASSETS HELD FOR SALE AND DISCONTINUED OPERATIONS (NU, NU Enterprises)

Assets Held for Sale:  In November of 2005, NU decided to exit NU Enterprises’ retail marketing and competitive generation businesses.  In the first quarter of 2006, management determined that these businesses became held for sale under applicable accounting guidance, and should therefore be recorded at fair value less cost to sell.  NU recorded a pre-tax charge of $62.9 million in the first quarter of 2006 to record the retail marketing business at fair value less cost to sell, including derivative contracts that no longer qualified for accrual accounting because physical delivery can no longer be asserted.  The $62.9 million includes $3 million related to the estimated costs to sell the retail business, which has been reflected in restructuring and impairment charges.  The remaining amount ($59.9 million) has been included in other operation expenses.

At December 31, 2005, management determined that the wholesale and retail marketing businesses did not meet the held for sale criteria under applicable accounting guidance.  At March 31, 2006, management continues to believe the wholesale marketing business does not meet the held for sale criteria under applicable accounting guidance.

At March 31, 2006, the following businesses are accounted for as held for sale, at the lower of their carrying amount or fair value less cost to sell:  

·

Select Energy's retail marketing business, which engages in retail energy marketing activities primarily in the northeastern United States,

·

NGC, which owns generating facilities,

·

Mt. Tom, which is a coal-fired generating facility,

·

Certain assets and liabilities of SESI, a performance contracting subsidiary that specializes in upgrading the energy efficiency of large governmental and institutional facilities, and

·

Certain assets and liabilities of Woods Electrical, which provides electrical services.

On May 1, 2006, NU Enterprises signed an agreement to sell the retail marketing business.  In April of 2006, NU Enterprises sold certain assets of Woods Electrical for approximately $1 million.   On May 5, 2006, NU Enterprises completed the sale of SESI.   

In April of 2006, indicative bids for the competitive generation business were received.  NU continues to expect to close on the sale of the competitive generation business by the end of 2006.  At December 31, 2005, assets held for sale and liabilities of assets held for sale consisted of certain assets and liabilities of SESI and Woods Electrical.  

These businesses are included as part of the NU Enterprises reportable segment in Note 12, "Segment Information," to the condensed consolidated financial statements.  The major classes of assets and liabilities that are held for sale at March 31, 2006 and December 31, 2005 are as follows:

	At March 31, 2006	At December 31, 2005
(Millions of Dollars)
Derivative contracts	$  39.4	$      -
Property, plant and equipment	822.7	-
Long-term contract receivables	75.5	79.5
Other assets	54.5	22.3
Total assets	992.1	101.8
Derivative contracts	65.0	-
Long-term debt	400.7	86.3
Other liabilities	39.1	15.2
Total liabilities	504.8	101.5
Net assets	$487.3	$   0.3

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Discontinued Operations:  NU's condensed consolidated statements of loss for the three months ended March 31, 2006 and 2005 present NGC, Mt. Tom, SESI and Woods Electrical as discontinued operations.  In addition, SECI-NH (including Reeds Ferry) and Woods Network are included in discontinued operations for the three months ended March 31, 2005.  These businesses were sold in November of 2005.  

The retail marketing business is not presented as discontinued operations because separate financial information is not available for this business for the periods prior to the first quarter of 2006.  For information regarding the derivative contracts above, see Note 5, "Derivative Instruments," to the condensed consolidated financial statements.

Under discontinued operations presentation, revenues and expenses of these businesses are classified net of tax in income from discontinued operations on the condensed consolidated statements of loss and all prior periods have been reclassified.  These businesses are included as part of the NU Enterprises reportable segment in Note 12, "Segment Information," to the condensed consolidated financial statements.  Summarized financial information for the discontinued operations is as follows:  

	For the Three Months Ended
(Millions of Dollars)	March 31, 2006	March 31, 2005
Operating revenue	$58.7	$88.1
Income/(loss) before income tax   expense/(benefit)	17.6	(7.0)
Income tax expense/(benefit)	7.0	(2.6)
Net income/(loss)	10.6	(4.4)

Included in discontinued operations for the three months ended March 31, 2006 and 2005 are $50.1 million and $56.3 million, respectively, of intercompany revenues that are not eliminated in consolidation due to the separate presentation of discontinued operations.  Of this amount, $35.7 million and $14.2 million, respectively, represent revenues on intercompany contracts between the generation operations of NGC and Mt. Tom and Select Energy.  NGC's and Mt. Tom's earnings related to these contracts are included in discontinued operations while Select Energy's related expenses are included in continuing operations.  At March 31, 2006, 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.

DERIVATIVE INSTRUMENTS (NU, CL&P, Select Energy, Yankee Gas)

Contracts that are derivatives and do not meet the definition of a cash flow hedge and are not elected or do not meet the criteria of 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.  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.  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 items 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.  The change in fair value of a normal purchase or sale contract is not included in earnings.  

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The tables below summarize current and long-term derivative assets and liabilities at March 31, 2006 and December 31, 2005.  At March 31, 2006 and December 31, 2005, derivative assets and liabilities have been segregated between wholesale, retail, generation and hedging amounts.  The fair value of these contracts may not represent amounts that will be realized.  

	At March, 31, 2006
(Millions of Dollars)	Assets		Liabilities
	Current	Long- Term	Current	Long- Term	Net Total
NU Enterprises:
Wholesale	$133.2	$  70.2	$(223.5)	$(153.6)	$(173.7)
Retail	30.5	9.2	(45.9)	(15.4)	(21.6)
Generation	7.3	-	(4.6)	(10.8)	(8.1)
Utility Group - Electric:
Non-trading	54.1	280.3	(6.4)	(34.3)	293.7
Hedging	3.2	-	-	-	3.2
NU Parent:
Hedging	-	-	-	(10.9)	(10.9)
	228.3	359.7	(280.4)	(225.0)	82.6
Derivative assets and  liabilities held for sale	30.2	9.2	(38.8)	(26.2)	(25.6)
Totals	$198.1	$350.5	$(241.6)	$(198.8)	$108.2

	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	55.0	12.9	(27.2)	0.4	41.1
Generation	9.2	-	(5.1)	(15.5)	(11.4)
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 March 31, 2006 and December 31, 2005, Select Energy had 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.  

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 include wholesale short-term and long-term electricity supply and sales contracts, which include contracts to sell electricity to utilities under full requirements contracts and a contract to sell electricity to a municipality with a term of seven 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 active markets.  

Derivatives used in wholesale activities are recorded at fair value and included in the condensed consolidated balance sheets as derivative assets or liabilities.  Changes in fair value are recorded in the period of change, mostly in wholesale contract market changes, net on the accompanying condensed consolidated statements of loss.   

NU Enterprises - Retail:  Select Energy is in the process of exiting the retail marketing business.  Select Energy's retail portfolio 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,

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the fair value of which is based on historical settlement prices as well as external sources.  During the first quarter of 2006, management was no longer able to conclude that physical delivery was probable under contracts that extended past the June 1, 2006 expected sale of the retail marketing business.   As a result, retail marketing derivative contracts that were previously accounted for on an accrual basis under the normal purchase and sale exception were marked to market in the first quarter of 2006 and recognized in other operation expenses.  

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 price risk under these agreements through NYMEX futures contracts through May of 2006.  At March 31, 2006 the NYMEX futures contracts had notional values of $13.2 million and were recorded at fair value as derivative liabilities totaling $2.6 million.  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 financial instruments to hedge its electric and gas purchases and sales through May of 2006.  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 $0.3 million and derivative liabilities of $6.5 million at March 31, 2006 and derivative assets of $24.4 million and derivative liabilities of $4.8 million at December 31, 2005.

As of March 31, 2006, Select Energy has retained in accumulated other comprehensive income the portion of cash flow hedges for which the hedged item is probable of being delivered.  Any hedges extending past the assumed sale date have been dedesignated.  For those cash flow hedges that were dedesignated and the hedged transactions which are no longer probable of delivery, the result was a reclassification from accumulated other comprehensive income to other operation expenses of $14.1 million.  A loss was also recognized into earnings for additional amounts not expected to be recovered because the combination of the hedging instrument and hedged transaction would have resulted in the recognition of a net loss.  In addition, a negative $2.2 million was recognized in earnings in the first three months of 2006 for the ineffective portion of cash flow hedges.   For further information, see Note 9, “Comprehensive Income,” to the condensed consolidated financial statements.

Select Energy hedges certain amounts of natural gas inventory with gas futures that are accounted for as fair value hedges.  Changes in the fair value of hedging instruments and natural gas inventory are recorded in fuel, purchased, and net interchange power on the accompanying condensed consolidated statement of loss.  The change in fair value of the futures were included in derivative liabilities and amounted to $0.1 million and $3.4 million at March 31, 2006 and December 31, 2005, respectively.  A negative pre-tax $0.1 million was recognized in earnings and recorded in fuel, purchased, and net interchange power for the first three months of 2006 for the ineffective portion of fair value hedges.

NU Enterprises - Generation:  Derivative contracts include generation asset-specific sales and forward sales of electricity at hub trading points.  The fair value of these 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.  Certain of these contracts have been recorded at fair value in revenues, while others qualified for accrual accounting until the fourth quarter of 2005 when Select Energy marked them to market when the probability of physical delivery could no longer be asserted.  Changes in fair value of generation contracts formerly accounted for on an accrual basis are recorded in wholesale contract market changes, net for those contracts that are part of continuing operations.  Changes in fair value of generation contracts that are held for sale are included in discontinued operations.  

Utility Group - Electric - Non-Trading:  CL&P has two independent power producer (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 March 31, 2006 include a derivative asset with a fair value of $333.5 million and a derivative liability with a fair value of $36.9 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, 2005, the fair values of these IPP non-trading derivatives included a derivative asset with a fair value of $391.2 million and a derivative liability with a fair value of $32.3 million.

CL&P has entered into Financial Transmission Rights (FTR) contracts to limit the congestion costs associated with its transitional standard offer (TSO) contract.  An offsetting regulatory asset has been recorded as this contract is part of the stranded costs and management believes that these costs will continue to be recovered in rates.  At March 31, 2006, the fair value of these contracts is recorded as a derivative asset of $0.9 million and derivative liability of $3.8 million on the accompanying condensed consolidated balance sheets.

Utility Group - Electric - Hedging:  In March of 2006, CL&P entered into a forward swap agreement to hedge the interest rate associated with $125 million of its planned $250 million, 30-year, fixed rate debt issuance.  Under the agreement, CL&P has locked in a Libor swap rate of 5.322 percent based on the notional amount of $125 million in debt that is expected to be issued in June of 2006.  As a cash flow hedge at March 31, 2006, the change in fair value of this agreement is recorded as a derivative asset of $3.2 million on

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the accompanying condensed consolidated balance sheets and an offsetting amount is included in accumulated other comprehensive income.  

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.  The changes in fair value of the swap and the hedged debt instrument are recorded on the condensed consolidated balance sheets and are equal and offsetting in the condensed consolidated statements of loss.  The cumulative change in the fair value of the hedged debt of $10.9 million is included as a decrease to long-term debt on the condensed consolidated balance sheets.  The hedge is recorded as a derivative liability of $10.9 million at March 31, 2006, and $5.2 million at December 31, 2005.  The resulting changes in interest payments made are recorded as adjustments to interest expense.

6.

GOODWILL AND OTHER INTANGIBLE ASSETS (Yankee Gas, NU Enterprises)

The only NU reporting unit that currently maintains goodwill is the Yankee Gas reporting unit, which is 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.  The goodwill balance was $287.6 million at both March 31, 2006 and December 31, 2005.   

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.  During the three months ended March 31, 2005, goodwill and intangible asset balances at the NU Enterprises energy services businesses were determined to be impaired and $38.3 million in write-offs were recorded.  In addition, $7.2 million of intangible assets, related to an exclusivity agreement held by the retail marketing business, were written off.  

NU recorded amortization expense of $0.9 million for the three months ended March 31, 2005 related to intangible assets subject to amortization.  

7.

COMMITMENTS AND CONTINGENCIES

A.

Regulatory Developments and Rate Matters (CL&P, PSNH, WMECO, Yankee Gas)

Connecticut:

CTA and SBC Reconciliation:  The Competitive Transition Assessment (CTA) allows CL&P to recover stranded costs, such as securitization costs associated with the rate reduction bonds, amortization of regulatory assets, and IPP over market costs, while the 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 worker protection costs.

On March 31, 2006, CL&P filed its 2005 CTA and SBC reconciliation with the Connecticut Department of Public Utility Control (DPUC), which compares CTA and SBC revenues to revenue requirements.  For the year ended December 31, 2005, total CTA revenues exceeded the CTA revenue requirement by $60.1 million.  This amount was recorded as a regulatory liability on the accompanying condensed consolidated balance sheets.  For the same period, the SBC revenue requirement exceeded SBC revenues by $1.3 million.  Management expects a decision in this docket from the DPUC by the end of 2006 and does not expect the outcome to have a material adverse impact on CL&P's net income, financial position or cash flows.  

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, and 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.  

Income Taxes: In 2000, CL&P requested from the Internal Revenue Service (IRS) a Private Letter Ruling (PLR) regarding the treatment of unamortized investment tax credits (UITC) and excess deferred income taxes (EDIT) related to generation assets that have been sold.   On April 18, 2006, the IRS issued a PLR to CL&P regarding the treatment of UITC and EDIT related to generation assets that CL&P has 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 holds that it would be a violation of tax regulations if the EDIT or UITC is used to reduce customers' rates following the sale of the generation assets.  The statement in the PLR is consistent with proposed regulations released in December 2005.  Previously, CL&P was ordered by the

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DPUC to submit the PLR to the DPUC within 10 days of issuance and retain the UITC and EDIT in their existing accounts pending its receipt and review of the PLR.  CL&P has complied with this order.

In addition to the PLR received by CL&P, proposed regulations were issued by the Treasury Department in December of 2005.  The proposed regulations would generally allow EDIT and UITC generated by property that is no longer regulated to be returned to regulated customers without violating the tax law.  The new proposed regulations, however, would only apply to property that ceases to be regulated public utility property after December of 2005.  As such, under the proposed regulations, the EDIT and UITC cannot be used to reduce CL&P's customers' rates because CL&P sold these assets before December of 2005.  Those proposed regulations have not been finalized.

At March 31, 2006, CL&P's UITC balance is $59.3 million and EDIT balance is $14.7 million related to generation assets that have been sold.  The resolution of this contingency may result in these deferred tax balances being eliminated with a corresponding reduction to income tax expense.

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 DPUC issued a new decision on April 20, 2006 requiring an audit of Yankee Gas' PGA accounting methods and deferring any conclusion on the $9 million of previously recovered revenues until the completion of the audit.  Management believes the unbilled sales and revenue adjustments and resultant charges to customers through the PGA clause were appropriate. & nbsp;Based on the facts of the case and the supplemental information provided to the DPUC, notwithstanding the new decision, 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 Stranded Cost Recovery Charge (SCRC) allows PSNH to recover its stranded costs.  On an annual basis, PSNH files with the New Hampshire Public Utilities Commission (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 $330 million at March 31, 2006.  At March 31, 2006, this cumulative deferral will decrease the amount of non-securitized stranded costs to be recovered from PSNH's customers in the future from $355.3 million to $25.3 million.

From May of 2001 through January 31, 2006, the difference between PSNH ES revenues and ES costs was deferred and included in the SCRC calculation for recovery or refund.  As part of a settlement agreement with NHPUC staff and OCA regarding 2006 ES rates, PSNH requested a change in accounting for ES to allow the difference between ES revenues and costs to be included in subsequent ES rates.  The NHPUC issued its order on January 20, 2006 approving the settlement agreement including the change in accounting.  Effective February 1, 2006, PSNH began deferring the difference between ES revenues and ES costs for inclusion in the calculation of the subsequent ES rate.  At March 31, 2006, ES revenues exceeded ES costs and PSNH has deferred the $22.7 million difference.   

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 IPPs' 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.  PSNH recovers the over market costs of IPP contracts through the SCRC.

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 and the term of the second NHPUC commissioner under challenge expired.  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 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.  

Environmental Legislation:  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.  A bill to implement that agreement passed the New Hampshire House of Representatives in late-March of 2006, passed the New Hampshire Senate on April 20, 2006 and will be sent to New Hampshire

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Governor Lynch for signing into law.  PSNH intends to comply with the legislation by installing wet scrubber technology at its two Merrimack coal units, which combined generate 433 megawatts (MW) by mid-2013.  PSNH currently estimates the cost to comply of approximately $250 million, however, this amount is subject to change as final design is undertaken.  State law, this new bill and PSNH's restructuring agreement provide for the recovery of its generation costs, including the cost to comply with state environmental regulations.  

Massachusetts:

Transition Cost Reconciliation:  WMECO filed its 2005 transition cost reconciliation with the Massachusetts Department of Telecommunications and Energy (DTE) on March 31, 2006.  This filing reconciles transition costs, default service costs and retail transmission costs with their associated revenues collected from customers.  The DTE has not yet reviewed this filing or issued a schedule for review.  Therefore the timing of a decision is uncertain at this time.  However once reviewed by the DTE, management does not expect the outcome to have a material adverse impact on WMECO's net income or financial position.

B.

NRG Energy, Inc. Exposures (CL&P, Yankee Gas)

Certain subsidiaries of NU, including CL&P and Yankee Gas, 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 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’ 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 their resolution will have a material adverse effect on NU’s consolidated financial condition or results of operations.  

C.

Long-Term Contractual Arrangements (CL&P, Merchant Energy)

CL&P:  These amounts represent commitments for various services and materials associated with the Bethel, Connecticut to Norwalk, Connecticut and the Middletown, Connecticut to Norwalk, Connecticut transmission projects as of March 31, 2006.  

(Millions of Dollars)	2006	2007	2008	2009	2010	Thereafter	Total
Transmission business   project commitments	$123.1	$17.6	$14.7	$7.1	$0.1	$ -	$162.6

Merchant Energy:  Select Energy maintains long-term agreements to purchase energy as part of its portfolio of resources to meet its actual or expected sales commitments.  The majority of these purchase commitments are being exited.  Certain purchase commitments are accounted for on the accrual basis, while the remaining commitments are recorded at their mark-to-market value.  These purchase commitments at March 31, 2006 are as follows:

(Millions of Dollars)	2006	2007	2008	2009	2010	Thereafter	Total
Select Energy   purchase commitments	$1,818.9	$829.9	$258.8	$24.1	$11.4	$6.0	$2,949.1

Select Energy's purchase commitment amounts exceed the amount expected to be reported in fuel, purchased and net interchange power because many wholesale sales transactions are classified in fuel, purchased and net interchange power and certain purchases are included in revenues.  Select Energy also maintains certain wholesale, retail and generation energy commitments whose mark-to-market values have been recorded on the condensed consolidated balance sheets as derivative assets and liabilities, a portion of which are included in assets held for sale and liabilities of assets held for sale.  

The amounts and timing of the costs associated with Select Energy’s purchase agreements will be impacted by the exit from the wholesale and retail marketing businesses.

D.

Deferred Contractual Obligations (NU, CL&P, PSNH, WMECO)

FERC Proceedings:  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 by CYAPC beginning on February 1, 2005, subject to refund.

The FERC staff 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.  

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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.  A final order from the FERC 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 its customers' obligations, including the obligation of CL&P, PSNH and WMECO.  Due to the terms of the settlement of state court litigation between CYAPC and Bechtel Power Corporation (Bechtel) over the terminated decommissioning contract, Bech tel has withdrawn from the FERC proceedings.

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 with the FERC 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.  The FERC and CYAPC have asked 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 previously 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.  On March 7, 2006, CYAPC and Bechtel executed a settlement agreement terminating this litigation.  Bechtel paid CYAPC $15 million and the parties have withdrawn their litigation from state court.  CYAPC expects to credit the net proceeds from the settlement agreement against decommissioning costs recoverable from its customers, including CL&P, PSNH and WMECO.

Spent Nuclear Fuel Litigation:  CYAPC, YAEC and MYAPC commenced litigation in 1998 charging that the federal government breached contracts it entered into with each company in 1983 under the Nuclear Waste Policy Act of 1982.  The trial ended on August 1, 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.  On January 31, 2006, the FERC issued an order accepting the rate increase, effective February 1, 2006, subject to refund by YAEC after hearings and settlement judge proceedings.  

On May 1, 2006, YAEC filed with the FERC a proposed settlement agreement with the DPUC, the Massachusetts Attorney General and the Vermont Department of Public Service.  Under the proposed settlement agreement, YAEC agreed to revise its November 2005 decommissioning cost increase from $85 million to $56.8 million.  The revision includes adjustments for contingencies and projected escalation and certain decontamination and dismantlement (D&D) expenses.  Other terms of the proposed settlement agreement include extending the collection period for charges through December 2014, reconciling and adjusting future charges based on actual D&D expenses and the decommissioning trust fund's actual investment earnings.  The company believes that its share of the increase in decommissioning costs will ultimately be recovered from the customers of CL&P, PSNH and WMECO.  NU has a 38.5 percent ownership interest in YAEC.  The proposed settlement agreement w ill become effective upon approval from the FERC, but should not materially affect the level of 2006 charges.

E.

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.  

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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 opted not to seek review of this ruling by the United States Supreme Court.  On April 7, 2006, NU filed its motion for partial summary judgment on Con Edison’s damage claim which asserts that NU is entitled to judgment in its favor with respect to this claim based on the undisputed material facts and applicable law.  At this stage, NU cannot predict the outcome of this matter or its ultimate effect on NU.

F.

Environmental Matters

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 condensed 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, these costs have increased by $4.5 million during the three months ended March 31, 2006.  At March 31, 2006 and December 31, 2005, NU had $32.6 million and $30.7 million, respectively, recorded as environmental reserves.  A reconciliation of the activity in these reserves for the three months ended March 31, 2006 is as follows:

(Millions of Dollars)
Balance at January 1, 2006	$30.7
Additions and adjustments	4.5
Payments	(2.6)
Balance at March 31, 2006	$32.6

Manufactured gas plant (MGP) sites comprise the largest portion of NU’s environmental liability and the environmental reserves related to these sites increased by $4.8 million in the first three months of 2006.  MGPs are sites that manufactured gas from coal which produced certain byproducts that may pose a risk to human health and the environment.  At March 31, 2006 and December 31, 2005, $27.6 million and $25.3 million, respectively, represents amounts for the site assessment and remediation of MGPs.

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.  

8.

MARKETABLE SECURITIES

The following is a summary of NU’s available-for-sale securities related to NU's investment in Globix Corporation (Globix), NU's Supplemental Executive Retirement Plan (SERP) assets and WMECO's prior spent nuclear fuel trust assets, which are recorded at their fair values and are included in current and long-term marketable securities on the accompanying condensed consolidated balance sheets.  Changes in the fair value of these securities are recorded as unrealized gains and losses in accumulated other comprehensive income:

	At March 31, 2006	At December 31, 2005
(Millions of Dollars)
Globix investment (a)	$7.4	$    3.7
SERP assets	59.7	58.1
WMECO prior spent nuclear fuel trust assets	51.3	50.8
Totals	$118.4	$112.6

(a)

NU had an investment in the common stock of NEON Communications, Inc. (NEON), a provider of optical networking services.  On March 8, 2005, NEON merged with Globix Corporation (Globix).  In connection with the closing of the merger, a $0.1 million after-tax loss was recognized in the first quarter of 2005 and a pre-tax positive $0.4 million change in fair value

24

subsequent to March 8, 2005 was included in accumulated other comprehensive income.  On April 6, 2006, NU sold its investment in Globix.  This sale resulted in net proceeds of $6.7 million and a pre-tax gain of $3 million.

At March 31, 2006 and December 31, 2005, marketable securities are comprised of the following:

	At March 31, 2006
(Millions of Dollars)	Amortized Cost	Pre-Tax Gross Unrealized Gains	Pre-Tax Gross Unrealized Losses	Estimated Fair Value
United States equity securities	$23.4	$8.5	$(0.3)	$31.6
Non-United States equity securities	5.9	1.2	-	7.1
Fixed income securities	80.4	0.2	(0.9)	79.7
Totals	$109.7	$9.9	$(1.2)	$118.4

	At December 31, 2005
(Millions of Dollars)	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

At March 31, 2006 and December 31, 2005, 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 March 31, 2006 and December 31, 2005, 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 March 31, 2006	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	$  2.8	$(0.2)	$0.6	$(0.1)	$  3.4	$(0.3)
Non-United States   equity securities	-	-	-	-	-	-
Fixed income securities	35.2	(0.6)	7.8	(0.3)	43.0	(0.9)
Totals	$38.0	$(0.8)	$8.4	$(0.4)	$46.4	$(1.2)

	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)	45.5	(0.9)
Totals	$42.7	$(0.9)	$6.1	$(0.3)	$48.8	$(1.2)

For information related to the change in net unrealized holding gains and losses included in shareholders' equity, see Note 9, "Comprehensive Income," to the condensed consolidated financial statements.

For the three months ended March 31, 2006 and 2005, realized gains and losses recognized on the sale of available-for-sale securities are as follows:

	For the Three Months Ended March 31,
(Millions of Dollars)	Realized Gains	Realized Losses	Net Realized Gains/(Losses)
2006	$0.3	$(0.2)	$0.1
2005	$0.2	$(0.3)	$(0.1)

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For the three months ended March 31, 2006 and 2005, realized gains of $0.2 million and $0.1 million, respectively, are included in other income, net on the accompanying condensed consolidated statements of loss.  For the three months ended March 31, 2006 and 2005, realized losses of $37,000 and $11,000, respectively, relating to the WMECO spent nuclear fuel trust are included in fuel, purchased and net interchange power on the accompanying condensed consolidated statements of loss.

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 $18.3 million and $18.7 million for the three months ended March 31, 2006 and 2005, respectively.

At March 31, 2006, the contractual maturities of the available-for-sale securities are as follows:

(Millions of Dollars)	Amortized Cost	Estimated Fair Value
Less than one year	$  56.4	$  65.7
One to five years	26.3	26.0
Six to ten years	6.7	6.5
Greater than ten years	20.3	20.2
Total	$109.7	$118.4

NU's investment in Globix and all other available-for-sale equity securities are included in the less than one year maturity category in the table above.

9.

COMPREHENSIVE INCOME (NU, CL&P, PSNH, WMECO, NU Enterprises, Yankee Gas)

Total comprehensive income, which includes all comprehensive income/(loss) items by category, for the three months ended March 31, 2006 and 2005 is as follows:

	For the Three Months Ended March 31, 2006
(Millions of Dollars)	NU*	CL&P	PSNH	WMECO	NU Enterprises	Yankee Gas	Other
Net (loss)/income	$(10.1)	$32.5	$5.1	$5.2	$(62.6)	$11.8	$(2.1)
Comprehensive income/(loss) items:
Cash flow hedging instruments	(20.1)	1.9	-	-	(22.0)	-	-
Unrealized gains on securities	3.1	-	-	-	2.5	-	0.6
Other	(2.3)	-	-	-	-	-	(2.3)
Net change in comprehensive income items	(19.3)	1.9	-	-	(19.5)	-	(1.7)
Total comprehensive (loss)/income	$(29.4)	$34.4	$5.1	$5.2	$(82.1)	$11.8	$(3.8)

	For the Three Months Ended March 31, 2005
(Millions of Dollars)	NU*	CL&P	PSNH	WMECO	NU Enterprises	Yankee Gas	Other
Net (loss)/income	$(117.7)	$25.2	$8.8	$4.7	$(167.4)	$14.9	$(3.9)
Comprehensive income/(loss) items:
Cash flow hedging instruments	7.3	-	-	-	7.3	-	-
Unrealized gains on securities	(0.6)	-	-	(0.2)	-	-	(0.4)
Net change in comprehensive income items	6.7	-	-	(0.2)	7.3	-	(0.4)
Total comprehensive (loss)/income	$(111.0)	$25.2	$8.8	$4.5	$(160.1)	$14.9	$(4.3)

*After preferred dividends of subsidiary.

Comprehensive income amounts included in the Other column primarily relate to NU parent and Northeast Utilities Service Company.

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Accumulated other comprehensive income fair value adjustments in NU’s cash flow hedging instruments for the three months ended March 31, 2006 and the twelve months ended December 31, 2005 are as follows:

(Millions of Dollars, Net of Tax)	Three Months Ended March 31, 2006	Twelve Months Ended December 31, 2005
Balance at beginning of period	$18.2	$(3.5)
Hedged transactions recognized into earnings	(2.8)	5.6
Amount reclassified into earnings due to  discontinuation of cash flow hedges	(14.1)	- -
Change in fair value	(4.4)	11.0
Cash flow transactions entered into for the period	1.2	5.1
Net change associated with the current period   hedging transactions	(20.1)	21.7
Total fair value adjustments included in   accumulated other comprehensive income	$(1.9)	$18.2

For the three months ended March 31, 2006, $2.8 million, net of tax, was reclassified from accumulated other comprehensive income in connection with the consummation of the underlying hedged transactions and recognized into earnings in revenues and fuel, purchased, and net interchange power.  For the three months ended March 31, 2006, $14.1 million was reclassified from accumulated other comprehensive income into earnings (specifically included in other operation expenses) due to discontinuing cash flow hedge accounting and concluding that the retail marketing contracts being hedged beyond the expected sale date are no longer probable of physical delivery due to the expectation that the retail business will be sold.  At March 31, 2006, it is estimated that a negative $4.3 million will be reclassified as a decrease to earnings in the next year, primarily over the next two months in fuel, purchased and net interchange power, as a result of delivery on retail marketing contracts through May of 2006.

Accumulated other comprehensive income items unrelated to NU's cash flow hedging instruments totaled $2.5 million and $1.8 million in gains at March 31, 2006 and December 31, 2005, respectively.  These amounts relate to unrealized gains on investments in marketable debt and equity securities and minimum pension liability adjustments, net of related income taxes.

10.

EARNINGS PER SHARE (NU)

Earnings per share (EPS) is computed based upon the weighted average number of common shares outstanding, excluding unallocated Employee Stock Ownership Plan (ESOP) shares, during each period.  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.  At March 31, 2006 and 2005, 1,739,430 options and 1,507,145 options, respectively, were excluded from the following table as these options were antidilutive.  The weighted average common shares outstanding at March 31, 2006 include the impact of the issuance of 23 million common shares on December 12, 2005.  The following table sets forth the components of basic and fully diluted EPS:

	For the Three Months Ended March 31,
(Millions of Dollars, Except for Share Information)	2006	2005
Loss from continuing operations	$(20.7)	$(113.3)
Income/(loss) from discontinued operations	10.6	(4.4)
Net loss	(10.1)	(117.7)
Basic EPS common shares outstanding (average)	153,442,640	129,278,505
Dilutive effects of employee stock options	-	-
Fully diluted EPS common shares   outstanding (average)	153,442,640	129,278,505
Basic and Fully Diluted EPS:
Loss from continuing operations	(0.13)	(0.88)
Income/(loss) from discontinued operations	0.06	(0.03)
Basic and fully diluted EPS	$(0.07)	$ (0.91)

11.

PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS (All Companies)

NU’s subsidiaries participate in a uniform noncontributory defined benefit retirement plan (Pension Plan) covering substantially all regular NU employees and also provide certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired employees (PBOP Plan).  The components of net periodic benefit expense for the Pension Plan and the PBOP Plan for the three months ended March 30, 2006 and 2005 are estimated as follows:

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NU	For the Three Months Ended March 31,
	Pension Benefits		Postretirement Benefits
(Millions of Dollars)	2006	2005	2006	2005
Service cost	$12.3	$12.3	$ 1.9	$  1.9
Interest cost	32.3	31.2	6.8	6.3
Expected return on plan assets	(43.5)	(43.0)	(3.5)	(2.8)
Amortization of unrecognized net   transition (asset)/obligation	-	(0.1)	2.8	3.0
Amortization of prior service cost	1.5	1.8	(0.1)	(0.1)
Amortization of actuarial loss	10.3	8.1	-	-
Other amortization, net	-	-	4.5	4.3
Total - net periodic expense	$12.9	$10.3	$12.4	$12.6

A portion of these pension amounts is capitalized related to current employees that are working on capital projects.  Amounts capitalized were approximately $2.6 million and $2.3 million for the three months ended March 31, 2006 and 2005, respectively.

CL&P	For the Three Months Ended March 31,
	Pension Benefits		Postretirement Benefits
(Millions of Dollars)	2006	2005	2006	2005
Service cost	$  4.4	$  4.5	$  0.7	$  0.7
Interest cost	12.0	11.7	2.7	2.6
Expected return on plan assets	(20.3)	(20.0)	(1.4)	(1.1)
Amortization of unrecognized net   transition obligation	-	-	1.5	1.5
Amortization of prior service cost	0.7	0.7	-	-
Amortization of actuarial loss	4.0	3.1	-	-
Other amortization, net	-	-	1.8	1.7
Total - net periodic expense	$  0.8	$     -	$  5.3	$  5.4

Not included in the pension and postretirement benefits expense amounts above are intercompany allocations totaling $3.3 million and $2.0 million, respectively, for the three months ended March 31, 2006 and $1.9 million and $1.8 million, respectively, for the three months ended March 31, 2005.

For CL&P, a portion of the pension amounts is capitalized related to current employees that are working on capital projects.  Amounts capitalized were $1 million and $0.2 million for the three months ended March 31, 2006 and 2005, respectively.  

PSNH	For the Three Months Ended March 31,
	Pension Benefits		Postretirement Benefits
(Millions of Dollars)	2006	2005	2006	2005
Service cost	$2.4	$2.2	$0.4	$0.4
Interest cost	5.0	4.7	1.2	1.1
Expected return on plan assets	(4.1)	(4.1)	(0.6)	(0.5)
Amortization of unrecognized net   transition obligation	0.1	0.1	0.6	0.6
Amortization of prior service cost	0.3	0.4	-	-
Amortization of actuarial loss	1.5	1.1	-	-
Other amortization, net	-	-	0.8	0.8
Total - net periodic expense	$5.2	$4.4	$2.4	$2.4

Not included in the pension and postretirement benefits expense amounts above are intercompany allocations totaling $0.5 million and $0.4 million, respectively, for the three months ended March 31, 2006 and $0.4 million and $0.3 million, respectively, for the three months ended March 31, 2005.

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For PSNH, a portion of these pension amounts is capitalized related to current employees that are working on capital projects.  Amounts capitalized were $1.4 million and $1.2 million for the three months ended March 31, 2006 and 2005, respectively.  

WMECO	For Three Months Ended March 31,
	Pension Benefits		Postretirement Benefits
(Millions of Dollars)	2006	2005	2006	2005
Service cost	$0.9	$0.8	$0.2	$0.2
Interest cost	2.4	2.3	0.6	0.5
Expected return on plan assets	(4.4)	(4.4)	(0.4)	(0.3)
Amortization of unrecognized net   transition obligation	-	-	0.3	0.3
Amortization of prior service cost	0.1	0.2	-	-
Amortization of actuarial loss	0.8	0.6	-	-
Other amortization, net	-	-	0.4	0.4
Total - net periodic (income)/expense	$(0.2)	$(0.5)	$1.1	$1.1

Not included in the pension income and postretirement benefits expense amounts above are intercompany allocations totaling $0.5 million and $0.3 million, respectively, for the three months ended March 31, 2006 and $0.4 million and $0.3 million, respectively, for the three months ended March 31, 2005.  

For WMECO, a portion of these pension amounts is capitalized related to current employees that are working on capital projects.  Amounts capitalized for the three months ended March 31, 2006 were immaterial.  Amounts capitalized were $0.1 million for the three months ended March 31, 2005.  The capitalized amounts offset capital project costs, as pension income was recorded for the three months ended March 31, 2006 and 2005 as noted in the above table.  

NU does not currently expect to make any contributions to the Pension Plan in 2006.  NU contributed and anticipates contributing approximately $12.4 million quarterly totaling approximately $49.5 million in 2006 to fund its PBOP Plan.  

12.

SEGMENT INFORMATION (All Companies)

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 on January 1, 2005, the portion of Northeast Generation Services Company's (NGS's) business that supports Northeast Generation Services Company (NGC's) and HWP's generation assets has been reclassified from the services and other segment to the merchant energy segment within the NU Enterprises segment.  Cash flows for total investments in plant included in the segment information below are cash capital expenditures that do not include cost of removal, AFUDC, and the capitalized portion of pension expense or income.  Segment information for all periods presented has been restated to conform to the current period presentation, except as indicated.  

Effective on January 1, 2006, separate financial information was prepared and used by management for each of the NU Enterprises merchant energy businesses it is exiting.  Accordingly, separate detailed information is presented below for the wholesale and retail marketing and competitive generation businesses for the three months ended March 31, 2006.  It is not practicable to prepare comparable detailed information for any periods prior to January 1, 2006, due to the manner in which the merchant energy business operated prior to January 1, 2006.  

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 76 percent and 63 percent of NU's total revenues for the three months ended March 31, 2006 and 2005, respectively, and includes the operations of the regulated electric utilities, CL&P, PSNH and WMECO, whose complete condensed consolidated financial statements are included in this combined report on Form 10-Q.  PSNH's distribution segment includes generation activities.  Also included in this combined report on Form 10-Q 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 primarily are derived from residential, commercial and industrial customers and are not dependent on any single customer.

The NU Enterprises merchant energy business segment includes:  1) Select Energy, consisting of the wholesale and retail marketing businesses; and 2) NGC, NGS, and Mt. Tom, collectively referred to as the competitive generation businesses.  The NU Enterprises services and other business segment includes E. S. Boulos Company, Woods Electrical Co., Inc., and NGS Mechanical, Inc., (which are subsidiaries of NGS), SESI, SECI, HEC/Tobyhanna Energy Project, Inc. and HEC/CJTS Energy Center LLC, and intercompany eliminations between the energy services businesses and merchant energy businesses.  The results of NU Enterprises parent are also included within services and other.  For further information regarding NU Enterprises' businesses, which are being exited, see Note 2,

29

"Wholesale Contract Market Changes," Note 3, "Restructuring and Impairment Charges," and Note 4, "Assets Held for Sale and Discontinued Operations," to the condensed 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-generation 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.  

Intercompany Transactions:  Total Select Energy revenues from CL&P, represented approximately $3.3 million and $14.2 million  for the three months ended March 31, 2006 and 2005, respectively, of total NU Enterprises’ revenues.  Total CL&P purchases from Select Energy are eliminated in consolidation.

Select Energy revenues from WMECO for standard offer and default service and for other transactions with Select Energy represented $0.5 million and $20.5 million of total NU Enterprises’ revenues for the three months ended March 31, 2006 and 2005, respectively.  Total WMECO purchases from Select Energy are eliminated in consolidation.

Select Energy purchases from NGC and Mt. Tom represented approximately $35.7 million and $14.2 million for the three months ended March 31, 2006, respectively.  These amounts totaled $39.5 million and $13.3 million for NGC and Mt. Tom, respectively, for the three months ended March 31, 2005.

Customer Concentrations:  Select Energy revenues related to contracts with NSTAR companies represented $206.4 million of total NU Enterprises’ revenues for the three months ended March 31, 2005.  There were no sales to NSTAR for the three months ended March 31, 2006.  Select Energy also provides basic generation service in the New Jersey and Maryland markets.  Select Energy revenues related to these contracts represented $132.5 million and $108 million of total NU Enterprises’ revenues for the three months ended March 31, 2006 and 2005, respectively.  No other individual customer represented in excess of 10 percent of NU Enterprises’ revenues for the three months ended March 31, 2006 and 2005.

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 three months ended March 31, 2006 and 2005 is as follows (some amounts between the financial statements and between segment schedules may not agree due to rounding):

	For the Three Months Ended March 31, 2006
	Utility Group
	Distribution (1)
(Millions of Dollars)	Electric	Gas	Transmission	NU Enterprises	Other	Eliminations	Total
Operating revenues	$1,400.7	$   184.1	$48.4	$   527.0	$    87.7	$(100.5)	$ 2,147.4
Depreciation and amortization	(151.9)	(5.7)	(8.2)	(0.3)	(4.6)	3.5	(167.2)
Wholesale contract market   changes, net	- -	- -	- -	(6.8)	- -	- -	(6.8)
Restructuring and   impairment charges	- -	- -	- -	(5.1)	- -	- -	(5.1)
Other operating expenses	(1,176.6)	(156.2)	(19.8)	(621.7)	(82.8)	96.2	(1,960.9)
Operating income/(loss)	72.2	22.2	20.4	(106.9)	0.3	(0.8)	7.4
Interest expense, net of AFUDC	(42.1)	(4.4)	(4.0)	(8.7)	(8.9)	6.9	(61.2)
Interest income	3.5	-	0.1	2.1	7.2	(7.3)	5.6
Other income/(loss), net	10.2	(0.1)	(0.2)	(0.1)	60.6	(59.8)	10.6
Income tax (expense)/benefit	(12.6)	(5.9)	(3.3)	40.4	(0.3)	-	18.3
Preferred dividends	(1.1)	-	(0.3)	-	-	-	(1.4)
Income/(loss) from   continuing operations	30.1	11.8	12.7	(73.2)	58.9	(61.0)	(20.7)
Income/(loss) from   discontinued operations	- -	- -	- -	10.6	- -	- -	10.6
Net income/(loss)	$      30.1	$     11.8	$12.7	$   (62.6)	$     58.9	$     (61.0)	$      (10.1)
Total assets (2)	$ 9,046.2	$1,154.1	N/A	$1,922.9	$4,878.5	$(4,867.1)	$12,134.6
Cash flows for total  investments in plant	$      79.5	$     17.8	$90.2	$      5.0	$    11.3	$      -	$     203.8

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	For the Three Months Ended March 31, 2005
	Utility Group
	Distribution (1)
(Millions of Dollars)	Electric	Gas	Transmission	NU Enterprises	Other	Eliminations	Total
Operating revenues	$1,175.4	$194.9	$36.7	$    872.7	$86.1	$(132.8)	$2,233.0
Depreciation and amortization	(110.4)	(5.4)	(5.6)	(1.6)	(4.3)	3.3	(124.0)
Wholesale contract market   changes, net	- -	- -	- -	(188.9)	- -	- -	(188.9)
Restructuring and   impairment charges	- -	- -	- -	(21.5)	- -	- -	(21.5)
Other operating expenses	(981.7)	(162.2)	(15.3)	(910.4)	(83.4)	128.2	(2,024.8)
Operating income/(loss)	83.3	27.3	15.8	(249.7)	(1.6)	(1.3)	(126.2)
Interest expense, net of AFUDC	(41.4)	(4.3)	(2.9)	(3.5)	(8.0)	3.8	(56.3)
Interest income	1.0	0.1	0.1	0.6	4.1	(4.5)	1.4
Other income/(loss), net	4.8	(0.3)	(0.6)	(0.7)	46.5	(45.3)	4.4
Income tax (expense)/benefit	(16.4)	(7.9)	(3.6)	90.3	2.4	-	64.8
Preferred dividends	(1.0)	-	(0.4)	-	-	-	(1.4)
Income/(loss) from   continuing operations	30.3	14.9	8.4	(163.0)	43.4	(47.3)	(113.3)
Income/(loss) from   discontinued operations	- -	- -	- -	(4.4)	- -	- -	(4.4)
Net income/(loss)	$     30.3	$ 14.9	$  8.4	$   (167.4)	$43.4	$(47.3)	$  (117.7)
Cash flows for total   investments in plant	$   103.1	$ 12.0	$41.6	$         5.8	$  4.3	$       -	$   166.8

(1)

Includes PSNH's generation activities.  

(2)

Information for segmenting total assets between electric distribution and transmission is not available at March 31, 2006.  On a NU consolidated basis, these distribution and transmission assets are disclosed in the electric distribution column above.  

Utility Group segment information related to the regulated electric distribution and transmission businesses for CL&P, PSNH and WMECO for the three months ended March 31, 2006 and 2005 is as follows:

	CL&P - For the Three Months Ended March 31, 2006
(Millions of Dollars)	Distribution	Transmission	Totals
Operating revenues	$972.0	$32.8	$1,004.8
Depreciation and amortization	(62.1)	(6.4)	(68.5)
Other operating expenses	(863.7)	(12.7)	(876.4)
Operating income	46.2	13.7	59.9
Interest expense, net of AFUDC	(27.1)	(2.8)	(29.9)
Interest income	3.2	0.1	3.3
Other income/(loss), net	8.9	(0.2)	8.7
Income tax expense	(6.7)	(1.4)	(8.1)
Preferred dividends	(1.1)	(0.3)	(1.4)
Net income	$ 23.4	$  9.1	$     32.5
Cash flows for total investments in plant	$ 43.9	$80.3	$   124.2

	CL&P - For the Three Months Ended March 31, 2005
(Millions of Dollars)	Distribution	Transmission	Totals
Operating revenues	$   814.9	$24.0	$  838.9
Depreciation and amortization	(55.5)	(4.1)	(59.6)
Other operating expenses	(708.6)	(9.1)	(717.7)
Operating income	50.8	10.8	61.6
Interest expense, net of AFUDC	(26.5)	(1.9)	(28.4)
Interest income	0.8	0.1	0.9
Other income/(loss), net	5.0	(0.7)	4.3
Income tax expense	(9.7)	(2.1)	(11.8)
Preferred dividends	(1.0)	(0.4)	(1.4)
Net income	$     19.4	$  5.8	$    25.2
Cash flows for total investments in plant	$     60.8	$30.5	$    91.3

31

	PSNH - For the Three Months Ended March 31, 2006
(Millions of Dollars)	Distribution (1)	Transmission	Totals
Operating revenues	$304.6	$10.7	$315.3
Depreciation and amortization	(85.2)	(1.3)	(86.5)
Other operating expenses	(203.9)	(4.5)	(208.4)
Operating income	15.5	4.9	20.4
Interest expense, net of AFUDC	(10.7)	(0.8)	(11.5)
Interest income	0.2	-	0.2
Other income, net	0.7	-	0.7
Income tax expense	(3.2)	(1.5)	(4.7)
Net income	$   2.5	$ 2.6	$    5.1
Cash flows for total investments in plant	$ 29.1	$ 6.0	$  35.1

	PSNH - For the Three Months Ended March 31, 2005
(Millions of Dollars)	Distribution (1)	Transmission	Totals
Operating revenues	$ 260.3	$8.6	$268.9
Depreciation and amortization	(49.8)	(1.0)	(50.8)
Other operating expenses	(189.2)	(4.2)	(193.4)
Operating income	21.3	3.4	24.7
Interest expense, net of AFUDC	(10.9)	(0.6)	(11.5)
Interest income	-	-	-
Other income, net	-	0.1	0.1
Income tax expense	(3.5)	(1.0)	(4.5)
Net income	$     6.9	$1.9	$   8.8
Cash flows for total investments in plant	$   33.1	$7.2	$ 40.3

(1)

Includes PSNH's generation activities.  

	WMECO  - For the Three Months Ended March 31, 2006
(Millions of Dollars)	Distribution	Transmission	Totals
Operating revenues	$124.0	$5.0	$129.0
Depreciation and amortization	(4.5)	(0.6)	(5.1)
Other operating expenses	(109.2)	(2.5)	(111.7)
Operating income	10.3	1.9	12.2
Interest expense, net of AFUDC	(4.3)	(0.5)	(4.8)
Interest income	0.2	-	0.2
Other income, net	0.6	-	0.6
Income tax expense	(2.6)	(0.4)	(3.0)
Net income	$  4.2	$1.0	$  5.2
Cash flows for total investments in plant	$  6.6	$3.8	$10.4

	WMECO  - For the Three Months Ended March 31, 2005
(Millions of Dollars)	Distribution	Transmission	Totals
Operating revenues	$100.2	$4.1	$104.3
Depreciation and amortization	(5.1)	(0.5)	(5.6)
Other operating expenses	(83.9)	(2.0)	(85.9)
Operating income	11.2	1.6	12.8
Interest expense, net of AFUDC	(4.0)	(0.5)	(4.5)
Interest income	0.1	-	0.1
Income tax expense	(3.3)	(0.4)	(3.7)
Net income	$    4.0	$0.7	$   4.7
Cash flows for total investments in plant	$    7.5	$3.5	$ 11.0

32

NU Enterprises' segment information for the three months ended March 31, 2006 and 2005 is as follows.  The services and other column includes eliminations relating to the total merchant energy business and the energy services businesses.

	NU Enterprises – For the Three Months Ended March 31, 2006
(Millions of Dollars)	Wholesale	Retail	Generation	Total Merchant Energy	Services and Other	Totals
Operating revenues	$9.2	$409.1	$94.9	$513.2	$13.8	$527.0
Depreciation and amortization	-	-	(0.2)	(0.2)	(0.1)	(0.3)
Wholesale contract market   changes, net	(6.8)	- -	- -	(6.8)	- -	(6.8)
Restructuring and impairment   charges	- -	(3.0)	- -	(3.0)	(2.1)	(5.1)
Other operating expenses	(2.2)	(514.1)	(90.6)	(606.9)	(14.8)	(621.7)
Operating income/(loss)	0.2	(108.0)	4.1	(103.7)	(3.2)	(106.9)
Interest expense	(3.1)	(2.7)	(2.9)	(8.7)	-	(8.7)
Interest income	0.4	0.8	0.7	1.9	0.2	2.1
Other loss, net	(0.4)	-	0.3	(0.1)	-	(0.1)
Income tax benefit	1.0	38.3	0.1	39.4	1.0	40.4
Loss from continuing operations	(1.9)	(71.6)	2.3	(71.2)	(2.0)	(73.2)
Income/(loss) from discontinued   operations	- -	- -	11.7	11.7	(1.1)	10.6
Net loss	$(1.9)	$ (71.6)	$14.0	$ (59.5)	$(3.1)	$ (62.6)

	NU Enterprises - For the Three Months Ended March 31, 2005
(Millions of Dollars)	Total Merchant Energy	Services and Other	Totals
Operating revenues	$  847.0	$ 25.7	$ 872.7
Depreciation and amortization	(1.4)	(0.2)	(1.6)
Wholesale contract market   changes, net	(188.9)	- -	(188.9)
Restructuring and impairment charges	(7.2)	(14.3)	(21.5)
Other operating expenses	(883.5)	(26.9)	(910.4)
Operating loss	(234.0)	(15.7)	(249.7)
Interest expense	(3.4)	(0.1)	(3.5)
Interest income	0.4	0.2	0.6
Other loss, net	(0.7)	-	(0.7)
Income tax benefit	86.5	3.8	90.3
Loss from continuing operations	(151.2)	(11.8)	(163.0)
Income/(loss) from   discontinued operations	12.8	(17.2)	(4.4)
Net loss	$(138.4)	$(29.0)	$(167.4)

13.

SUBSEQUENT EVENTS (NU Enterprises)

On May 1, 2006, NU Enterprises signed a definitive agreement to sell its retail marketing business to Amerada Hess Corporation (Amerada Hess) with a closing date expected around June 1, 2006.  Under the terms of the agreement, Select Energy will pay Amerada Hess approximately $44 million, subject to mark-to-market and other closing adjustments that are not expected to be material, and Amerada Hess will acquire Select Energy’s ongoing retail marketing business, including all of its retail supply obligations.  The terms reflect the positive value of the retail marketing business net of the current negative value of the retail sales contracts, which Select Energy is selling separate from the generation resources of NGC and Mt. Tom.

On May 5, 2006, NU Enterprises completed the sale of SESI.  In connection with the closing of this transaction, NU Enterprises paid the buyer approximately $7.7 million and will record a pre-tax charge to income of approximately $6 million in the second quarter of 2006.  In connection with this sale, the company anticipates that the balance of more than $90 million of NU parent guarantees associated with SESI's outstanding debt will be eliminated by March of 2007, with over $80 million being eliminated by the end of 2006.

33

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Trustees and Shareholders of

Northeast Utilities

Berlin, Connecticut

We have reviewed the accompanying condensed consolidated balance sheet of Northeast Utilities and subsidiaries (the "Company") as of March 31, 2006, and the related condensed consolidated statements of loss and of cash flows for the three-month periods ended March 31, 2006 and 2005.  These interim financial statements are the responsibility of the Company’s management.

We conducted our reviews in accordance with the standards of the Public Company Accounting Oversight Board (United States).  A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters.  It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole.  Accordingly, we do not express such an opinion.

Based on our reviews, we are not aware of any material modifications that should be made to such condensed consolidated interim financial statements for them to be 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 three-month periods ended March 31, 2006 and 2005 in connection with its decision to exit certain business lines.  Also, as discussed in Note 4, prior period financial statements have been restated to include certain components of the Company’s generation business as discontinued operations.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet and consolidated statement of capitalization of Northeast Utilities and subsidiaries as of December 31, 2005, and the related consolidated statements of loss, comprehensive loss, shareholders’ equity, and cash flows for the year then ended (not presented herein); and in our report dated March 7, 2006 (which report included explanatory paragraphs related to the recording of significant charges in connection with the Company’s decision to exit certain business lines and, the presentation of certain components of the Company’s energy services businesses as discontinued operations), we expressed an unqualified opinion on those consolidated financial statements.  In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2005 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/	Deloitte & Touche LLP
	Deloitte & Touche LLP

Hartford, Connecticut

May 5, 2006

34

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

35

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,	December 31,
	2006	2005
	(Thousands of Dollars)
ASSETS
Current Assets:
Cash	$                 3,984	$               2,301
Investments in securitizable assets	241,652	252,801
Receivables, less provision for uncollectible
accounts of $1,890 in 2006 and $1,982 in 2005	59,665	80,883
Accounts receivable from affiliated companies	2,424	17,214
Unbilled revenues	7,883	7,888
Taxes receivable	26,067	-
Materials and supplies	33,725	32,929
Derivative assets - current	57,296	82,578
Prepayments and other	25,040	18,003
	457,736	494,597
Property, Plant and Equipment:
Electric utility	4,086,667	3,997,652
Less: Accumulated depreciation	1,196,058	1,175,164
	2,890,609	2,822,488
Construction work in progress	373,717	344,204
	3,264,326	3,166,692
Deferred Debits and Other Assets:
Regulatory assets	1,422,432	1,357,985
Prepaid pension	314,989	315,532
Derivative assets - long-term	280,373	308,648
Other	134,070	121,618
	2,151,864	2,103,783
Total Assets	$          5,873,926	$        5,765,072
The accompanying notes are an integral part of these condensed consolidated financial statements.

36

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,	December 31,
	2006	2005
	(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION
Current Liabilities:
Notes payable to banks	$             125,000	$                      -
Notes payable to affiliated companies	121,425	26,825
Accounts payable	321,255	253,974
Accounts payable to affiliated companies	26,030	39,755
Accrued taxes	-	60,531
Accrued interest	15,158	16,947
Derivative liabilities - current	6,380	477
Other	61,016	70,025
	676,264	468,534
Rate Reduction Bonds	817,304	856,479
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	851,900	774,190
Accumulated deferred investment tax credits	85,318	85,970
Deferred contractual obligations	226,441	243,279
Regulatory liabilities	602,512	742,993
Derivative liabilities - long-term	34,339	31,774
Other	128,337	131,253
	1,928,847	2,009,459
Capitalization:
Long-Term Debt	1,261,255	1,258,883
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 2006 and 2005	60,352	60,352
Capital surplus, paid in	612,950	612,815
Retained earnings	399,135	382,628
Accumulated other comprehensive income/(loss)	1,619	(278)
Common Stockholder's Equity	1,074,056	1,055,517
Total Capitalization	2,451,511	2,430,600
Commitments and Contingencies (Note 7)
Total Liabilities and Capitalization	$          5,873,926	$        5,765,072
The accompanying notes are an integral part of these condensed consolidated financial statements.

37

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
	Three Months Ended
	March 31,
	2006	2005
	(Thousands of Dollars)
Operating Revenues	$       1,004,760	$           838,901
Operating Expenses:
Operation -
Fuel, purchased and net interchange power	664,927	536,685
Other	143,953	116,374
Maintenance	20,452	18,675
Depreciation	35,739	32,452
Amortization of regulatory liabilities, net	(649)	(4,254)
Amortization of rate reduction bonds	33,453	31,380
Taxes other than income taxes	47,046	45,990
Total operating expenses	944,921	777,302
Operating Income	59,839	61,599
Interest Expense:
Interest on long-term debt	15,854	12,775
Interest on rate reduction bonds	12,584	14,768
Other interest	1,445	902
Interest expense, net	29,883	28,445
Other Income, Net	12,000	5,166
Income Before Income Tax Expense	41,956	38,320
Income Tax Expense	8,126	11,787
Net Income	$            33,830	$             26,533
The accompanying notes are an integral part of these condensed consolidated financial statements.

38

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Three Months Ended
	March 31,
	2006	2005
	(Thousands of Dollars)
Operating Activities:
Net income	$                33,830	$               26,533
Adjustments to reconcile to net cash flows
(used in)/provided by operating activities:
Bad debt expense	2,909	3,563
Depreciation	35,739	32,452
Deferred income taxes	72,674	26,599
Amortization of regulatory liabilities, net	(649)	(4,254)
Amortization of rate reduction bonds	33,453	31,380
Deferral of recoverable energy costs	(72,642)	(31,726)
Pension expense	420	275
Regulatory refunds	(100,683)	(30,154)
Deferred contractual obligations	(16,838)	(13,421)
Other non-cash adjustments	(8,569)	(3,044)
Other sources of cash	2,342	1,712
Other uses of cash	(12,526)	(3,100)
Changes in current assets and liabilities:
Receivables and unbilled revenues, net	33,104	(19,781)
Materials and supplies	(796)	(800)
Investments in securitizable assets	11,149	(50,288)
Other current assets	(6,983)	(4,861)
Accounts payable	56,996	49,179
Accrued taxes	(86,598)	3,293
Other current liabilities	(10,815)	(6,819)
Net cash flows (used in)/provided by operating activities	(34,483)	6,738
Investing Activities:
Investments in plant	(124,212)	(91,254)
Proceeds from sales of investment securities	245	373
Purchases of investment securities	(254)	(382)
Other investing activities	(2,553)	(4,808)
Net cash flows used in investing activities	(126,774)	(96,071)
Financing Activities:
Retirement of rate reduction bonds	(39,175)	(36,748)
Capital contribution from Northeast Utilities	-	22,000
Increase in short-term debt	125,000	67,000
NU Money Pool borrowing	94,600	47,500
Cash dividends on preferred stock	(1,390)	(1,390)
Cash dividends on common stock	(15,933)	(13,459)
Other financing activities	(162)	7
Net cash flows provided by financing activities	162,940	84,910
Net increase/(decrease) in cash	1,683	(4,423)
Cash - beginning of period	2,301	5,608
Cash - end of period	$                  3,984	$                 1,185
The accompanying notes are an integral part of these condensed consolidated financial statements.

39

This Page Intentionally Left Blank

40

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

41

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,	December 31,
	2006	2005
	(Thousands of Dollars)
ASSETS
Current Assets:
Cash	$               4,468	$                    27
Receivables, less provision for uncollectible
accounts of $2,401 in 2006 and $2,362 in 2005	94,541	95,599
Accounts receivable from affiliated companies	21,709	20,348
Unbilled revenues	50,662	47,705
Notes receivable from affiliated companies	4,100	-
Fuel, materials and supplies	74,364	72,820
Prepayments and other	8,470	11,987
	258,314	248,486
Property, Plant and Equipment:
Electric utility	1,749,546	1,732,716
Other	5,816	5,816
	1,755,362	1,738,532
Less: Accumulated depreciation	708,295	698,480
	1,047,067	1,040,052
Construction work in progress	128,438	115,371
	1,175,505	1,155,423
Deferred Debits and Other Assets:
Regulatory assets	795,482	821,951
Other	74,401	68,723
	869,883	890,674
Total Assets	$        2,303,702	$        2,294,583
The accompanying notes are an integral part of these condensed consolidated financial statements.

42

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,	December 31,
	2006	2005
	(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION
Current Liabilities:
Notes payable to affiliated companies	$                      -	$             15,900
Accounts payable	61,549	63,320
Accounts payable to affiliated companies	25,264	16,738
Accrued taxes	30,836	5,186
Accrued interest	11,751	8,202
Other	11,718	15,733
	141,118	125,079
Rate Reduction Bonds	371,121	382,692
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	216,156	242,590
Accumulated deferred investment tax credits	1,142	1,230
Deferred contractual obligations	44,706	48,262
Regulatory liabilities	462,865	414,558
Accrued pension	81,693	76,446
Other	43,158	44,136
	849,720	827,222
Capitalization:
Long-Term Debt	507,089	507,086
Common Stockholder's Equity:
Common stock, $1 par value - authorized
100,000,000 shares; 301 shares outstanding
in 2006 and 2005	-	-
Capital surplus, paid in	209,765	209,788
Retained earnings	224,765	242,633
Accumulated other comprehensive income	124	83
Common Stockholder's Equity	434,654	452,504
Total Capitalization	941,743	959,590
Commitments and Contingencies (Note 7)
Total Liabilities and Capitalization	$        2,303,702	$        2,294,583
The accompanying notes are an integral part of these condensed consolidated financial statements.

43

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
	Three Months Ended March 31,
	2006	2005
	(Thousands of Dollars)
Operating Revenues	$           315,316	$             268,891
Operating Expenses:
Operation -
Fuel, purchased and net interchange power	142,238	126,231
Other	42,568	43,413
Maintenance	13,491	14,035
Depreciation	12,224	11,318
Amortization of regulatory assets, net	62,076	27,937
Amortization of rate reduction bonds	12,191	11,563
Taxes other than income taxes	10,095	9,719
Total operating expenses	294,883	244,216
Operating Income	20,433	24,675
Interest Expense:
Interest on long-term debt	5,724	4,772
Interest on rate reduction bonds	5,535	6,303
Other interest	230	363
Interest expense, net	11,489	11,438
Other Income, Net	887	96
Income Before Income Tax Expense	9,831	13,333
Income Tax Expense	4,699	4,545
Net Income	$               5,132	$                 8,788
The accompanying notes are an integral part of these condensed consolidated financial statements.

44

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Three Months Ended
	March 31,
	2006		2005
	(Thousands of Dollars)
Operating activities:
Net income	$                   5,132	$                   8,788
Adjustments to reconcile to net cash flows
provided by operating activities:
Bad debt expense	849	1,235
Depreciation	12,224	11,318
Deferred income taxes	(25,760)	(13,505)
Amortization of regulatory assets, net	62,076	27,937
Amortization of rate reduction bonds	12,191	11,563
Pension expense	3,887	3,201
Regulatory overrecoveries	(333)	2,727
Deferred contractual obligations	(3,556)	(2,908)
Other non-cash adjustments	(1,794)	(752)
Other sources of cash	-	4
Other uses of cash	(3,692)	(12,430)
Changes in current assets and liabilities:
Receivables and unbilled revenues, net	(4,109)	(33,419)
Fuel, materials and supplies	(1,544)	2,866
Other current assets	3,609	10,403
Accounts payable	12,872	14,002
Accrued taxes	25,650	124
Other current liabilities	(440)	(149)
Net cash flows provided by operating activities	97,262	31,005
Investing Activities:
Investments in plant	(35,099)	(40,252)
Proceeds from sales of investment securities	420	639
Purchases of investment securities	(436)	(654)
NU Money Pool lending	(4,100)	-
Other investing activities	(3,075)	(3,305)
Net cash flows used in investing activities	(42,290)	(43,572)
Financing Activities:
Retirement of rate reduction bonds	(11,571)	(10,714)
Increase in short-term debt	-	10,000
NU Money Pool (lending)/borrowing	(15,900)	15,900
Cash dividends on common stock	(23,000)	(6,128)
Other financing activities	(60)	88
Net cash flows (used in)/provided by financing activities	(50,531)	9,146
Net increase/(decrease) in cash	4,441	(3,421)
Cash - beginning of period	27	4,855
Cash - end of period	$                   4,468	$                   1,434
The accompanying notes are an integral part of these condensed consolidated financial statements.

45

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46

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

47

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,	December 31,
	2006	2005
	(Thousands of Dollars)
ASSETS
Current Assets:
Cash	$                  1,127	$                      1
Receivables, less provision for uncollectible
accounts of $4,129 in 2006 and $3,653 in 2005	43,088	43,490
Accounts receivable from affiliated companies	6,310	5,752
Unbilled revenues	19,278	16,411
Taxes receivable	1,549	-
Materials and supplies	1,417	1,414
Marketable securities	21,617	20,905
Prepayments and other	730	897
	95,116	88,870
Property, Plant and Equipment:
Electric utility	678,361	671,292
Less: Accumulated depreciation	195,296	193,151
	483,065	478,141
Construction work in progress	22,595	21,176
	505,660	499,317
Deferred Debits and Other Assets:
Regulatory assets	234,220	223,174
Prepaid pension	80,927	80,618
Marketable securities	30,256	30,434
Other	24,721	23,583
	370,124	357,809
Total Assets	$              970,900	$           945,996
The accompanying notes are an integral part of these condensed consolidated financial statements.

48

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
		March 31,	December 31,
		2006	2005
	(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION
Current Liabilities:
Notes payable to banks		$              10,000	$                      -
Notes payable to affiliated companies		17,900	14,900
Accounts payable		32,742	31,333
Accounts payable to affiliated companies		7,666	9,015
Accrued taxes		693	1,620
Accrued interest		1,682	4,517
Other		8,504	9,364
		79,187	70,749
Rate Reduction Bonds		108,267	111,331
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		224,667	219,992
Accumulated deferred investment tax credits		2,571	2,655
Deferred contractual obligations		61,997	66,633
Regulatory liabilities		24,095	23,836
Other		13,091	11,977
		326,421	325,093
Capitalization:
Long-Term Debt		260,018	259,487
Common Stockholder's Equity:
Common stock, $25 par value - authorized
1,072,471 shares; 434,653 shares outstanding
in 2006 and 2005		10,866	10,866
Capital surplus, paid in		97,311	82,811
Retained earnings		88,156	84,965
Accumulated other comprehensive income		674	694
Common Stockholder's Equity		197,007	179,336
Total Capitalization		457,025	438,823
Commitments and Contingencies (Note 7)
Total Liabilities and Capitalization		$            970,900	$           945,996
The accompanying notes are an integral part of these condensed consolidated financial statements.

49

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
	Three Months Ended
	March 31,
	2006	2005
	(Thousands of Dollars)
Operating Revenues	$             129,040	$           104,335
Operating Expenses:
Operation -
Fuel, purchased and net interchange power	88,875	62,698
Other	15,522	15,994
Maintenance	3,832	3,838
Depreciation	4,293	4,027
Amortization of regulatory liabilities, net	(2,186)	(1,253)
Amortization of rate reduction bonds	3,034	2,847
Taxes other than income taxes	3,478	3,416
Total operating expenses	116,848	91,567
Operating Income	12,192	12,768
Interest Expense:
Interest on long-term debt	2,744	2,177
Interest on rate reduction bonds	1,762	1,968
Other interest	248	337
Interest expense, net	4,754	4,482
Other Income, Net	764	137
Income Before Income Tax Expense	8,202	8,423
Income Tax Expense	3,025	3,696
Net Income	$                 5,177	$               4,727
The accompanying notes are an integral part of these condensed consolidated financial statements.

50

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Three Months Ended
	March, 31
	2006	2005
	(Thousands of Dollars)
Operating Activities:
Net income	$                   5,177	$                  4,727
Adjustments to reconcile to net cash flows
(used in)/provided by operating activities:
Bad debt expense	1,077	893
Depreciation	4,293	4,027
Deferred income taxes	4,953	(574)
Amortization of regulatory liabilities, net	(2,186)	(1,253)
Amortization of rate reduction bonds	3,034	2,847
Pension income	(143)	(214)
Regulatory (underrecoveries)/overrecoveries	(12,098)	4,820
Deferred contractual obligations	(4,636)	(3,668)
Other non-cash adjustments	(1,945)	(753)
Other sources of cash	1,670	552
Other uses of cash	(568)	(5,092)
Changes in current assets and liabilities:
Receivables and unbilled revenues, net	(4,100)	(8,640)
Materials and supplies	(3)	105
Other current assets	167	5,546
Accounts payable	1,577	5,967
Accrued taxes	(2,476)	1,893
Other current liabilities	(3,695)	(3,034)
Net cash flows (used in)/provided by operating activities	(9,902)	8,149
Investing Activities:
Investments in plant	(10,385)	(10,972)
Proceeds from sales of investment securities	11,279	8,010
Purchases of investment securities	(11,839)	(8,408)
Other investing activities	(477)	(241)
Net cash flows used in investing activities	(11,422)	(11,611)
Financing Activities:
Retirement of rate reduction bonds	(3,064)	(2,877)
Increase in short-term debt	10,000	5,000
Increase in NU Money Pool borrowing	3,000	2,200
Capital contribution from Northeast Utilities	14,500	-
Cash dividends on common stock	(1,986)	(1,921)
Other financing activities	-	23
Net cash flows provided by financing activities	22,450	2,425
Net increase/(decrease) in cash	1,126	(1,037)
Cash - beginning of period	1	1,678
Cash - end of period	$                   1,127	$                     641
The accompanying notes are an integral part of these condensed consolidated financial statements.

51

NORTHEAST UTILITIES AND SUBSIDIARIES

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

This discussion should be read in conjunction with the condensed consolidated financial statements and footnotes in this Form 10-Q, and the NU 2005 Form 10-K.  All per share amounts are reported on a fully diluted basis.

FINANCIAL CONDITION AND BUSINESS ANALYSIS

Executive Summary

The following items in this executive summary are explained in more detail in this quarterly report.

Results, Strategy and Outlook:

·

Northeast Utilities (NU or the company) lost $10.1 million, or $0.07 per share, in the first quarter of 2006, compared with a loss of $117.7 million, or $0.91 per share, in the first quarter of 2005.  The results for 2006 included net income of $54.6 million, or $0.35 per share, after payment of preferred dividends at the regulated Utility Group businesses and losses of $62.6 million, or $0.41 per share, at the competitive NU Enterprises businesses.  The NU Enterprises losses included a $39.1 million after-tax charge at its retail marketing business recorded in connection with exiting that business.

·

Earnings in the first quarter of 2006 at the Utility Group businesses included earnings of $12.7 million for the transmission businesses of The Connecticut Light & Power Company (CL&P), Public Service Company of New Hampshire (PSNH), and Western Massachusetts Electric Company (WMECO), compared with $8.4 million in the first quarter of 2005.  The $4.3 million in higher transmission earnings was due primarily to a higher level of transmission investment on which these companies earned a return.  Earnings at the distribution businesses of CL&P, PSNH, WMECO and Yankee Gas Services Company (Yankee Gas) and the regulated generation business of PSNH totaled $41.9 million in the first quarter of 2006, compared with $45.2 million in the first quarter of 2005.  Electric distribution and generation earnings were consistent with 2005, but natural gas distribution earnings were lower in 2006 as a result of a 13.5 percent decl ine in Yankee Gas firm natural gas sales mostly due to milder weather.  

·

Losses in the first quarter of 2006 for the NU Enterprises businesses were related to Select Energy, Inc.'s (Select Energy) retail marketing business as a result of an after-tax charge of $39.1 million which was recorded to reduce the book value of this business to its fair value less its cost to sell in order to reflect its held for sale status.  The improved results from 2005 reflect significant mark-to-market losses totaling $120.1 million recorded in 2005 associated with exiting the wholesale marketing business.

·

In 2005, NU announced decisions to exit all of its competitive businesses.  On May 1, 2006, NU Enterprises signed an agreement to sell the retail marketing business.  In connection with this agreement, NU Enterprises will pay the buyer $44 million, subject to mark-to-market and other closing adjustments that are not expected to be material.  By May of 2006, NU had sold four of its energy services businesses and portions of a fifth.  These businesses included 1) Select Energy Contracting, Inc. - New Hampshire (SECI-NH), a division of Select Energy Contracting, Inc. (SECI) (including Reeds Ferry Supply Co., Inc. (Reeds Ferry)) and 2) Woods Network Services, Inc. (Woods Network), which were sold in November of 2005, 3) the Massachusetts service location of Select Energy Contracting, Inc. - Connecticut (SECI-CT), which was sold in January of 2006, and 4) certain assets of Woods Electrical Co., Inc. (Woods Electrical), which were sold in April of 2006.  On May 5, 2006, NU Enterprises completed the sale of Select Energy Services, Inc. (SESI).   

·

NU continues to project 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.  

Legislative Items:

·

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.  A bill to implement that agreement passed the New Hampshire House of Representatives in late-March of 2006, passed the New Hampshire Senate on April 20, 2006 and will be sent to New Hampshire Governor Lynch for signing into law.  PSNH intends to comply with the legislation by installing wet scrubber technology at its two Merrimack coal

52

units, which combined generate 433 megawatts (MW) by mid-2013.  PSNH currently estimates the cost to comply of approximately $250 million, however, this amount is subject to change as final design is undertaken.  

Regulatory Items:

·

On September 9, 2005 the Connecticut Department of Public Utility Control (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.  The DPUC issued a new decision on April 20, 2006 requiring an audit of Yankee Gas' PGA accounting methods and deferring any conclusion on the $9 million of previously recovered revenues until the completion of the audit.  Based on the facts of the case and the supplemental information provided to the DPUC, notwithstanding the new decision, management believes the appropriateness of the PGA charges to customers for the time period under review will be approved.

·

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 Federal Energy Regulatory Commission (FERC) proposing a Forward Capacity Market (FCM) in place of the previously proposed Locational Installed Capacity (LICAP) mechanism.  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, PSNH and WMECO expect to recover these costs from their customers.

·

On April 12, 2006, PSNH notified the New Hampshire Public Utilities Commission (NHPUC) that it will seek to reduce Stranded Cost Recovery Charge (SCRC) charges by approximately $170 million annually and to reduce Energy Service Rate (ES) charges by approximately $13 million annually due to declining fuel and purchased power costs.  PSNH also filed an application to increase delivery rates by approximately $34 million annually on a temporary basis.  PSNH requested that all of the rate changes, which in total would reduce customer bills by approximately 12.7 percent, be effective on July 1, 2006.  PSNH expects to file a request for a permanent delivery rate increase of approximately $50 million around May 30, 2006 with a decision on that rate increase expected in 2007.  The temporary rate increase will be reconciled to permanent rates and differences between the two rates will be reflected in customers' bills once permane nt rates become effective.  

·

On April 18, 2006, the Internal Revenue Service (IRS) issued a Private Letter Ruling (PLR) to CL&P regarding the treatment of unamortized investment tax credits (UITC) and excess deferred income taxes (EDIT) related to generation assets that CL&P has sold.  CL&P has submitted the PLR to the DPUC.  At March 31, 2006, CL&P's UITC balance is $59.3 million and EDIT balance is $14.7 million related to generation assets that have been sold.  The resolution of this contingency may result in these deferred tax balances being eliminated with a corresponding reduction to income tax expense.

Liquidity:

·

NU's capital expenditures totaled $203.8 million in the first three months of 2006, compared with $166.8 million in the first three months of 2005.  The increase in NU's capital expenditures was primarily the result of higher transmission capital expenditures, particularly at CL&P.  Utility Group capital expenditures are expected to approach approximately $900 million in 2006.  

·

Cash flows from operations decreased by $146.4 million from $189.1 million for the first three months of 2005 to $42.7 million for the first three months of 2006.  The decrease in operating cash flows is due primarily to higher regulatory refunds as CL&P refunded amounts to its ratepayers to moderate the increase in CL&P's transitional standard offer (TSO) rates which was effective on January 1, 2006.  The decrease in operating cash flows is also due to a federal income tax payment of approximately $55 million related to NU's 2005 tax return which was made in the first quarter of 2006.

Overview

Consolidated:  NU lost $10.1 million, or $0.07 per share, in the first quarter of 2006, compared with a loss of $117.7 million, or $0.91 per share, in the first quarter of 2005.  Earnings per share in 2006 includes the impact of the issuance of 23 million NU common shares on December 12, 2005.  A summary of NU's earnings/(losses) by major business line for the first quarter of 2006 and 2005 is as follows:

53

	For the Three Months Ended March 31,
	2006		2005
(Millions of Dollars, except per share amounts)	Amount	Per Share	Amount	Per Share
Utility Group	$ 54.6	$  0.35	$     53.6	$   0.41
NU Enterprises (1)	(62.6)	(0.41)	(167.4)	(1.29)
Parent and Other	(2.1)	(0.01)	(3.9)	(0.03)
Net Loss	$(10.1)	$(0.07)	$(117.7)	$(0.91)

(1)

A portion of NU Enterprises results are included in discontinued operations.  See the Overview – NU Enterprises section included in this management's discussion and analysis for further information.  

The earnings per share of any segment does not represent a direct legal interest in the assets and liabilities allocated to any one segment, but rather represents a direct equity interest in NU's assets and liabilities as a whole.  

In the first three months of 2006, the NU Enterprises businesses accounted for approximately $0.5 billion of NU's revenues, compared with $0.9 billion during the three months ended March 31, 2005.  At March 31, 2006, these businesses also accounted for $1.9 billion of NU's total assets.  NU Enterprises is comprised of the wholesale marketing, retail marketing, competitive generation, and the energy services businesses.  By May of 2006, NU had sold four of its energy services business and portions of a fifth.   

The first quarter 2006 NU loss was primarily related to the retail marketing business of NU Enterprises.  An after-tax charge of $39.1 million ($59.9 million pre-tax) was recorded to reduce the book value of this business to its fair value less its cost to sell.  In addition to the retail marketing business charge, NU Enterprises lost $23.5 million in the first quarter of 2006.  On  May 1, 2006, NU Enterprises signed an agreement to sell the retail marketing business.  

Within 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 $12.7 million in the first quarter of 2006, compared with $8.4 million in the first quarter of 2005.  The higher level of earnings was due primarily to a return on a higher level of transmission investment at CL&P.  In the first quarter of 2006, the electric distribution and regulated generation companies earned $30.1 million, compared with $30.3 million in the first quarter of 2005.  Yankee Gas earned $11.8 million in the first quarter of 2006, compared with earnings of $14.9 million in the first quarter of 2005.  The decline in earnings at Yankee Gas was primarily due to a 13.5 percent decline in firm sales, mostly caused by milder weather.

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.  A summary of Utility Group earnings by company and business segment for 2006 and 2005 is as follows:

	For the Three Months Ended March 31,
(Millions of Dollars)	2006	2005
CL&P Distribution	$23.4	$19.4
CL&P Transmission	9.1	5.8
Total CL&P *	32.5	25.2
PSNH Distribution and Generation	2.5	6.9
PSNH Transmission	2.6	1.9
Total PSNH	5.1	8.8
WMECO Distribution	4.2	4.0
WMECO Transmission	1.0	0.7
Total WMECO	5.2	4.7
Total Distribution and Generation	30.1	30.3
Total Transmission	12.7	8.4
Yankee Gas	11.8	14.9
Total Utility Group Net Income	$54.6	$53.6

*After preferred dividends of $1.4 million in both years.

54

CL&P's first quarter 2006 distribution earnings increased as a result of higher rates and a lower effective tax rate as a result of the settlement of a tax case with the State of Connecticut which, including interest, improved CL&P's net income by $4.9 million, offset by lower sales and higher interest and operating expenses.  First quarter 2006 transmission earnings benefited from higher revenues due to earnings on a higher level of investment in its transmission system.  

PSNH's distribution and generation earnings in 2006 were lower primarily due to higher retail transmission costs included in operation expenses as PSNH does not have a cost recovery tracking mechanism for retail transmission expenses.  PSNH's distribution and generation earnings in 2006 were also lower due to severance costs which were recorded in the first quarter of 2006, higher income taxes and lower sales, partially offset by a delivery rate increase of $10 million effective in June of 2005.

WMECO's improved 2006 distribution results were due to a $3 million distribution rate increase that took effect on January 1, 2006, offset by a 4.9 percent decrease in sales.

Yankee Gas' 2006 results were lower primarily as a result of a 13.5 percent decline in firm natural gas retail sales, mostly caused by milder weather.

The Utility Group's retail electric sales were negatively affected by temperatures that were milder in the first quarter of 2006 than during the first quarter of 2005 and by price elasticity driven by higher energy prices in 2006.  Overall, retail kilowatt-hour (kWh) electric sales decreased by 3.5 percent in the first quarter of 2006 from the first quarter of 2005 (a 0.9 percent decrease on a weather-normalized basis).  Residential electric sales decreased 5.7 percent from 2005; commercial electric sales decreased 1.6 percent; and industrial sales decreased 1.9 percent.  Absent the impacts of the weather, management believes the decline in sales is due primarily to higher prices driven by the higher fuel and purchased power costs.  Lower sales, along with higher employee benefits and capital costs, are factors contributing to the need for distribution rate relief at all four regulated utilities.

On April 12, 2006, PSNH filed an application with the NHPUC to increase delivery rates by $34 million annually on a temporary basis effective on July 1, 2006.  CL&P is evaluating whether to file a request for higher distribution rates in the second quarter of 2006 and Yankee Gas is expected to file a request for distribution rate relief by the end of 2006.  WMECO expects to file a request unless a settlement agreement is reached.  Because rate relief, other than for PSNH, is unlikely to be effective until the end of 2006 or early 2007, management believes that the distribution companies are likely to earn less than their authorized returns on equity (ROEs) in 2006.  

NU Enterprises:  At March 31, 2006, NU Enterprises was the parent of Select Energy, Northeast Generation Company (NGC), Northeast Generation Services Company (NGS) and its subsidiaries, Woods Electrical and E.S. Boulos Company (Boulos), SESI and its subsidiaries, and SECI-CT, which is a division of SECI, all of which are collectively referred to as "NU Enterprises."  The generation operations of Holyoke Water Power Company's (HWP) Mt. Tom plant (Mt. Tom), are also included in the results of NU Enterprises.  

The merchant energy business includes Select Energy's wholesale marketing and retail marketing businesses, 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 related to Mt. Tom, and NGS.  At March 31, 2005, the energy services businesses include the operations of Woods Electrical, Boulos, SESI, and SECI-CT.

NU’s condensed consolidated statements of loss for the three months ended March 31, 2006 and 2005 present the operations for the following companies as discontinued operations:

·

NGC,

·

Mt. Tom,

·

SESI,

·

Woods Electrical,

·

SECI-NH (including Reeds Ferry), sold in November of 2005, and  

·

Woods Network, sold in November of 2005.

NU Enterprises exited all of its New England wholesale sales obligations in 2005 by buying out those contracts or assigning or transferring its obligations to third parties.  Most of these contracts were with municipalities.  There were no additional contracts bought out or assigned in the first quarter of 2006.  Select Energy's wholesale obligations in the PJM power pool expire in 2008.  Select Energy's remaining wholesale obligation in New York expires in 2013.  Although Select Energy continues to serve this obligation, steps have been taken in the first quarter of 2006 to reduce its volatility by hedging a portion of this obligation.  Select Energy is seeking to divest these obligations.

55

NU Enterprises' wholesale and retail marketing businesses are not included in discontinued operations because they do not meet the criteria for this presentation under applicable accounting guidance.  

A summary of NU Enterprises' losses for the three months ended March 31, 2006 and 2005 is as follows:

	For the Three Months Ended March 31,
(Millions of Dollars)	2006	2005
Merchant Energy (1)	$(59.5)	$(138.4)
Energy Services, Parent and Other (2)	(3.1)	(29.0)
Net Loss	$(62.6)	$(167.4)

(1)

The merchant energy losses above totaling $59.5 million include $71.2 million of continuing operations losses, offset by $11.7 million of discontinued operations earnings for the three months ended March 31, 2006.  The 2005 losses totaling $138.4 million include $151.2 million of continuing operations losses, offset by $12.8 million of discontinued operations earnings for the three months ended March 31, 2005.  The earnings included in discontinued operations relate to NGC's and Mt. Tom's contracts with Select Energy.  

(2)

The energy services, parent and other losses above totaling $3.1 million include $2 million of continuing operations losses and $1.1 million of discontinued operations losses for the three months ended March 31, 2006.  The 2005 losses totaling $29 million include $11.8 million of continuing operations losses and $17.2 million of discontinued operations losses for the three months ended March 31, 2005.

Retail marketing lost $69.8 million in the first quarter of 2006 compared with earnings of $1.4 million in the first quarter of 2005 (excluding restructuring charges as discussed in Note 3 to the condensed consolidated financial statements).  The 2006 loss includes an after-tax loss of $32.1 million from operations, an after-tax mark-to-market gain of $1.4 million and an after-tax loss of $39.1 million to reflect the estimated fair value less the estimated cost to sell of the retail business that is being sold.  

The retail marketing business loss from operations for the first quarter of 2006 and the negative adjustment to record the retail business at fair value less cost to sell partially reflects the impacts of the decision to exit the wholesale marketing business.  As a result of that decision, third party contracts intended to source a combination of retail and wholesale loads were required to be marked-to-market in the first quarter of 2005.  The after-tax mark-to-market value of these contracts was recorded in the first quarter of 2005 as a gain of approximately $60 million.  This gain was recorded in wholesale contract market changes, net because it was included in the wholesale business line and included with the wholesale contracts to be divested.  Market prices were higher when the retail supply was re-established with a combination of new supply contracts and generation resources.  When the decision to exit the competitive generation and retail marketing busi nesses was announced, the resources of the competitive generation business that were previously dedicated to the retail marketing business at a fixed price were separated from the retail marketing business, exposing the portfolio of retail sales to current market prices.  Current market prices have generally been higher than those that would have been charged by the competitive generation business.  The higher costs incurred to replace that retail supply accounted for most of the negative results in the first quarter of 2006.  Although electricity prices decreased during the quarter and provided a positive contribution to results, the mild weather caused the retail business to be long in energy supply, and surplus energy supply was sold into the market at a loss.

Combined wholesale marketing and competitive generation net income for the first quarter of 2006 is $12.1 million compared with a loss of $135.6 million in the first quarter of 2005 (excluding restructuring charges).  Included in these results are $4 million and $135.4 million of mark-to-market impacts in 2006 and 2005, respectively.  Current operations excluding the mark-to-market impacts resulted in a gain of $16.1 million in 2006 and a loss of $0.2 million in 2005.

The loss for the first quarter of 2005 reflects the impacts of NU’s March 9, 2005 decision to exit the wholesale marketing business.  As a result of that decision, third party sales contracts and the majority of contracts intended to source a combination of retail and wholesale loads were marked-to-market, and NU Enterprises began the process of divesting itself of the wholesale marketing business.  As of March 31, 2006, the wholesale marketing business continues to manage one short-term supply contract and one long-term sale contract in New York, one long-term supply contract and one short-term supply contract in New England and several long-term sales contracts in PJM which will expire by 2008.  By the end of 2006, a significant portion of the obligations in PJM will be served.  Select Energy has also taken steps to reduce the volatility of these obligations by hedging a portion of them.  Management is continuing to pursue opportunities to complete the di vestiture of the wholesale marketing business.  During the first quarter of 2006, market prices generally decreased and loads were lower than expected due to both mild weather and fewer customers joining standard offer service, both of which factors contributed positively to the financial results of managing these remaining contracts.  

Market prices in the first quarter of 2006 have been higher than the prices at which the competitive generation business was previously selling to Select Energy to serve the retail marketing business.  This has resulted in a benefit to the competitive generation business.  

56

Conventional hydroelectric generation was approximately 220,000 MWh in 2006 versus 200,000 MWh in 2005, also contributing to the better first quarter 2006 results.  Generation at Mt. Tom was lower in 2006 than in 2005 (248,000 MWh versus 278,000 MWh) primarily due to unusually wet coal, which decreased the quarterly results in 2006 compared to 2005.  

The energy services business had a net loss in 2006 of $0.8 million versus a net loss in 2005 of $2.6 million (excluding restructuring and impairment charges).  The improved results in the first quarter of 2006 are primarily due to contract losses recorded in the first quarter of 2005.

Restructuring and impairment charges for the first quarter of 2006 are an after-tax loss of $3.9 million, mostly related to the estimated cost to sell of the retail marketing business and professional fees incurred as a result of divestiture efforts.  In 2005, the first quarter after-tax loss for these charges was $29.9 million, most of which was recorded by the energy services businesses.

For information regarding the current status of the exit from the wholesale marketing, retail marketing, competitive generation and energy services businesses, see "NU Enterprises Divestitures," included in this management's discussion and analysis.

Parent and Other:  Parent company and other after-tax expenses totaled $2.1 million in the first quarter of 2006, compared with expenses of $3.9 million in the first quarter of 2005.  Results in the first quarters of 2006 and 2005 were negatively impacted by additional environmental reserves which were recorded by HWP associated with its manufactured gas plant coal tar site, totaling $1.3 million in 2006 and $2.2 million in 2005.  Expenses in 2006 were offset by higher investment income in 2006 as compared to 2005.

Future Outlook

NU continues to project 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 mild winter in 2006, slowing non-weather affected 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 estimated 2006 earnings range of between $0.89 and $0.96 per share.  Utility Group earnings may also be affected by the outcome of various retail distribution rate proceedings, particularly at PSNH, the potential reductions of income taxes associated with the IRS PLR, 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.  

Parent and Other:  NU believes that due to higher projected investment income and other factors, 2006 parent company losses will be less than the previous estimate of between $0.09 and $0.12 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.  

Liquidity

Consolidated:  NU continues to maintain an adequate level of liquidity.  At March 31, 2006, 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 approximately $900 million.  At March 31, 2006, NU also had $36.3 million of cash and cash equivalents on hand, compared with $45.8 million at December 31, 2005.  

Cash flows from operations decreased by $146.4 million from $189.1 million for the first three months of 2005 to $42.7 million for the first three months of 2006.  The decrease in operating cash flows is due primarily to higher regulatory refunds as CL&P refunded amounts to its ratepayers to moderate the increase in CL&P's TSO rates which was effective on January 1, 2006.  The decrease in operating cash flows is also due to a federal income tax payment of approximately $55 million related to NU's 2005 tax return which was made in the first quarter of 2006.  

PSNH's operating cash flows are expected to decline significantly in the second half of 2006 and beyond as a result of a significant reduction in SCRC rates of approximately $0.02 per kilowatt-hour that PSNH has proposed be implemented effective on July 1, 2006.  That decline, which amounts to approximately $170 million annually, is the result of the completion of PSNH's recovery of its Part 3 stranded costs in 2006.

In November of 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.  There were $110 million of borrowings outstanding under that agreement at March 31, 2006.

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NU Enterprises had a modestly negative impact on NU's liquidity in the first quarter of 2006.  However, NU Enterprises is expected to have a much more significant impact on NU's liquidity over the remainder of 2006 as the company successfully executes its plans to exit its remaining competitive businesses.  The sale of the retail marketing business, which is expected to close around June 1, 2006, will result in NU making a payment to the buyer in the amount of $44 million, subject to mark-to-market and other closing adjustments that are not expected to be material.  The renegotiation of Select Energy's remaining wholesale contracts also could result in significant payments to counterparties or third parties.  However, the sale of NU's competitive generation business is expected to result in significant cash inflows after assumption of $320 million of debt and after payment of taxes if the company is able to sell those generation assets at or above their book value of approximately $825 million.  The sale of the remaining energy services businesses is not expected to have a significant impact on NU's liquidity.  Considering the company's estimates of the cash payments, cash proceeds and tax benefits associated with selling NU Enterprises' businesses, in aggregate, the company expects the exit from these businesses to positively impact cash flows by at least $200 million.

NU's senior unsecured debt is rated Baa2, BBB- and BBB with a stable outlook by Moody's Investors Service (Moody's), Standard & Poor's (S&P) and Fitch Ratings (Fitch).  At March 31, 2006, at NU's current credit ratings levels, Select Energy could have been requested to provide $3 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 letters of credit (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 $315 million of collateral or LOCs to various unaffiliated counterparties and approximately $98 million to several independent system operators and unaffiliated local distribution compan ies (LDCs) at March 31, 2006.  If such a downgrade were to occur, management believes NU would currently be able to provide this collateral.  

On April 17, 2006, Moody's placed the ratings of PSNH on review for possible downgrade due to their expectations of lower PSNH cash flows and revised the rating outlook for Yankee Gas from stable to negative.  Moody's lowered Yankee Gas' outlook from stable to negative as a result of Yankee Gas' low earned returns in recent years and the absence of rate mechanisms that would stabilize cash flows if revenues decline as a result of mild weather or customers' energy conservation.  Moody's also lowered the rating on the senior secured debt of NGC to Ba3 from Ba1 and placed its NGC rating under review for possible further downgrade.  Fitch has placed NGC under review for downgrade.  Management does not believe that such downgrades of NGC, in and of themselves, would have a negative impact on the ratings of NU or any other subsidiary.

NU paid common dividends of $27.2 million in the first quarter of 2006, compared with $21 million in the first quarter of 2005.  The higher level of dividend payments reflects a 7.7 percent increase in the NU quarterly dividend to $0.175 per share that was effective with the September 30, 2005 dividend and an increase in the number of outstanding shares as a result of the 23 million common share issuance in December of 2005.  On April 11, 2006, the NU Board of Trustees approved a dividend of $0.175 per share payable on June 30, 2006 to shareholders of record on June 1, 2006.  The NU annual meeting of shareholders will be held on May 9, 2006.  Prior to each of the past five annual meetings, the NU Board of Trustees approved an increase of the common dividend, effective with the third quarter dividend.

Capital expenditures included on the condensed consolidated statements of cash flows and described in the liquidity section of this management's discussion and analysis 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 $203.8 million in the first three months of 2006, compared with $166.8 million in the first three months of 2005.  First quarter 2006 capital expenditures were $124.2 million by CL&P, $35.1 million by PSNH, $10.4 million by WMECO, $17.8 million by Yankee Gas and $16.3 million by other NU subsidiaries, including $5 million by NU Enterprises.  The increase in NU's capital expenditures was primarily the result of higher transmission capital expenditures, particularly at CL&P.  Utility Group capital expenditures are expected to approach approximately $900 million in 2006, including approx imately $600 million, $150 million, $50 million, and $100 million for CL&P, PSNH, WMECO and Yankee Gas, respectively.  

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.  CL&P is expected to issue approximately $250 million of debt in June of 2006.  No other Utility Group company is expected to issue additional debt in 2006.  The Utility Group will also fund its capital expenditures through equity contributions from NU.  

Utility Group:  In November of 2005, 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 $160 million of borrowings outstanding under that agreement at March 31, 2006.

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 March 31, 2006, CL&P had sold $100 million to that financial institution.  

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For more information regarding the sale of receivables, see Note 1G, "Summary of Significant Accounting Policies - Sale of Customer Receivables," to the condensed consolidated financial statements.

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, 2005 to March 31, 2006, the net positive impact on NU Enterprises' liquidity related to these items was approximately $30 million.  

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 would likely require NU Enterprises to continue to make significant payments to the counterparties in such transactions.

On April 6, 2006, Mode 1 Communications, Inc. sold its investment in Globix Corporation shares at an after-tax gain of $1.8 million to be recognized in the second quarter of 2006.

NU Enterprises Divestitures

In 2005, NU announced that NU Enterprises would exit its competitive businesses.  NU intends to apply the net proceeds from the exiting of these businesses to debt reduction and the financing of the Utility Group's capital spending programs.  An overview of this process is as follows:  

Wholesale Marketing Business:  In the first three months of 2006, NU Enterprises continues to serve its remaining wholesale power obligations pending the exit from this business.

Retail Marketing Business:  On May 1, 2006, NU Enterprises signed a definitive agreement to sell its retail marketing business to Amerada Hess Corporation (Amerada Hess) with a closing date expected around June 1, 2006.  Under the terms of the agreement, Select Energy will pay Amerada Hess approximately $44 million, subject to mark-to-market and other closing adjustments that are not expected to be material, and Amerada Hess will acquire Select Energy’s ongoing retail marketing business, including all of its retail supply obligations.  The terms reflect the positive value of the retail marketing business net of the current negative value of the retail sales contracts, which Select Energy is selling separate from the generation resources of NGC and Mt. Tom.

Competitive Generation Business:  The competitive generation business includes NGC's competitive generation assets in Massachusetts and Connecticut and Mt. Tom in Massachusetts.  In April of 2006, indicative bids for the competitive generation business were received.  NU continues to expect to close on the sale of the competitive generation business by the end of 2006.

Energy Services Businesses:  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.  In April of 2006, NU Enterprises sold certain assets of Woods Electrical for approximately $1 million.

On May 5, 2006, NU Enterprises completed the sale of SESI.  In connection with the closing of this transaction, NU Enterprises paid the buyer approximately $7.7 million and will record a pre-tax charge to income of approximately $6 million in the second quarter of 2006.  In connection with this sale, the company anticipates that the balance of more than $90 million of NU parent guarantees associated with SESI's outstanding debt will be eliminated by March of 2007, with over $80 million being eliminated by the end of 2006.

NU Enterprises' has two remaining energy services businesses, SECI-CT and E.S. Boulos Company (Boulos), which the company is in the process of exiting.

When all of the competitive businesses are exited, NU expects its employment levels to total approximately 5,500 employees, compared with approximately 7,000 employees at the beginning of 2005.

For further information regarding these companies, see Note 4, "Assets Held for Sale and Discontinued Operations," to the condensed consolidated financial statements.  

Business Development and Capital Expenditures

Consolidated:  In the first quarter of 2006, NU's cash capital expenditures totaled $203.8 million, compared with $166.8 million in the first quarter of 2005.  Total capital expenditures are expected to total approximately $900 million in 2006, compared with $813.4 million in 2005.  This 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.  

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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 the first quarter of 2006, CL&P's distribution capital expenditures totaled $45.8 million, compared with $61.6 million in the first quarter of 2005.  In 2006, CL&P projects distribution capital expenditures of approximately $200 million.

CL&P's transmission capital expenditures totaled $83.3 million in the first quarter of 2006, compared with $27.8 million in the first quarter of 2005.  The increase in CL&P's transmission capital expenditures in 2006 was primarily the result of increased spending on a new 21-mile 345 kilovolt (kV) transmission project between Bethel 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 69-mile Middletown to Norwalk 345 kV transmission project, 3) a related two cable 115 kV underground project between Norwalk and Stamford, Connecticut (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 totaled $65.9 million in the first quarter of 2006 compared to $16 million in the first quarter of 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 was successfully energized on September 23, 2005.  The 10 miles of 115 kV underground line for this project was completed in March of 2006 and was energized in April of 2006.  This project, which is expected to cost approximately $350 million, is nearly 80 percent complete, on budget and ahead of schedule, and is expected to be completed by the end of 2006.  CL&P has capitalized $248.2 million at March 31, 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.  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 the Connecticut Department of Environmental Protection (DEP) approvals.  The CSC will amend the Middletown to Norwalk docket and will hold a limited scope proceeding to address CL&P's proposal to re-route a 1.3 mile section of 345 kV underground cable in Norwalk.  This route change will further minimize the environmental impact of the project, and is not expected to change either the cost or scope.  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 and third quarters of 2006.  CL&P expects the project to be completed by the end of 2009.  CL&P has reached tentative settlement agreements with all three of the appeals related to the project, including the signing of one settlement agreement.  At this time, CL&P does not expect any of these three appeals to delay construction.  At March 31, 2006, CL&P has capitalized $50.7 million associated with this project.

CL&P’s construction of the Glenbrook Cables Project, two 115 kV underground transmission lines between Norwalk and Stamford was approved by ISO-NE on August 3, 2005 and approved by the CSC on July 20, 2005 with no court appeals.  The project responds to growing electric demands in the area.  The $120 million cost estimate for this project is currently being re-evaluated and will increase, based upon experience with similar Bethel to Norwalk work and Middletown to Norwalk bids.  The increase will be primarily driven by increases in commodity prices, and the cost of installing the underground cable and supporting infrastructure.

Management expects to begin construction in late 2006 and expects the lines to be in service in 2008.  At March 31, 2006, CL&P has capitalized $9.3 million associated with this project.

On October 1, 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 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.  In early March, negotiations with a preferred Engineering, Procurement, and Construction (EPC) Contractor commenced.  CL&P expects to award the EPC contract during the second quarter and to place the project into service in 2008.  Management believes that the current co st estimate for NU's portion of the project of $72 million is still valid.  At March 31, 2006, CL&P has capitalized $6.4 million associated with this project.

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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 March 31, 2006, CL&P has capitalized $8.7 million associated with this project.

NU, ISO-NE and National Grid have begun planning an upgrade to the transmission system connecting Massachusetts, Rhode Island and Connecticut in a comprehensive study called the Southern New England Transmission Reliability Project.  The parties are expected to identify a number of possible routes and configurations by 2007.  NU and National Grid have not yet estimated a total cost for the upgrade, but NU estimates that approximately $400 million of its $2.3 billion transmission capital budget in 2006 through 2010 could be spent on this project.

Yankee Gas:  In the first quarter of 2006, Yankee Gas' capital expenditures totaled $13.3 million, compared with $11.9 million in the first quarter of 2005.  Yankee Gas is constructing a liquefied natural gas (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, was approximately 48 percent complete at March 31, 2006.  Yankee Gas has capitalized $52.9 million related to this project at March 31, 2006.

PSNH:   In the first quarter of 2006, PSNH's capital expenditures totaled $32.2 million, compared with $38.9 million in the first quarter of 2005.  The expenditures in 2006 included $3.3 million in construction activities associated with PSNH's $75 million 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 be completed in the second half of 2006.  PSNH has scheduled an outage of the unit beginning in April of 2006 to connect the new, wood-fired boiler to the existing turbine and to perform other maintenance.  At March 31, 2006, PSNH has capitalized $68 million related to this project and the project was approximately 90 percent complete.

WMECO:  WMECO's capital expenditures totaled $9.2 million in the first quarter of 2006, compared with $9.6 million in the first quarter of 2005.  In 2006, WMECO projects total capital expenditures of approximately $50 million.

NU Enterprises:  HWP is installing a selective catalytic reduction system at Mt. Tom.   The $14 million project commenced in July of 2005 and is expected to be complete by mid-2006.  At March 31, 2006, this project was approximately 75 percent complete and HWP has capitalized $9.9 million related to this project.

Transmission Access and FERC Regulatory Changes

The New England Regional Transmission Organization (RTO) was activated on February 1, 2005.  As a result, 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.  NU collects approximately 75 percent of its wholesale transmission revenues under its RNS tariff and 25 percent under its LNS tariff.

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.  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.  A final order from the FERC is expecte d in 2006.  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.  At March 31, 2006, this deferral has resulted in the recognition of an $8.7 million regulatory liability.

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 in the third quarter of 2006.  

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Legislative Matters

Environmental Legislation:  The Regional Greenhouse Gas Initiative (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, if adopted by the New Hampshire legislature.  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.  The 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 Mt. Tom plant 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, which includes two adjustments annually in January and June, allows CL&P to include forward-looking transmission charges in its retail transmission rate and promptly recover its transmission expenditures.  On January 1, 2006, CL&P raised its retail transmission rate to collect $21 million of additional revenues over the first six months of 2006.

Public Act 05-01: 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 cost (FMCC) charges.  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 Connecticut distribution companies.  The legislation provides utilities with the opportunity to earn one-time awards for generation that is installed in their service territories and allows distribution companies, such as CL&P, to bid as much as 250 MW of capacity into the re quest 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 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 subsequent rate cases.  The DPUC is conducting additional proceedings to implement this legislation.  

On March 27, 2006, the DPUC issued final decisions that will provide customers and distribution companies with financial incentives for installing distributed generation resources, including capital grants of up to $200 per kW for emergency generators and $450 per kW for base load generation, with an extra $50 per kW for projects located in southwest Connecticut.

New Hampshire:

Environmental Legislation:  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.  A bill to implement that agreement passed the New Hampshire House of Representatives in late-March of 2006, passed the New Hampshire Senate on April 20, 2006, and will be sent to New Hampshire Governor Lynch for signing into law.  PSNH intends to comply with the legislation by installing wet scrubber technology at its two Merrimack coal units, which combined generate 433 MW by mid-2013.  PSNH currently estimates the cost to comply of approximately $250 million, however, this amount is subject to change as final design is undertaken.  State law, this new bill and PSNH's restructuring agreement provide for the recovery of its generation costs, including th e cost to comply with state environmental regulations.  

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

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NU's transmission business recovers its total transmission revenue requirements, including the allowed ROE.  At March 31, 2006, this true-up resulted in the recognition of a $0.7 million regulatory asset, including approximately $0.6 million due from 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 and the new rates became 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, as a result of the enactment of the new legislation passed by the Connecticut legislature in 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.  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, but management expects to request such a mechanism in PSNH's 2006 energy delivery rate case.

Capacity Market:  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 proposing a Forward Capacity Market (FCM) in place of the previously proposed LICAP mechanism.  The settlement agreement provides for a fixed level of compensation to generator s 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.  The settlement judge forwarded the settlement to the FERC on April 11, 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, PSNH and WMECO expect to recover these costs from their customers.

Connecticut - CL&P:     

Procurement Fee Rate Proceedings:  CL&P is currently allowed to collect a fixed procurement fee of 0.50 mills per 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.  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.  A final decision, which had been scheduled for December 28, 2005, was delayed by the DPUC and the DPUC re-opened this docket to allow the Connecticut Office of Consumer Counsel (OCC) to submit additional testimony.  A new schedule has been est ablished which provides for a final decision in August of 2006.  Management continues to believe that recovery of the $5.8 million regulatory asset recorded related to CL&P's 2004 incentive payment, which was reflected in 2005 earnings, is probable.  No amounts have been recorded related to the 2005 incentive portion of CL&P's procurement fee.  

CTA and SBC Reconciliation:  The competitive transition assessment (CTA) allows CL&P to recover stranded costs, such as securitization costs associated with the rate reduction bonds, amortization of regulatory assets, and IPP over market costs, while the systems benefit 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 worker protection costs.

On March 31, 2006, CL&P filed its 2005 CTA and SBC reconciliation with the DPUC, which compares CTA and SBC revenues to revenue requirements.  For the year ended December 31, 2005, total CTA revenues exceeded the CTA revenue requirement by $60.1 million.  This amount was recorded as a regulatory liability on the accompanying condensed consolidated balance sheets.  For the same period, the SBC revenue requirement exceeded SBC revenues by $1.3 million.  Management expects a decision in this docket from the DPUC by the end of 2006 and does not expect the outcome to have a material adverse impact on CL&P's net income, financial position or cash flows.  

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

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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 and 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.  

Income Taxes:  In 2000, CL&P requested from the IRS a PLR regarding the treatment of UITC and EDIT related to generation assets that have been sold.  On April 18, 2006, the IRS issued a PLR to CL&P regarding the treatment of UITC and EDIT related to generation assets that CL&P has 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 holds that it would be a violation of tax regulations if the EDIT or UITC is returned to customers following the sale of the generation assets.  The statement in the PLR is consistent with proposed regulations released in December 2005.  Previously, CL&P was ordered by the DPUC to submit the PLR to the DPUC within 10 days of issuance and retain the UITC and EDIT in their existing accounts pending its receipt and review of the PLR.  CL&P has complied with this order.  

In addition to the PLR received by CL&P, proposed regulations were issued by the Treasury Department in December of 2005.  The proposed regulations would generally allow EDIT and UITC generated by property that is no longer regulated to be returned to regulated customers without violating the tax law.  The new proposed regulations, however, would only apply to property that ceases to be regulated public utility property after December of 2005.  As such, under the proposed regulations, the EDIT and UITC cannot be used to reduce CL&P's customers' rates because CL&P sold these assets before December of 2005.  Those proposed regulations have not been finalized.

At March 31, 2006, CL&P's UITC balance is $59.3 million and EDIT balance is $14.7 million related to generation assets that have been sold.  The resolution of this contingency may result in these deferred tax balances being eliminated with a corresponding reduction to income tax expense.

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 the remaining 50 percent of its 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 increased rates another 4.9 percent on April 1, 2006, representing a total increase of $676.5 million on an annualized basis.  

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.  A draft decision in this proceeding is scheduled for May 31, 2006, with a final decision expected on June 14, 2006.

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 took effect on January 1, 2005, 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.  CL&P anticipates filing a retail rate increase in the second quarter of 2006.  

Porcelain Cutouts:  The DPUC initiated a proceeding relating to an incident involving the failure of certain equipment in CL&P's distribution system.  On April 26, 2006, the DPUC issued an order requiring CL&P to report its progress in replacing porcelain cutouts.  Management is currently evaluating whether an asset retirement obligation has arisen.  Removal costs are expected to total approximately $5 million over the next three years.  

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 DPUC issued a new decision on April 20, 2006 requiring an audit of Yankee Gas' PGA accounting methods and deferring any conclusion on the $9 million of previously recovered revenues until the completion of the audit.  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, notwithstanding the new decision, management believes the appropriateness of the PGA charges to customers for the time period under review will be approved.

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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 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 energy service revenues and the actual costs incurred.  

The NHPUC issued an order on January 20, 2006 setting the current ES rate of $0.0913 per kWh for the 11-month period, subject to a mid-year review for cost changes.  

On April 12, 2006, PSNH notified the NHPUC that it will seek to reduce SCRC charges by approximately $170 million annually and to reduce ES charges by approximately $13 million annually due to declining fuel and purchased power costs.  PSNH also filed an application to increase delivery rates by approximately $34 million annually on a temporary basis.  PSNH requested that all of the rate changes, which in total would reduce customer bills by approximately 12.7 percent, be effective on July 1, 2006.  PSNH expects to file a request for a permanent rate increase of approximately $50 million around May 30, 2006 with a decision on that rate increase expected in 2007.  The temporary rate increase will be reconciled to permanent rates and differences between the two rates will be reflected in customers' bills once permanent rates become effective.  

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 $330 million at March 31, 2006.  At March 31, 2006, this cumulative deferral will decrease the amount of non-securitized stranded costs to be recovered from PSNH's customers in the future from $355.3 million to $25.3 million.

From May of 2001 through January 31, 2006, the difference between PSNH ES revenues and ES costs was deferred and included in the SCRC calculation for recovery or refund.  As part of a settlement agreement with NHPUC staff and OCA regarding 2006 ES rates, PSNH requested a change in accounting for ES to allow the difference between ES revenues and costs to be included in subsequent ES rates.  The NHPUC issued its order on January 20, 2006 approving the settlement agreement including the change in accounting.  Effective February 1, 2006, PSNH began deferring the difference between ES revenues and ES costs for inclusion in the calculation of the subsequent ES rate.  At March 31, 2006, ES revenues exceeded ES costs and PSNH has deferred the $22.7 million difference.   

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 IPPs' 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.  PSNH recovers the over market costs of IPP contracts through the SCRC.  

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.   In addition, while the motion was pending, the term of the second NHPUC commissioner under challenge expired.  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 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.

Massachusetts:

Transition Cost Reconciliation:  WMECO filed its 2005 transition cost reconciliation with the Massachusetts Department of Telecommunications and Energy (DTE) on March 31, 2006.  This filing reconciles transition costs, default service costs and retail transmission costs with their associated revenues collected from customers.  The DTE has not yet reviewed this filing or issued a schedule for review.  Therefore the timing of a decision is uncertain at this time.  However once reviewed by the DTE, management does not expect the outcome to have a material adverse impact on WMECO's net income or financial position.

Annual Rate Change Filing:  Under the 2004 rate case settlement agreement, WMECO expects to file late in the second quarter of 2006 for new rates to be effective on January 1, 2007.

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Deferred Contractual Obligations

FERC Proceedings:  On July 1, 2004, Connecticut Yankee Atomic Power Company (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 by CYAPC beginning on February 1, 2005, subject to refund.

The FERC staff 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.  A final order from the FERC 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 its customers' obligations, including the obligations of CL&P, PSNH and WMECO.  Due to the terms of the settlement of state court litigation between CYAPC and Bechtel Power Corporation (Bechtel) over the terminated decommissioning contract, Bec htel has withdrawn from the FERC proceedings.

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 with the FERC 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.  The FERC and CYAPC have asked 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:  CYAPC and Bechtel Power Corporation (Bechtel) previously 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.  On March 7, 2006, CYAPC and Bechtel executed a settlement agreement terminating this litigation.  Bechtel has paid CYAPC $15 million and the parties have withdrawn their litigation from state court.  CYAPC expects to credit the net proceeds from the settlement agreement against decommissioning costs recoverable from its customers, including CL&P, PSNH and WMECO.

Spent Nuclear Fuel Litigation:  CYAPC, Yankee Atomic Electric Company (YAEC) and Maine Yankee Atomic Power Company (MYAPC) (Yankee Companies) commenced litigation in 1998 charging that the federal government breached contracts it entered into with each company in 1983 under the Nuclear Waste Policy Act of 1982.  The 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.  On January 31, 2006, the FERC issued an order accepting the rate increase, effective February 1, 2006, subject to refund by YAEC after hearings and settlement judge proceedings.  

On May 1, 2006, YAEC filed with the FERC a proposed settlement agreement with the DPUC, the Massachusetts Attorney General and the Vermont Department of Public Service.  Under the proposed settlement agreement, YAEC agreed to revise its November 2005 decommissioning cost increase from $85 million to $56.8 million.  The revision includes adjustments for contingencies and projected escalation and certain decontamination and dismantlement (D&D) expenses.  Other terms of the proposed settlement agreement include extending the collection period for charges through December 2014, reconciling and adjusting future charges based on actual D&D expenses and the decommissioning trust fund's actual investment earnings.  The company believes that its share of the increase in decommissioning costs will ultimately be recovered from the customers of CL&P, PSNH and WMECO.  NU has a 38.5 percent ownership interest in YAEC.  The proposed settlement agreement will b ecome effective upon approval from the FERC, but should not materially affect the level of 2006 charges.

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NU Enterprises

NU has decided to exit all aspects of NU Enterprises' businesses.  

Merchant Energy Business:  At March 31, 2006, the merchant energy business includes Select Energy's wholesale marketing business, 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 related to Mt. Tom, and NGS, which NU Enterprises is exiting.  Prior to the March 2005 decision to exit the wholesale marketing business, this business primarily comprised 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 Business:  At March 31, 2006, the energy services businesses include the operations of Woods Electrical, Boulos, SESI, and SECI-CT, which is a division of SECI.

Outlook:  NU is not providing 2006 earnings guidance for NU Enterprises.  

Intercompany Transactions:  There were no CL&P TSO purchases from Select Energy in the first quarters of 2006 or 2005.  Other energy purchases between CL&P and Select Energy totaled $3.3 million in the first quarter of 2006 and $14.2 million in the first quarter of 2005.  WMECO had $0.5 million in purchases from Select Energy in the first quarter of 2006, compared with $20.5 million in the first quarter of 2005.

Select Energy purchases from NGC and Mt. Tom represented approximately $35.7 million and $14.2 million for the three months ended March 31, 2006, respectively.  These amounts totaled $39.5 million and $13.3 million for NGC and Mt. Tom, respectively, for the three months ended March 31, 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 business.  This business includes 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.  

Wholesale Contracts:  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 in the first quarter 2005.  Existing energy trading contracts have been and will continue to be marked-to-market with changes in fair value reflected in the statements of loss.  

At March 31, 2006 and December 31, 2005, Select Energy had wholesale derivative assets and derivative liabilities as follows:   

(Millions of Dollars)	March 31, 2006	December 31, 2005
Current wholesale derivative assets	$  133.2	$  256.6
Long-term wholesale derivative assets	70.2	103.5
Current wholesale derivative liabilities	(223.5)	(369.3)
Long-term wholesale derivative liabilities	(153.6)	(220.9)
Portfolio position	$(173.7)	$(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 divest some or all of these contracts, the volatility of commodity prices until the contracts are divested, 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 March 31, 2006 and December 31, 2005.  A description of each method is as follows: 1) prices actively quoted primarily

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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 March 31, 2006 and December 31, 2005, the sources of the fair value of wholesale contracts and for the three months ended March 31, 2006 and 2005, the changes in fair value of these contracts are included in the following tables:

(Millions of Dollars)	Fair Value of Wholesale Contracts at March 31, 2006
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	$  13.8	$    6.2	$        -	$   20.0
Prices provided by external sources	(104.3)	(54.4)	(1.2)	(159.9)
Models based	0.2	(15.6)	(18.4)	(33.8)
Totals	$(90.3)	$(63.8)	$(19.6)	$(173.7)

(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)

	Total Portfolio Fair Value For the Three Months Ended
(Millions of Dollars)	March 31, 2006	March 31, 2005
Fair value of wholesale contracts outstanding   at beginning of period	$(230.1)	$ (48.9)
Contracts realized or otherwise settled during the period	63.4	36.3
Changes in fair value of contracts recorded:
Wholesale contract market changes, net	(6.8)	(167.9)
Fuel, purchased and net interchange power	(0.1)	(40.8)
Operating revenues	(0.1)	5.9
Changes in model based assumption included in      operating revenues	-	14.2
Fair value of wholesale contracts outstanding  at end of period	$(173.7)	$ (201.2)

Change in the fair value of wholesale contracts that were marked-to-market as a result of the decision to exit the wholesale business totaled a negative $6.8 million and $167.9 million for the three months ending March 31, 2006 and 2005, respectively, and are recorded as wholesale contract market changes, net on the accompanying condensed consolidated statements of loss.  Changes in the fair value of natural gas contracts totaling a negative $0.1 million and $40.7 million for the three months ending March 31, 2006 and 2005, respectively, are recorded as fuel, purchased and net interchange power, and changes in fair value of contracts formerly designated as trading totaling a negative $0.1 million and a positive $5.9 million for the three months ended March 31, 2006 and 2005, respectively, and are recorded as revenue on the condensed consolidated statements of loss.

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.

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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.

Through the first quarter of 2006, the retail marketing business was the successful bidder on nearly 20 percent of its bids compared to 15 percent in the first quarter of 2005.  

For the three months ended March 31, 2006, approximately 2.1 million MWhs were delivered as compared to approximately 2.6 million MWhs for the three months ended March 31, 2005.  For natural gas, approximately 19.5 billion cubic feet were delivered in the first three months of 2006 as compared to approximately 17.1 billion cubic feet in the first three months of 2005.  

Retail margins on new business ranged from approximately $1.29 to $2.00 per MWh for the period ended March 31, 2006.  Similarly, for natural gas, sales margins averaged between approximately $0.20 and $0.35 per thousand cubic feet in 2006.   

As of March 31, 2006, Select Energy has only recorded retail contracts or portions thereof as normal if they expire in the next two months as amounts with delivery dates beyond that point would be included as part of the sale of the retail marketing business, and therefore not probable of delivery; all other retail derivatives are included in assets held for sale and liabilities of assets held for sale.  The retail derivative contracts marked-to-market include virtually all retail sourcing contracts and certain retail sales contracts that are derivatives.  See Note 4, "Assets Held for Sale and Discontinued Operations," to the condensed consolidated financial statements.  At March 31, 2006 and December 31, 2005, Select Energy had retail derivative assets and derivative liabilities as follows:   

(Millions of Dollars)	March 31, 2006	December  31, 2005
Current retail derivative assets	$30.5	$55.0
Long-term retail derivative assets	9.2	12.9
Current retail derivative liabilities	(45.9)	(27.2)
Long-term retail derivative liabilities	(15.4)	0.4
Total retail	(21.6)	41.1
Hedged portfolio	(8.9)	24.1
Portfolio position	(12.7)	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 March 31, 2006 and December 31, 2005.  A description of each method is as follows: 1) prices actively quoted primarily represent NYMEX 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 March 31, 2006 and December 31, 2005, the sources of the fair value of retail energy sourcing contracts and for the three months ended March 31, 2006 and 2005, the changes in fair value of these contracts are included in the following tables:  

(Millions of Dollars)	Fair Value of Retail Sourcing Contracts at March 31, 2006
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	$(7.7)	$  6.0	$ -	$  (1.7)
Prices provided by external sources	1.3	(12.3)	-	(11.0)
Totals	$(6.4)	$(6.3)	$ -	$(12.7)

(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

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	Total Portfolio Fair Value For the Three Months Ended
(Millions of Dollars)	March 31, 2006	March 31, 2005
Fair value of retail sourcing contracts outstanding   at beginning of period	$ 17.0	$  0.1
Contracts realized or otherwise settled during the period	(4.8)	(0.1)
Changes in fair value recorded:
Other operating expenses	(23.7)	-
Wholesale contract market changes, net	-	30.0
Fuel, purchased and net interchange power	(1.2)	0.6
Fair value of retail sourcing contracts outstanding  at end of period	$(12.7)	$30.6

In connection with 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 support its retail marketing business.  Subsequent changes in fair value are now recorded in fuel, purchased and net interchange power.  Transactions being marked as a result of the expected sale of the retail marketing business are included in the accompanying condensed consolidated statements of loss.  

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 three months ended March 31, 2006, NU Enterprises' competitive generation assets continued to run well.  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 three months ended March 31, 2006, the 146 MW Mt. Tom plant had an availability factor of 86.8 percent, while the 1,080 MW Northfield Mountain facility had an availability factor of 95.7 percent.  The approximately 200 MW of hydroelectric units had an aggregate availability factor of 92.8 percent.  NU Enterprises realized energy-related gross margin of approximately $3 million in the three months ended March 31, 2006 due to a favorable ratio of on-peak to off-peak energy prices for the Northfield Mountain facility.  The competitive generation business also receives revenues from sales of the ISO-NE products other than energy.  The recent s ettlement agreement filed with the FERC that proposed the adoption of FCM in place of the prior LICAP mechanism would increase capacity revenues above their current level.  

Total competitive generation was 0.7 million MWhs through March 31, 2006.  The Mt. Tom station, a coal-fired unit located in Holyoke, Massachusetts, generated more than 0.2 million MWhs in the first three months of 2006, while NGC's Northfield Mountain facility and other hydroelectric units generated approximately 0.2 million MWhs and approximately 0.2 million MWhs, respectively, for the three months ended March 31, 2006.

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).  At March 31, 2006 and December 31, 2005, Select Energy had generation derivative assets and derivative liabilities as follows:   

(Millions of Dollars)	March 31, 2006	December 31, 2005
Current generation derivative assets	$ 7.3	$   9.2
Long-term generation derivative assets	-	-
Current generation derivative liabilities	(4.6)	(5.1)
Long-term generation derivative liabilities	(10.8)	(15.5)
Portfolio position	$(8.1)	$(11.4)

Certain generation derivatives are included in liabilities of assets held for sale.  See Note 4, "Assets Held for Sale and Discontinued Operations," to the condensed consolidated financial statements.

The methods used to determine the fair value of generation contracts are identified and segregated in the table of fair value of contracts at March 31, 2006 and 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.  

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As of March 31, 2006 and December 31, 2005, the sources of the fair value of generation contracts and for the three months ended March 31, 2006 and 2005, the changes in fair value of these contracts are included in the following tables:  

(Millions of Dollars)	Fair Value of Generation Contracts at March 31, 2006
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	$2.1	$       -	$ -	$  2.1
Prices provided by external sources	0.6	(10.8)	-	(10.2)
Totals	$2.7	$(10.8)	$ -	$(8.1)

(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)

	Total Portfolio Fair Value For the Thee Months Ended
(Millions of Dollars)	March 31, 2006	March 31, 2005
Fair value of competitive generation   contracts outstanding at beginning of period	$(11.4)	$ -
Contracts realized or otherwise settled during the period	(10.2)	-
Changes in fair value recorded:
Discontinued operations	2.5	-
Operating revenues	11.0	-
Fair value of competitive generation contracts   outstanding at end of period	$  (8.1)	$ -

Changes in the fair value of generation contracts that became marked-to-market as a result of the decision to exit the remainder of the NU Enterprises' businesses totaled a positive $2.5 million at March 31, 2006 which is recorded in discontinued operations on the accompanying condensed consolidated statement of loss.  Changes in the fair value of natural gas contracts that remain in continuing operations totaling $11 million at March 31, 2006 are recorded as revenues on the condensed consolidated statement of loss.

For further information regarding Select Energy's derivative contracts, see Note 5, "Derivative Instruments," to the condensed 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 overall exposure to credit risk, ei ther positively or negatively, in that the counterparties may be similarly affected by changes to economic, regulatory or other conditions.  At March 31, 2006, approximately 37 percent of Select Energy's counterparty credit exposure to wholesale and trading counterparties was collateralized or rated BBB- or better.  Select Energy was provided $12.9 million and $28.9 million of counterparty deposits at March 31, 2006 and December 31, 2005, respectively.  For further information, see Note 1K, "Summary of Significant Accounting Policies - Counterparty Deposits," to the condensed consolidated financial statements.

Critical Accounting Policies and Estimates Update

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 those accounting policies and estimates it believes are most critical.  

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 Statement of Financial Accounting

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Standards (SFAS) No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," and that it meets the criteria for discontinued operations.  As of March 31, 2006, based on the status of exiting these businesses, management concluded that discontinued operations presentation is appropriate for NGC, Mt. Tom, SESI, Woods Electrical, SECI-NH and Woods Network.  The retail marketing business, which is held for sale, is not presented as discontinued operations because separate financial information is not available for this business for the periods prior to the first quarter of 2006.  The wholesale marketing business is not held for sale.  In November of 2005, NU Enterprises sold SECI-NH and Woods Network to unaffiliated buyers.  In April of 2006, NU Enterprises sold certain assets of Woods Electrical.  On May 5, 2006, NU Enterprises completed the sale of SESI.

For further information regarding these companies, see Note 4, "Assets Held for Sale and Discontinued Operations," to the condensed consolidated financial statements.  Management will continue to evaluate this classification in 2006 for NU Enterprises' businesses that are being exited.  

Derivative Accounting:  Certain of the contracts comprising Select Energy’s wholesale marketing, retail marketing and competitive generation activities are derivatives, as are certain Utility Group contracts for the purchase or sale of energy or energy-related products.  Many retail marketing sales contracts 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:  identification of derivatives and embedded derivatives, designation and dedesignation of the normal purchases and sales exception, identifying hedge relationships and determining continuing qualification for hedge accounting, assessing and measuring hedge ineffectiveness, and estimating the fair value of derivatives.  All of these judgments, depending upon their timing and effect, can have a significant impact on NU’s condensed consolidated net income.

The fair value of derivatives is based upon the quantity of the contract and the underlying market price or fair value per unit.  When quantities are not specified in the contract, the company estimates load amounts using amounts referenced in default provisions and other relevant sections of the contract.  The estimated load 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.  Contracts for which the company has elected the normal exception may be designated if qualified as cash flow hedges with changes in fair value recorded in accumulated other comprehensive income.  If the normal exception is terminated, then the cash flow hedge accounting is also terminated to the extent that the company no longer expects to physically deliver under the contract.  In connection with the expect ed sale of the retail marketing business, in the first quarter of 2006 management discontinued normal accrual accounting and cash flow hedge accounting for retail derivative contracts with deliveries beyond the mid-year expected divestiture of the retail business.  Accordingly, the fair value of these contracts was recorded in other operation expenses in the first quarter of 2006.  See "Impairment of Long-Lived Assets" below.

For further information regarding hedge accounting, see Note 5, "Derivative Instruments," to the condensed consolidated financial statements.  

The Utility Group reports the settlement of all short-term sales contracts that are part of procurement activities on a net basis in expenses.

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 the NU Enterprises businesses.  

When the company believes one of these events has occurred, the determination needs to be made whether a long-lived asset should be classified as held and used or 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 and depreciation of these assets is discontinued.  

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.

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In the first quarter of 2006, management determined that the competitive generation business, which includes NGC and Mt. Tom, should be classified as assets held for sale rather than held and used.  Using the impairment testing for assets held for sale, at March 31, 2006 NU determined that no impairment existed for the competitive generation business generation assets as the fair value of these assets less their expected costs to sell exceeded their carrying values.  In the first quarter of 2006, management also determined that the retail marketing business should be classified as held for sale and should therefore be recorded at fair value less cost to sell.  For the three months ended March 31, 2006, NU recorded a pre-tax charge of $59.9 million in other operation expenses to record the retail marketing business at fair value less cost to sell, including derivative contracts that no longer qualified for accrual accounting because physical delivery could not be asse rted.  An expected cost to sell of $3 million is included in restructuring and impairment charges for the first quarter of 2006 and represents professional fees expected to be incurred on the sale of the retail marketing business.

For further information regarding 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 condensed consolidated financial statements.

Other Matters

Commitments and Contingencies:  For further information regarding other commitments and contingencies, see Note 7, "Commitments and Contingencies," to the condensed consolidated financial statements.

Contractual Obligations and Commercial Commitments:  For updated information regarding NU's contractual obligations and commercial commitments at March 31, 2006, see Note 7C, "Commitments and Contingencies - Long-Term Contractual Arrangements," to the condensed consolidated financial statements.  

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 opted not to seek review of this ruling by the United States Supreme Court.  On April 7, 2006, NU filed its motion for partial summary judgment on Con Edison's damage claim.  At this stage, NU cannot predict the outcome of this matter or its ultimate effect on NU.

Proposed Accounting Pronouncement:

Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans:  On March 31, 2006, the Financial Accounting Standards Board (FASB) issued an exposure draft, "Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans - an amendment of FASB Statements No. 87, 88, 106 and 132(R)."  An exposure draft is not a final accounting pronouncement and is subject to change.  If adopted as proposed, a company would be required to recognize the projected benefit pension and other postretirement plan obligations, net of the fair value of plan assets, on the balance sheet.  The offsetting amount to the adjustment would be recognized in shareholders' equity, primarily in other comprehensive income.  The exposure draft is expected to be effective on December 31, 2006, and would be retroactively applied to comparative prior year financial statements.  If adopted in its present form, and to the extent the co mpany is unable to receive rate treatment allowing for the establishment of a regulatory asset, the final statement is expected to result in a material reduction of NU's shareholders' equity.  See Note 11, "Pension Benefits and Postretirement Benefits Other Than Pensions," to the condensed consolidated financial statements for information related to NU's defined benefit pension and other postretirement benefit plans.  

Accounting Standard Issued But Not Yet Adopted:

 Accounting for Servicing of Financial Assets:  In March of 2006, the FASB issued SFAS No. 156, "Accounting for Servicing of Financial Assets - An Amendment of FASB Statement No. 140."  SFAS No. 156 requires an entity to recognize a servicing asset or liability at fair value each time it undertakes an obligation to service a financial asset by entering into a servicing contract in a transfer of the servicer's financial assets that meets the requirements for sale accounting and in other circumstances.  Servicing assets and liabilities may be subsequently measured through either amortization or recognition of fair value changes in earnings.  SFAS No. 156 is required to be applied prospectively to transactions beginning on January 1, 2007.  The company is evaluating the effect of this statement on its accounting for sale and servicing of accounts receivable.  

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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 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 deve lopments or circumstances occurring after the statement is made.

Web Site:  Additional financial information is available through NU’s web site at www.nu.com.

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RESULTS OF OPERATIONS - NU CONSOLIDATED

The following table provides the variances in income statement line items for the condensed consolidated statements of loss for NU included in this report on Form 10-Q for the three months ended March 31, 2006:

	Income Statement Variances (Millions of Dollars) 2006 over/(under) 2005
	Amount				Percent
Operating Revenues:		$	(85)		(4)	%
Operating Expenses:
Fuel, purchased and net interchange power		(132)			(8)
Other operation		64			26
Wholesale contract market changes, net		(182)			(96)
Restructuring and impairment charges		(16)			(76)
Maintenance		2			6
Depreciation		4			7
Amortization		36			(a)
Amortization of rate reduction bonds		3			6
Taxes other than income taxes		2			3
Total operating expenses		(219)			(9)
Operating income/(loss)		134			(a)
Interest expense, net		5			9
Other income, net		10			(a)
Loss before income tax benefit		139			79
Income tax benefit		46			72
Preferred dividends of subsidiary		-			-
Loss from continuing operations		93			82
Income/(loss) from discontinued operations		15			(a)
Net Loss		$		108	91	%

(a) Percent greater than 100.

Comparison of the First Quarter of 2006 to the First Quarter of 2005

Operating Revenues

Operating revenues decreased $85 million in the first quarter of 2006 primarily due to lower revenues from NU Enterprises ($314 million), partially offset by higher distribution revenues ($215 million) and higher regulated transmission business revenues ($12 million).

The NU Enterprises’ revenues decrease of $314 million is primarily due to progress in the divesture of the competitive businesses.  Revenues in the wholesale marketing business decreased $438 million as a result of exiting all of its New England wholesale sales obligations in 2005 by either buying out those contracts or assigning its obligations to third parties.  There were no additional contracts bought out or assigned in the first quarter of 2006.  The remaining wholesale obligations in the PJM power pool expire in 2008 and the remaining wholesale obligation in New York continues through 2013.  NU Enterprises’ revenues also decreased primarily due to the sale of the Massachusetts service location of SECI-CT in January 2006 ($12 million).  These decreases are partially offset by an increase in the retail marketing business primarily as a result of higher prices ($100 million).

Distribution revenues increased $215 million primarily due to higher electric distribution revenues ($225 million), partially offset by lower gas distribution revenues ($11 million).  Higher electric distribution revenues include 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 ($222 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 $222 million is primarily due to the pass through of higher energy supply costs ($180 million), higher CL&P FMCC charges ($34 million) and higher wholesale revenues ($6 million).  The distribution component of these companies and the retail transmission component of PSNH which flow through to earnings increased $ 3 million primarily due to an increase in regulated retail

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rates, partially offset by a decrease in retail sales.  Retail electric sales decreased 3.5 percent in 2006 compared with 2005, primarily due to a mild winter.  On a weather adjusted basis, retail electric sales were lower by 0.9 percent.

The increase in distribution revenues is partially offset by lower gas distribution revenues of $11 million primarily due to lower sales volumes, partially offset by the recovery of increased gas costs.  Firm gas sales decreased 13.5 percent in 2006 compared with 2005 primarily due to a mild winter and increased conservation driven by higher gas costs.  On a weather adjusted basis, firm gas sales decreased 3.4 percent.

Transmission business revenues increased $12 million primarily due to the recovery of higher operating expenses in 2006 as allowed under FERC Tariff Schedule 21 and a higher transmission investment base.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expenses decreased $132 million in the first quarter of 2006, primarily due to lower fuel costs at NU Enterprises ($329 million), partially offset by higher fuel costs for distribution ($196 million).  

NU Enterprises’ lower fuel costs of $329 million are primarily due progress in the divesture of the competitive businesses.  Fuel costs decreased $515 million in the wholesale marketing business primarily due to the absence of servicing the New England wholesale sales contracts that were exited in 2005.  The remaining wholesale obligations in the PJM power pool expire in 2008 and the remaining wholesale obligation in New York continues through 2013.  This decrease is partially offset by higher fuel costs in the retail marketing business ($186 million).

The $196 million increase in distribution fuel costs is primarily due to higher standard offer supply costs for CL&P and WMECO ($185 million) and higher expenses for PSNH primarily due to higher energy costs ($16 million).  The increase in distribution fuel costs is partially offset by lower Yankee Gas expenses as a result of lower gas sales, partially offset by increased gas prices ($5 million).

Other Operation

Other operation expenses increased $64 million in the first quarter of 2006, primarily due to a charge to record the retail marketing business at fair value less cost to sell ($60 million).  See Note 4, "Assets Held for Sale and Discontinued Operations," to the condensed consolidated financial statements for a description and explanation of this amount.

In addition, other operation expenses increased primarily due to higher distribution reliability must run (RMR) costs and other power pool related expenses ($20 million) and higher pension and benefit expense ($3 million).  These increases are partially offset by lower NU Enterprises’ expenses of $19 million primarily due to the sale of the Massachusetts service location of SECI-CT in January 2006 and lower costs from progress in exiting the competitive businesses.

Wholesale Contract Market Changes, Net

See Note 2, "Wholesale Contract Market Changes," to the condensed consolidated financial statements for a description and explanation of this amount.

Restructuring and Impairment Charges

See Note 3, "Restructuring and Impairment Charges," to the condensed consolidated financial statements for a description and explanation of this amount.

Maintenance

Maintenance expenses increased $2 million in the first quarter of 2006 primarily due to higher distribution tree trimming costs and transmission maintenance expenses.

Depreciation

Depreciation increased $4 million in the first quarter of 2006 primarily due to higher distribution and transmission plant balances.

Amortization

Amortization increased $36 million in the first quarter of 2006 primarily due to PSNH's distribution ($34 million).  The PSNH increase is primarily due to the overrecovery of ES costs in February and March of 2006 ($23 million) and the acceleration in the recovery of PSNH’s non-securitized stranded costs as a result of the positive reconciliation of stranded cost revenues and expenses ($11 million).

Amortization of Rate Reduction Bonds

Amortization of rate reduction bonds increased $3 million in the first quarter of 2006 due to distribution’s repayment of a higher principal amount as compared to 2005.

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Taxes Other Than Income Taxes

Taxes other than income taxes increased $2 million in the first quarter of 2006 primarily due to distribution’s higher property taxes and higher Connecticut gross earnings tax related to higher CL&P revenues.

Interest Expense, Net

Interest expense, net increased $5 million in the first quarter of 2006 primarily due to the issuance of $350 million in long-term debt in 2005.  The long-term debt 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.

Other Income, Net

Other income, net increased $10 million in the first quarter of 2006 primarily due to higher investment income ($6 million), which includes $2 million for CL&P related to a Connecticut tax refund claim settlement, and higher allowance for funds used in construction ($3 million).  

Income Tax Benefit

Income tax benefit decreased $46 million to a benefit of $18 million in the first quarter of 2006 primarily due to a lower loss before income tax and higher non-plant flow through differences; partially offset by increased tax benefit and other adjustments to tax reserves.  The increase in the tax benefit results from favorably settling an income tax refund claim.  

Income/(Loss) from Discontinued Operations

For the quarter ended March 31, 2006 and 2005, the operations of NGC, the generation operations of HWP, SESI and Woods Electrical were presented as discontinued operations as a result of meeting certain criteria requiring this presentation.  In addition, SECI-NH (including Reeds Ferry) and Woods Network are included in discontinued operations for the three months ended March 31, 2005.  These businesses were sold in November of 2005.  Under this presentation, revenues and expenses of these businesses are included in the income/(loss) from discontinued operations on the condensed consolidated statements of loss.  See Note 4, "Assets Held for Sale and Discontinued Operations," to the condensed financial statements for a description and explanation of the discontinued operations.

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THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

Management’s Discussion and Analysis of

Financial Condition and Results of Operations

CL&P is a wholly owned subsidiary of NU.  This discussion should be read in conjunction with NU's management’s discussion and analysis of financial condition and results of operations, condensed consolidated financial statements and footnotes in this Form 10-Q, the NU 2005 Form 10-K.  

RESULTS OF OPERATIONS

The following table provides the variances in income statement line items for the condensed consolidated statements of income for CL&P included in this report on Form 10-Q for the three months ended March 31, 2006:

	Income Statement Variances (Millions of Dollars) 2006 over/(under) 2005
	Amount				Percent
Operating Revenues:		$	166		20	%
Operating Expenses:
Fuel, purchased and net interchange power		128			24
Other operation		28			24
Maintenance		2			10
Depreciation		3			10
Amortization of regulatory (liabilities)/assets, net		4			85
Amortization of rate reduction bonds		2			7
Taxes other than income taxes		1			2
Total operating expenses		168			22
Operating Income		(2)			(3)
Interest expense, net		2			5
Other income, net		7			(a)
Income before income tax expense		3			9
Income tax expense		(4)			(31)
Net Income		$		7	28	%

(a) Percent greater than 100.

Comparison of the First Quarter of 2006 to the First Quarter of 2005

Operating Revenues

Operating revenues increased $166 million in the first quarter of 2006, compared with the same period in 2005, due to higher distribution revenues ($157 million) and higher transmission revenues ($9 million).

The distribution revenue increase of $157 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 ($156 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 $1 million, primarily due to higher retail rates as a result of the rate increase effective January 1, 2006, partially offset by decreased sales volumes.  Retail sales in the first quarter of 2006 were 4.2 percent lower than the same period in 2005.

The distribution revenue tracking components increased $156 million primarily due to higher TSO related revenues ($108 million), an increase in revenues associated with the recovery of FMCC charges ($34 million), and higher wholesale revenues ($7 million) primarily due to higher market prices for the sales of IPP contract related power.

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Transmission revenues increased $9 million primarily due to a higher rate base and higher operating expenses which are recovered under the NU schedule 21 tariff.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expense increased $128 million in the first quarter of 2006 primarily due to higher standard offer supply costs as a result of higher fuel costs, partially offset by deferred fuel costs.

Other Operation

Other operation expenses increased $28 million in the first quarter of 2006 primarily due to higher RMR costs ($21 million) which are tracked and recovered through the FMCC, higher pension and other benefit costs ($2 million) and higher C&LM expenses ($1 million).

Maintenance

Maintenance expenses increased $2 million in the first quarter of 2006 primarily due to higher expenses related to underground lines maintenance.

Depreciation

Depreciation expense increased $3 million in the first quarter of 2006 due to higher utility plant balances resulting from plant additions.

Amortization of Regulatory Liabilities, Net

Amortization of regulatory liabilities, net increased $4 million in the first quarter of 2006 primarily due to higher amortization related to the recovery of transition charges ($1 million), higher amortization of transmission project costs ($1 million), and higher amortization of the securitized FAS109 regulatory asset.

Amortization of Rate Reduction Bonds

Amortization of rate reduction bonds increased $2 million in the first quarter of 2006 due to the repayment of additional principal.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $1 million in the first quarter of 2006, primarily due to higher property taxes.   

Interest Expense, Net

Interest expense, net increased $2 million in the first quarter of 2006 primarily due to higher interest on long-term debt ($3 million) mainly as a result of $200 million of new debt issued in April 2005, partially offset by lower rate reduction bond interest resulting from lower principal balances outstanding ($2 million).

Other Income, Net

Other income, net increased $7 million in the first quarter of 2006 primarily due to interest income related to a Connecticut tax refund claim settlement ($2 million), higher AFUDC ($2 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, and higher other interest income ($1 million).

Income Tax Expense

Income tax expense decreased $4 million in the first quarter of 2006 primarily as a result of favorably settling a Connecticut refund claim.  

LIQUIDITY

Net cash flows from operations decreased by $41.2 million from net cash flows provided by operating activities of $6.7 million for the first quarter of 2005 to net cash flows used in operating activities of $34.5 million for the first quarter of 2006.  The decrease in operating cash flows is primarily due to higher regulatory refunds as CL&P refunded amounts to its ratepayers to moderate the increase in CL&P's TSO rates which was effective on January 1, 2006.  The decrease in operating cash flows is also due to an estimated federal income tax payment of approximately $20 million related to CL&P's 2005 tax return which was made in the first quarter of 2006.  This decrease is offset by changes in working capital items, primarily a decrease in accounts receivable and an increase in accounts payable.

CL&P's capital expenditures totaled $124.2 million in the first three months of 2006, compared with $91.3 million in the first three months of 2005.  This increase is primarily due to higher transmission capital expenditures.  CL&P projects capital expenditures to total approximately $600 million in 2006.

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At March 31, 2006, CL&P had $125 million of borrowings on the Utility Group's revolving credit line.  Additionally, 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 March 31, 2006, CL&P had sold $100 million to that financial institution.  Financing activities also included the payment of $15.9 million in dividends to NU during the first three months of 2006 compared to $13.5 million during the first three months of 2005.

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PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

Management’s Discussion and Analysis of

Financial Condition and Results of Operations

PSNH is a wholly owned subsidiary of NU.  This discussion should be read in conjunction with NU's management’s discussion and analysis of financial condition and results of operations, condensed consolidated financial statements and footnotes in this Form 10-Q and the NU 2005 Form 10-K.  

RESULTS OF OPERATIONS

The following table provides the variances in income statement line items for the condensed consolidated statements of income for PSNH included in this report on Form 10-Q for the three months ended March 31, 2006:

	Income Statement Variances (Millions of Dollars) 2006 over/(under) 2005
	Amount				Percent
Operating Revenues:		$	46		17	%
Operating Expenses:
Fuel, purchased and net interchange power		16			13
Other operation		(1)			(2)
Maintenance		-			-
Depreciation		1			8
Amortization of regulatory (liabilities)/assets, net		34			(a)
Amortization of rate reduction bonds		1			5
Taxes other than income taxes		-			-
Total operating expenses		51			21
Operating Income		(5)			(17)
Interest expense, net		-			-
Other income, net		1			(a)
Income before income tax expense		(4)			(26)
Income tax expense		-			-
Net Income		$		(4)	(42)	%

(a) Percent greater than 100.

Comparison of the First Quarter of 2006 to the First Quarter of 2005

Operating Revenues

Operating revenues increased $46 million in the first quarter of 2006, as compared to the same period in 2005, primarily due to higher distribution revenue ($44 million) and higher transmission revenue ($2 million).  The distribution revenue increase of $44 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 ($42 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 energy service rate component of retail revenues increased by $47 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 $2 million primarily due to the retail rate increases effective June 1, 2005 ($3 million), partia lly offset by lower retail sales ($1 million).  Retail sales decreased 0.8 percent in 2006 compared to the same period of 2005.  

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power increased $16 million in 2006 primarily due to the higher cost of energy as a result of higher fuel prices.   

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Other Operation

Other operation expenses decreased $1 million primarily due to lower customer service expenses ($2 million) and lower power pool related expenses ($1 million), partially offset by higher administrative expenses primarily due to higher pension and medical costs ($2 million).

Depreciation

Depreciation expense increased $1 million in the first quarter of 2006 primarily due to higher plant balances.

Amortization of Regulatory Assets, Net

Amortization of regulatory assets, net increased $34 million in 2006.  The majority of the increase ($23 million) was due to the over-recovery of ES costs in February and March of 2006.  The remainder of the increase ($11 million) represents an acceleration in the recovery of PSNH’s non-securitized stranded costs.

From May 2001 through January 31, 2006, the difference between PSNH ES revenues and ES costs was deferred and included in the SCRC calculation for recovery or refund.  On January 20, 2006 the NHPUC issued an order setting 2006 ES rates effective February 1, 2006, that included a change in accounting for ES deferrals.  Effective February 1, 2006, PSNH began deferring the difference between ES revenues and ES costs for inclusion in the calculation of the subsequent ES rate.  The current $23 million positive difference between ES revenues and ES costs will be used to either offset cost increases in the 2006 ES rate period, or lower the 2007 ES rate.  The acceleration of non-securitized stranded cost recovery was due to the positive reconciliation of stranded cost revenues and stranded cost expense, and includes net ES costs for January 2006.

Amortization of Rate Reduction Bonds

Amortization of rate reduction bonds increased $1 million as a result of the repayment of additional principal.

Other Income/(Loss), Net

Other income/(loss), net increased $1 million in 2006 primarily due to 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.

LIQUIDITY

Net cash flows from operations increased by $66.3 million from $31 million for the first quarter of 2005 to $97.3 million for the first quarter of 2006.  The increase in operating cash flows is primarily due to an increase in the collection of regulatory assets.

PSNH's capital expenditures totaled $35.1 million in the first three months of 2006, compared with $40.3 million in the first three months of 2005.  PSNH projects capital expenditures to total $150 million in 2006.

Financing activities for the three months ended March 31, 2006 included the payment of $23 million in dividends to NU, compared to $6.1 million during the first three months of 2005.

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WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

Management's Discussion and Analysis of

Financial Condition and Results of Operations

WMECO is a wholly owned subsidiary of NU.  This discussion should be read in conjunction with NU's management’s discussion and analysis of financial condition and results of operations, condensed consolidated financial statements and footnotes in this Form 10-Q and the NU 2005 Form 10-K.  

RESULTS OF OPERATIONS

The following table provides the variances in income statement line items for the condensed consolidated statements of income for WMECO included in this report on Form 10-Q for the three months ended March 31, 2006:

	Income Statement Variances (Millions of Dollars) 2006 over/(under) 2005
	Amount				Percent
Operating Revenues:		$	24		24	%
Operating Expenses:
Fuel, purchased and net interchange power		26			42
Other operation		-			-
Maintenance		-			-
Depreciation		-			-
Amortization of regulatory (liabilities)/assets, net		(1)			74
Amortization of rate reduction bonds		-			-
Taxes other than income taxes		-			-
Total operating expenses		25			28
Operating Income		(1)			(5)
Interest expense, net		-			-
Other income, net		1			(a)
Income before income tax expense		-			-
Income tax expense		(1)			(18)
Net Income		$		1	10	%

(a) Percent greater than 100.  

Comparison of the First Quarter of 2006 to the First Quarter of 2005

Operating Revenues

Operating revenues increased $24 million in the first quarter of 2006, as compared to the same period in 2005, primarily due to higher distribution revenue ($24 million) and higher transmission revenue ($1 million).  The distribution revenue increase of $24 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 ($25 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 $25 million is primarily due to the pass through of higher energy supply costs ($26 million), partially offset by lower retail transmission revenues ($1 million).  The distribution component of WMECO’s retail rates which impacts earnings decreased $1 million primarily due to a decrease in retail sales volume.  Retail sales decreased 4.9 percent in 2006 compared to 2005.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expense increased $26 million in the first quarter of 2006 primarily due to higher default service supply costs.

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Amortization of Regulatory (Liabilities)/Assets, Net

Amortization of regulatory (liabilities)/assets, net decreased $1 million in the first quarter of 2006 primarily due to a lower deferral of transition costs, as a result of higher default service expenses.  

Other Income, Net

Other income, net increased $1 million in the first quarter of 2006 primarily due to higher interest and dividend income, and higher C&LM incentive.

Income Tax Expense

Income tax expense decreased $1 million in the first quarter of 2006 primarily due to a higher nontaxable Medicare subsidy and slower growth in bad debt reserves.  

LIQUIDITY

Net cash flows from operations decreased by $18 million from net cash flows provided by operating activities of $8.1 million for the first three months of 2005 to net cash flows used in operating activities of $9.9 million for the first three months of 2006.  The decrease in operating cash flows is primarily due to an increase in the regulatory assets that will be recovered from WMECO's customers.

WMECO's capital expenditures totaled $10.4 million in the first three months of 2006, compared with $11 million in the first three months of 2005.  WMECO projects capital expenditures to total approximately $50 million in 2006.

At March 31, 2006, WMECO had $10 million of borrowings on the Utility Group's revolving credit line.  Financing activities for the three months ended March 31, 2006 also included a capital contribution from NU in the amount of $14.5 million and the payment of $2 million in dividends to NU during the first three months of 2006, compared to $1.9 million during the first three months of 2005.

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ITEM 3.

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 prices.   As the NU Enterprises' businesses are exited, the risks associated with commodity prices are expected to be reduced.  

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 March 31, 2006, 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 in a pre-tax decrease in fair value of $25.1 million ($15.7 million after-tax) and a 10 percent decrease would have resulted in a pre-tax increase in fair value of $23.9 million ($14.9 million after-tax).

The impact of a change in electricity and natural gas prices on Select Energy's wholesale transactions at March 31, 2006 are not necessarily representative of the results that will be realized.  These transactions are accounted for at fair value, and changes in market prices impact earnings.

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 March 31, 2006, a 10 percent increase in market price would have resulted in a pre-tax decrease in fair value of $5.9 million ($3.7 million after-tax) and a 10 percent decrease would have resulted in a pre-tax increase in fair value of $5.9 million ($3.7 million after-tax).

The impact of a change in electricity and natural gas prices on Select Energy's retail marketing portfolio at March 31, 2006, is not necessarily representative of the results that will be realized.  

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 generation contracts was determined assuming a 10 percent change in forward market prices.  At March 31, 2006, a 10 percent increase in market price would have resulted in a pre-tax increase in fair value of $164.3 million ($102.5 million after-tax) and a 10 percent decrease would have resulted in a pre-tax decrease in fair value of $164.3 million ($102.5 million after-tax).  These transactions are accounted for at fair value, and changes in market prices impact earnings.  

The impact of a change in electricity prices on merchant energy’s generation portfolio at March 31, 2006, is not necessarily representative of the results that will be realized.  

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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 March 31, 2006, approximately 12.7 percent (21 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 March 31, 2006, NU parent maintained a fixed-to-floating interest rate swap to manage the interest rate risk associated with its $263 million of fix ed-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 negatively, in tha t the counterparties may be similarly affected by changes to economic, regulatory or other conditions.

At March 31, 2006 and December 31, 2005, Select Energy maintained collateral balances from counterparties of $12.9 million and $28.9 million, respectively.  These amounts are included in counterparty deposits on the accompanying condensed consolidated balance sheets.  Select Energy also has collateral balances deposited with counterparties of $54.8 million and $103.8 million at March 31, 2006 and December 31, 2005 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.

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.

Additional quantitative and qualitative disclosures about market risk are set forth in Part I, Item 2, "Management's Discussion and Analysis of Financial Condition and Results of Operations," included in this combined report on Form 10-Q.

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ITEM 4.

CONTROLS AND PROCEDURES

NU evaluated the design and operation of its disclosure controls and procedures at March 31, 2006 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 NU’s principal executive officer and principal financial officer, as of the end of the period covered by this report on Form 10-Q.  The principal executive officer and principal financial officer concluded, based on their review, that NU’s disclosure controls and procedures were effective to ensure that information required to be disclosed by NU in reports that it files under the Exchange Act i) is recorded, processed, summarized, and reported within the timeframes specified in SEC rules and forms and ii) is accumulated and communicated to management, including the principal executive offi cer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

There have been no significant changes in NU’s internal controls over financial reporting during the quarter ended March 31, 2006 that have materially affected, or are reasonably likely to materially affect NU’s internal control over financial reporting.

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PART II.  OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

1.

Consolidated Edison, Inc. (Con Edison) v. NU - Merger Litigation

On October 12, 2005, the United States 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 parties’ 1999 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 has opted not to seek certiora ri review by the U.S. Supreme Court.  On April 7, 2006, NU filed a Motion for Partial Summary Judgment relating to Con Edison’s damages claim.

At this stage, it is not possible to predict either the outcome of this matter or its ultimate effect on NU.

For further information on this litigation and related matters, see Part I, Item 3, "Legal Proceedings," in NU’s 2005 Form 10-K.

ITEM 1A.

RISK FACTORS

NU is subject to a variety of significant risks in addition to the matters set forth under "Forward Looking Statements," in Item 2, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Other Matters."  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, agreed on May 1, 2006 to sell its retail marketing business, has sold four of its six services businesses and plans to sell the remainder by the end of 2006, and is actively marketing its competitive generation assets.

Assuming the sale of the retail marketing business is consummated by June 1, 2006, as presently contemplated, the principle remaining risks from NU’s competitive businesses are related to the unhedged portion of a large wholesale contract expiring in 2013 and the outcome of the pending sales process for competitive generation.  This wholesale contract carries the risk that Select Energy may have to serve higher-than-anticipated loads, which will vary depending on weather and other factors not in its control.  Select Energy may settle this contract in the future, possibly at a cost higher than its present mark on the contract.  In the first quarter of 2006, the wholesale marketing and competitive generation businesses was profitable while the retail marketing business lost $69.8 million, partially due to the impacts of the 2005 decision to exit the wholesale marketing business.  The sale of the retail business by June 1, as anticipated, will end NU’s exposur e to this business and have a modest impact on financial results in the second quarter of 2006 with no material impact on NU’s liquidity.  

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 March 31, 2006 was a net liability of $173.7 million, all which has been reflected in first quarter of 2006 results.

NU’s decision to exit the competitive generation business could have material negative financial implications in 2006, depending on the outcome of a number of factors, including the results of future asset impairment analyses, recognition of closure or exit costs in excess of estimates and recognition of other losses from disposing of or otherwise exiting this business.  The amount and timing of these losses will depend on how the disposition of the competitive generation business is accomplished.

Exiting from Select Energy’s remaining wholesale obligations could have an adverse impact on NU’s liquidity, although any negative effect is expected to be mitigated by the sale of the competitive generating assets.  The book value of NU’s competitive generating assets was approximately $825 million at March 31, 2006.  NU’s equity investment in its generation business was approximately $420 million at March 31, 2006.  Should NU fail to realize this equity amount on sale of this business after payment or assumption of all related debt, NU could incur further charges.  

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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 purc hase 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 of 2005 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.

The competitive generation business is also subject to certain risks. The future values of Forward Capacity Market 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 March 31, 2006, approximately $315 million of collateral or letters of credit to unaffiliated counterparties and $98 million to several independent system operators and unaffiliated local distribution companies and LDCs under agreements largely guaranteed by NU.  In addition, at March 31, 2006, Select Energy could have been requested to provide $3 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; $72 million for replacement of an undersea electric transmission line between Norwalk and Northport, New York; and $120 million for two 115 kV underground transmission lines between Norwalk and Stamford, Connecticut, which costs are under review.  The regulatory approval process for these transmission

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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 FERC 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, require NU to incur additional expenses and/or delay recovery of transmission costs from customers, and may adversely affect its ability to achieve forecasted 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.

Failure of the operating companies to obtain timely and adequate rate increases could adversely affect their financial condition, profitability and credit ratings.

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 this legal proceeding, as well as other matters, is set forth in Part II, Item 1, "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 it.  

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 Environment al Matters - Environmental Regulation" of NU’s 2005 Annual Report on Form 10-K.

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.  

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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 appears to be reducing 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.  

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ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

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 quarter ended March 31, 2006.

ITEM 6.

EXHIBITS

(a)

Listing of Exhibits (NU)

Exhibit No.

Description

10

Material Contracts

10.31

Summary of Trustee Compensation

10.32

Purchase and Sale Agreement dated as of May 1, 2006 between Select Energy, Inc. and Amerada Hess Corporation

15

Deloitte & Touche LLP Letter Regarding Unaudited Financial Information

31

Certification of Charles W. Shivery, Chairman, President and Chief Executive Officer of Northeast Utilities, 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 May 5, 2006

31.1

Certification of David R. McHale, Senior Vice President and Chief Financial Officer of Northeast Utilities, 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 May 5, 2006

32

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 May 5, 2006

(a)

Listing of Exhibits (CL&P)

31

Certification of Cheryl W. Grisé, Chief Executive Officer of The Connecticut Light and Power Company, 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 May 5, 2006

31.1

Certification of David R. McHale, Senior Vice President and Chief Financial Officer of The Connecticut Light and Power Company, 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 May 5, 2006

32

Certification of Cheryl W. Grisé, Chief Executive Officer of The Connecticut Light and Power Company and David R. McHale, Senior Vice President and Chief Financial Officer of The Connecticut Light and Power Company, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated May 5, 2006

(a)

Listing of Exhibits (PSNH)

31

Certification of Cheryl W. Grisé, Chief Executive Officer of Public Service Company of New Hampshire, 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 May 5, 2006

31.1

Certification of David R. McHale, Senior Vice President and Chief Financial Officer of Public Service Company of New Hampshire, 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 May 5, 2006

92

32

Certification of Cheryl W. Grisé, Chief Executive Officer of Public Service Company of New Hampshire and David R. McHale, Senior Vice President and Chief Financial Officer of Public Service Company of New Hampshire, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated May 5, 2006

(a)

Listing of Exhibits (WMECO)

31

Certification of Cheryl W. Grisé, Chief Executive Officer of Western Massachusetts Electric Company, 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 May 5, 2006

31.1

Certification of David R. McHale, Senior Vice President and Chief Financial Officer of Western Massachusetts Electric Company, 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 May 5, 2006

32

Certification of Cheryl W. Grisé, Chief Executive Officer of Western Massachusetts Electric Company and David R. McHale, Senior Vice President and Chief Financial Officer of Western Massachusetts Electric Company, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated May 5, 2006

93

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.  

		NORTHEAST UTILITIES
		Registrant
Date:  May 5, 2006	By	/s/ David R. McHale
		David R. McHale
		Senior Vice President and Chief Financial Officer
		(for the Registrant and as Principal Financial Officer)

____________________________________________________________________________________

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.  

		THE CONNECTICUT LIGHT AND POWER COMPANY
		Registrant
Date:  May 5, 2006	By	/s/ David R. McHale
		David R. McHale
		Senior Vice President and Chief Financial Officer
		(for the Registrant and as Principal Financial Officer)

94

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

		PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
		Registrant
Date:  May 5, 2006	By	/s/ David R. McHale
		David R. McHale
		Senior Vice President and Chief Financial Officer
		(for the Registrant and as Principal Financial Officer)

____________________________________________________________________________________

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.    

		WESTERN MASSACHUSETTS ELECTRIC COMPANY
		Registrant
Date:  May 5, 2006	By	/s/ David R. McHale
		David R. McHale
		Senior Vice President and Chief Financial Officer
		(for the Registrant and as Principal Financial Officer)

95

EX-10.31

Exhibit 10.31

Following is a summary of the compensation arrangement between Northeast Utilities and the members of its Board of Trustees.

Each Trustee who is not an employee of Northeast Utilities or its subsidiaries receives an annual retainer.  The Lead Trustee and the Chairs of the Audit, Compensation, Corporate Affairs, Corporate Governance and Finance Committees receive additional annual retainers.  All retainers are payable quarterly.  The following table sets forth the amounts of the retainers for 2006:

	2006
Trustees	$45,000
Lead Trustee	$50,000
Audit Committee Chair	$20,000
Compensation Committee Chair	$15,000
Corporate Responsibility Committee Chair	$  7,500
Corporate Governance Committee Chair	$  7,500
Finance Committee Chair	$10,000

One-half of the value of the retainers to the Chairs of the Audit and Compensation Committees is payable in the form of common shares of NU.  

For 2006, non-employee Trustees received $1,500 for each meeting of the full Board and $1,250 for each Committee meeting through March 7, 2006, regardless of whether attendance was in person or by conference telephone.  Subsequent to March 7, 2006, Trustees will receive $1,500 for each Board meeting and each Committee meeting attended, regardless of whether attendance is in person or by conference telephone.

A non-employee Trustee who is asked by either the Board of Trustees or the Chairman of the Board to perform extra Board-related services in the interest of the Northeast Utilities System may receive additional compensation of $750 per half-day plus necessary expenses.  In addition, when the spouses of Trustees are invited to attend functions of the Board, the Company pays for the travel-related expenses of the spouses that attend such functions.  The payment of a Trustee's spousal expenses is considered imputed income to the individual Trustee and the Company makes a gross-up payment to each such Trustee to cover the tax liability for the imputed income associated with such spousal expenses.

In January 2006, each non-employee Trustee was granted 3,000 restricted share units (RSU) under the Incentive Plan.  Each RSU has the value of one common share of the company.    If a Trustee leaves the Board prior to January 10, 2007, such Trustee will forfeit a pro rata portion of these units.  Absent such forfeiture, and subject to any deferral election in effect, half of these units will be paid as newly-issued shares in January 2007 and half will be paid as newly-issued shares as of the earlier of January 10, 2011, the departure from the Board of Trustees for any reason, Change of Control, death or disability.

EX-10.32

Exhibit 10.32

EXECUTION COPY

PURCHASE AND SALE AGREEMENT

by and between

SELECT ENERGY, INC.

and

AMERADA HESS CORPORATION

Dated as of May 1, 2006

PURCHASE AND SALE AGREEMENT

This Purchase and Sale Agreement (“Agreement”) dated as of May 1, 2006 (the “Agreement Date”), is by and between Select Energy, Inc., a Connecticut corporation (“Seller”), and Amerada Hess Corporation (or such other name as it may be known by following the date hereof), a Delaware corporation (“Buyer,” together with Seller, the “Parties,” and each separately being a “Party”).

RECITALS:

WHEREAS, Seller currently conducts the business of supplying retail electricity and natural gas products and related services to commercial, industrial and institutional customers in the New England, New York and Mid-Atlantic regions of the United States through its own operations and the operations of Select Energy New York, Inc. (“SENY”), a Delaware corporation and wholly-owned subsidiary of Seller (the “Retail Business”);

WHEREAS, Seller desires to sell and Buyer desires to purchase the Retail Business subject to the assumption of certain of the liabilities of Seller, all upon the terms and subject to the conditions set forth in this Agreement; and

WHEREAS, Seller desires to engage Buyer to administer the Administered Contracts (as defined below) and Buyer desires to accept such obligation, all upon the terms and subject to the conditions set forth in this Agreement and in the Administration Agreement (as defined below).  

NOW, THEREFORE, in consideration of the premises and mutual covenants set forth herein, the receipt and sufficiency of which are hereby acknowledged, the Parties agree as follows:

ARTICLE I

DEFINITIONS

1.1

Definitions.

As used in this Agreement, the following terms shall have the meanings set forth below.  All references to articles, sections, subsections, exhibits and schedules herein shall be to those articles, sections, subsections, exhibits and schedules of this Agreement, unless otherwise specified.

“Acquired Assets” has the meaning set forth in Section 2.1(a).

“Acquired Records” has the meaning set forth in Section 6.5.

“Administered Contract(s)” has the meaning set forth in Section 2.3(a).

“Administration Agreement” has the meaning set forth in Section 2.3(b).

“AE/CC Commissions” means commissions paid to Seller’s regional account executives and channel coordinators with respect to Contracts and pursuant to the Commission Plan.  

“Affiliate” of a Person means a Person directly or indirectly controlled by, controlling or under common control with the other Person.  For the purposes of this definition, “control” means, when used with respect to any Person, the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of such Person, whether through the ownership of voting securities, by contract, or otherwise, and the terms “controlling” and “controlled” have correlative meanings.

“Agreement” has the meaning set forth in the introductory paragraph hereto, together with the Schedules and Exhibits, as the same may be amended from time to time.

“Agreement Date” has the meaning set forth in the introductory paragraph hereto.

“Allocations” has the meaning set forth in Section 6.3(m).

“Alternative Credit Support” has the meaning set forth in Section 2.2(d).

“Ancillary Documents” means the Bill of Sale, the Assignment and Assumption Agreement, the Seller Guaranty and the certificates of Buyer and Seller to be delivered at Closing.

“Applicable Law” means any statute, law, rule, or regulation, or judicial or administrative interpretation thereof, any judgment, decision, order, consent order, stipulated agreement, ordinance, writ, injunction, or decree of, any Governmental Entity to which a specified Person or property is subject.

“Assignment and Assumption Agreement” mean an assignment and assumption agreement in the form of Exhibit A.

“Assumed Liabilities” has the meaning set forth in Section 2.1(c).

“Attribute Law Requirements” has the meaning set forth in Section 6.20.

“Attribute Laws” means those Applicable Laws in effect from time to time requiring (a) the disclosure of the fuel source, emissions and/or other attributes of the generation used in providing electric service to retail customers, (b) the inclusion of specified amounts of generation with particular attributes in the generation used in providing electric service to retail customers, and/or (c) that generation falling within specified emission limits be used to serve retail customers.

“Back-to-Back Agreement” means the agreement provided for in Section 2.4, the form of which, if entered into by the Parties as contemplated in this Agreement, will be negotiated in good faith by the Parties as provided herein.

“Backed Transactions” has the meaning set forth in Section 2.4(a).

“Bankrupt” means the condition of being subject to voluntary or involuntary bankruptcy, insolvency, receivership, conservatorship or like proceedings (including the takeover of a party by an applicable regulatory agency) pursuant to Applicable Law.

“Base Annualized Volume” means the total volume for a twelve (12) month period, generally calendar year 2005, or the most recent such period on the Schedule Updates, or the best estimate therefor agreed by the Parties, for each of the retail service Customers of Seller and SENY as of March 6, 2006.

“Billing and Marketing Representative Agreements” means contracts with Persons representing either Seller or SENY or Counterparties in brokering agreements for Power or Gas, and pursuant to which such Persons are paid a specified fee in accordance with the terms of such contracts as a result of a completed transaction.

“Bill of Sale” means a bill of sale in the form of Exhibit B.

“Broker Fees” means fees payable to brokers, marketing representatives, aggregators and other similar Persons under the Contracts.

“Business Day” means any calendar day, excluding Saturdays and Sundays and any other days on which banks in Hartford, Connecticut are permitted or required to close.

“Buyer” has the meaning set forth in the introductory paragraph hereto.

“Buyer’s Closing Conditions” has the meaning set forth in Section 7.2.

“Buyer Indemnified Parties” has the meaning set forth in Section 9.2.

“Buy Out Amount” has the meaning set forth in Section 6.24.

“Buyer Regulatory Approvals” means those consents, approvals, orders or authorizations of, or registrations, declarations or filings with, all Governmental Entities required in connection with the execution, delivery or performance hereof by Buyer set forth on Schedule 1.1(o).

“Cancels/Rebills” means any adjustment, true-up and/or other settlement issued by any LDC, Pipeline Administrator, System Operator and/or Counterparty.

“Closing” has the meaning set forth in Section 5.1.

“Closing Conditions” means, collectively, the Seller’s Closing Conditions and Buyer’s Closing Conditions, as defined in Sections 7.1 and 7.2, respectively.

“Closing Date” has the meaning set forth in Section 5.1.

“COBRA” means the Consolidated Omnibus Budget Reconciliation Act of 1985, as amended.

“Code” means the United States Internal Revenue Code of 1986, as amended.

“Commercially Reasonable Efforts” mean efforts which are reasonably within the contemplation of the Parties at the Agreement Date and which do not require the performing Party to expend any funds other than expenditures that are customary and reasonable in nature and amount in transactions of the kind and nature contemplated by this Agreement in order for the performing Party to satisfy its obligations hereunder or otherwise assist in the consummation of the transactions contemplated by this Agreement.

“Commission Plan” means collectively the Seller’s 2003, 2004 and 2005 Retail Sales Commission Plan for Regional Account Executives and Channel Coordinators, copies of which Buyer acknowledges it has received from Seller.

“Competitive Business” has the meaning set forth in Section 6.24.

“Confidentiality Agreement” means the confidentiality agreement by and among Buyer, Seller and SENY dated November 22, 2005.

“Consent to Assignment and Release” means the assignment of a Contract to Buyer and the release of Seller and its Affiliates from all Liabilities related thereto, in a form or forms mutually acceptable to Seller and Buyer.

“Contracts” means the Select Contracts and SENY Contracts, collectively.

“Counterparty” means a party, other than Seller or its Affiliates, to a Contract.

“Credit Rating” has the meaning set forth in Section 2.2(d).

“Customer” means the Counterparty to a Contract for the retail sale of Power or Gas.

“Damages” means suits, actions, legal or administrative proceedings, arbitrations, claims, payments, charges, judgments, assessments, Liabilities, obligations, orders, damages, Taxes, penalties, losses, fees, fines, alternative compliance payments or costs and expenses, paid or incurred by a Person seeking recovery hereunder, including any legal, consulting or other expenses reasonably incurred in connection therewith.

“Divestiture Period” has the meaning set forth in Section 6.24.

"Dollars" or "$" means United States Dollars.

“Downgrade Event” shall mean any event resulting in either Buyer or Seller Guarantor having a Credit Rating of less than Baa3 from Moody’s and  BBB- from S&P.

“Elections” has the meaning set forth in Section 6.3(m).

“Encumbrances” means liens, pledges, licenses to third parties, leases, rights of first refusal, options to acquire, mortgages, deeds of trust and security interests.

“Enhanced Severance” means with respect to a Hired Employee an amount equal to (a) two (2) weeks of salary (based on such Person's base salary immediately preceding severance and paid bi-weekly) for each full year of service of such Person with Seller and Buyer, measured as continuous service in the case of any year in which such Person was employed by both Seller and Buyer, subject to a minimum of twelve (12) weeks and a maximum of fifty-two (52) weeks of such salary, less applicable federal, state, Social Security and Medicare Tax withholdings, (b) payment of such employee’s payments for the employee and any applicable dependents of the employee (other than co-pay and deductibles) pursuant to COBRA for a period of six (6) months following termination, and (c) the provision of outplacement services of duration and of a nature consistent with Seller’s and its Affiliates’ practices with respect to the div estiture of their respective competitive businesses.

“Exhibit” means an exhibit to this Agreement.

“Excluded Assets” has the meaning set forth in Section 2.1(b).

“Excluded Liabilities” has the meaning set forth in Section 2.1(d).

“FERC” means the Federal Energy Regulatory Commission, or its regulatory successor, as applicable.

“Financial Transmission Rights” means financial transmission rights as defined in the applicable Market Rules and Procedures.

“Gas” means natural gas procured under certain Sourcing Contracts or SENY Contracts, or supplied to Customers under certain Retail Service Contracts or SENY Contracts, and related natural gas pipeline capacity, products, services and storage.

“Governmental Entity” means any court or tribunal in any jurisdiction (domestic or foreign) or any federal, state, municipal or local government or other governmental body, agency, authority (including any state attorney general’s office or office of consumer protection), department, commission, board, bureau, instrumentality, arbitrator or arbitral body (domestic or foreign).

“Hired Employee” has the meaning set forth in Section 6.13(a).

“Indemnified Person” has the meaning set forth in Section 9.5.

“Indemnifying Party” has the meaning set forth in Section 9.5.

“Initial Employment Period” has the meaning set forth in Section 6.13(b).

“Initial MTM Adjustment” has the meaning set forth in Section 2.2(c)(i).

“Interim Period” means the period between the date of relevant initial Schedules and the Closing Date.

“IRS” means the United States Internal Revenue Service, or its successor, as applicable.

“LDCs” means the local distribution companies that distribute Power or Gas to Customers.

“LDC Obligations” means those obligations to meet LDC Rules that Seller and/or SENY is responsible for under, or in connection with, the Contracts or the requirements of any Governmental Entity.

“LDC Pools” means pools established by LDCs with respect to the distribution of Gas to retail customers.

“LDC Rules” means all criteria, rules, tariff provisions, standards, procedures, manuals, business practices or other documentation, obligations or understandings, as such may be amended, replaced, modified, or otherwise changed from time to time, that are applied by any  LDC.

“Liability” or “Liabilities” means all indebtedness, obligations, duties and other liabilities, whether absolute, accrued, contingent, fixed or otherwise, whether known or unknown, whether asserted or unasserted, whether liquidated or unliquidated, or whether due or to become due, including any charges, fees, Taxes, assessments, adders, surcharges, or awards of Damages imposed or authorized by any Governmental Entity, LDC, System Operator and/or  Pipeline Administrator.

“Load Obligations” means electrical load that Seller is responsible for under the Contracts and under the applicable Market Rules and Procedures, LDC Rules and/or the requirements of any Governmental Entity with respect to electrical load.

“Market Rules and Procedures” means all criteria, rules, tariff provisions, standards, procedures, manuals, business practices or other documentation, obligations or understandings, as such may be amended, replaced, modified, or otherwise changed from time to time, that are applied by an electric power pool, independent system operator, regional transmission organization or other similar entity applicable to the Retail Business (including the Contracts) and obligations associated therewith.

“Marks” has the meaning set forth in Section 6.11.

“Master Agreements” means those agreements used in the natural gas and electric power industries that provide generic terms and conditions under which specific transactions can be documented and confirmed by the parties to such transactions.  Such agreements include the North American Energy Standards Board, Inc. and Gas Industry Standards Board, Inc. Base Contracts, the Edison Electric Institute, Inc. Master Power Purchase and Sale Agreement, and the International Swaps and Derivatives Association, Inc. Master Agreement.

“Material Adverse Effect” means (a) any material adverse change, event, effect or occurrence arising or occurring after the Agreement Date, or for a change or event, if arising before the Agreement Date, such change or event, not being known to the Parties or reasonably susceptible to discovery, and with effects occurring after the Agreement Date with respect to the Acquired Assets, Seller or to Buyer, as the case may be, that prevents, or can reasonably be expected to prevent the consummation of the transactions contemplated by this Agreement and for which there is no monetary remedy set forth in this Agreement, or (b) the cessation prior to the Closing of all or substantially all of the operations of the Retail Business by Seller and SENY as a going concern; provided, however, that Material Adverse Effect shall not include any change, event, effect or occurrence (or changes, events, effects or occurrences taken toget her) that results from economic factors affecting the economy as a whole or generally affecting the international, national, regional or local wholesale or retail electric or gas industry as a whole or which does not affect the Contracts or the Parties in any manner or degree significantly different than the industry as a whole, including: (i) changes in the Retail Business, including the failure to consummate new sales (including renewals of existing Retail Service Contracts and/or SENY Contracts) in a manner consistent with past performance and/or the taking of any action and/or the exercise of any rights by any Counterparty that could adversely affect the relationship with such Counterparty, including the ability to continue doing business with such Counterparty; (ii) changes in markets for electric power, natural gas or fuel, including changes in market design and pricing (including the introduction of locational-based capacity requirements), (iii) changes resulting from or associated with acts of war or terrorism; (iv) changes (individually or taken together) in the North American, national, regional or local electric transmission systems or operations thereof; (v) weather generally or natural disasters and the effects thereof; or (vi) Seller’s failure or delay in collecting from Counterparties any reimbursements for billing determinant and other cost recoveries in respect of LDC and System Operators charges levied on Seller related to regulatory changes; and provided, further, that any change, event, effect or occurrence that is cured prior to the Closing shall not be a Material Adverse Effect.

“Moody's” means Moody’s Investor Services, Inc.

“MTM Adjustment” has the meaning set forth in Section 2.2(c)(i).

“Name Use License” has the meaning set forth in Section 6.11.

“Non-Compete Term” has the meaning set forth in Section 6.24.

“NU” means Northeast Utilities, a Massachusetts business trust.

“NU Guarantee” means any guarantee of payment or performance or other direct or indirect assurance or undertaking, in each case provided by or on behalf of Seller and/or SENY by NU under, or in connection with, any Contract, whether in the form of a written guaranty, letter of credit, performance bond, deposit, as a direct signatory party or otherwise, including those undertakings set forth on Schedule 1.1(n).  

“Other Select Agreements” means those contracts and agreements of Seller as of the date specified in, and that are listed on, Schedule 1.1(l).

“Owed” has the meaning set forth in Section 10.1.

“Partner Agreements” means those agreements as of the date specified in, and that are listed on or attached to, Schedule 1.1(b).

“Party” and “Parties” has the meaning set forth in the introductory paragraph hereto.

“Permits” means licenses, approvals, consents, franchises, authorizations, clearances and other permits of, to, from or with, any Governmental Entity.

“Permitted Encumbrances” has the meaning set forth in Section 3.8.

“Person” means any individual, corporation, partnership, joint venture, trust, limited liability company, unincorporated organization, Governmental Entity, Pipeline Administrator, System Operator, LDC or other entity.

“Pipeline Administrator” means each administrator of natural gas pipelines for the transportation of wholesale natural gas.

“Pipeline Obligations” means those obligations, including those imposed by Pipeline Administrators and/or any Governmental Entity and those under LDC Rules, associated with storage, transportation and delivery of Gas (including nominating and balancing).

“Power” means all electric energy, capacity (including locational capacity or any other capacity market design change approved by the FERC and implemented subsequent to the Closing Date), related ancillary services (including operating reserves and locational forward reserves) and any other electricity products (including renewable and/or green energy attributes) and services required, or determined to be required, to be supplied or purchased under the Administered Contracts.  The term Power shall include all requirements electric service to retail customers.

“Prime Rate” means the rate of interest as publicly announced from time to time by Bank of America as its prime rate as stated on the date of the applicable interest calculation.

“Program Agreements” means contracts between Seller and organizations with a membership pursuant to which such organizations endorse Seller to members of such organizations as a supplier of electric power, natural gas and/or related products and services.

“Proprietary Information” means, with respect to Seller, Seller’s valuation

methodologies, credit and/or risk management policies, legal analysis, work product or advice, modeling, and other proprietary records and information relating to Seller’s business activities.

“PUCs” has the meaning set forth in Section 6.18.

“Purchase Price” has the meaning set forth in Section 2.2.

“Receivables Proration Period” has the meaning set forth in Section 6.4(b).

“Reconciliation Period” has the meaning set forth in Section 6.4(d).

“Rejected Contracts” has the meaning set forth in Section 6.1(b).

“Renewable Energy Contracts” means those contracts of Seller related to the procurement and/or performance of obligations under or with respect to the Attribute Laws.

“Renewable Energy Credits” means those renewable energy credits, emission credits and other attributes of generation used to demonstrate compliance with Attribute Laws, including credits and certificates issued or accounted for in any Tracking System.

“Representatives” has the meaning set forth in Section 10.13(a)(i).

“Required Disclosure” has the meaning set forth in Section 10.13(a)(ii).

“Restricted Persons” has the meaning set forth in Section 6.24.

“Retail Business” has the meaning set forth in the introductory paragraph hereto.

“Retail Service Contracts” means contracts between Seller and Customers under which Seller supplies Power and/or Gas at retail to the Customers.

“Retained Accounts Receivable” means (a) all accounts receivable of Seller related to deliveries prior to the Closing Date, and (b) all accounts receivable of SENY related to deliveries prior to the Closing Date, in each case including any rights to reimbursement for any billing determinant and other cost recoveries from Counterparties in respect of LDC and System Operators charges related to deliveries prior to the Closing Date.

“Retained Syracuse Assets” has the meaning set forth in Section 6.19(e).

“S&P” means Standard & Poor’s Rating Group.

“Schedule” means a schedule to this Agreement, whether in hard copy or electronic media.

“Schedule Update” has the meaning set forth in Section 6.14(a).

“Securities Act” means the Securities Act of 1933, as amended.

“Select Contracts” means collectively the (a) Retail Service Contracts, (b) the Sourcing Contracts (with respect to Seller only), (c) the Renewable Energy Contracts, (d) the Sponsorship Contracts, (e) the Partner Agreements, (f) the Transportation and Storage Agreements, (g) the Billing and Marketing Representative Agreements (with respect to Seller only), (h) the Program Agreements, and (i) the Other Select Agreements.

“Seller Intellectual Property” means the intellectual property of Seller described on Schedule 1.1(m).

“Seller” has the meaning set forth in the introductory paragraph hereto.

“Seller’s Closing Conditions” has the meaning set forth in Section 7.1.

“Seller Group” has the meaning set forth in Section 6.3(i).

“Seller Guarantor” means NU.

“Seller Guaranty” means a guaranty in the form of Exhibit C.

“Seller Indemnified Parties” has the meaning set forth in Section 9.3.

“Seller’s Knowledge” means the actual knowledge of Seller’s Vice President, Retail Sales and Marketing, its Managing Director, Power and Gas Operations and all Directors in the Retail Business.

“Seller Regulatory Approvals” means those consents, approvals, orders or authorizations of, or registrations, declarations or filings with, all Governmental Entities required in connection with the execution, delivery or performance hereof by Seller set forth on Schedule 1.1(p).

“SENY” has the meaning set forth in the introductory paragraph hereto.

“SENY Assurances” has the meaning set forth in Section 6.6.

“SENY Contracts” means all of the contracts of SENY.

“SENY Shares” means the 10,000 shares of Common Stock, par value $1.00 per shares, issued by SENY.

“Smith Barney Trades” means those transactions with Citigroup Global Markets, Inc. (dba Smith Barney) listed on Schedule 1.1(i).

“Sourcing Contracts” means, collectively, the following contracts of Seller and SENY (as applicable): (a) transaction confirmations under which Seller procures and otherwise transacts

for Power and Gas at wholesale to serve Customers; (b) the Financial Transmission Rights; and (c) the Smith Barney Trades.

“Sponsorship Contracts” means the Contracts pursuant to which Seller sponsors certain activities and organizations for promotional purposes.

“Storage Gas Locations” means the locations listed on Schedule 6.23 with respect to stored Gas owned by Seller and SENY, as the case may be.

“Supplemental MTM Adjustment” has the meaning set forth in Section 2.2(c)(i).

“System Operator” means the operator of a transmission system for electric power and related products and services , and the administrator of regional market settlement systems for electric power and related products and services as provided for under applicable Market Rules and Procedures.

“Tax” or “Taxes” means all taxes, however denominated, including any interest, penalties or other additions to tax that may become payable in respect thereof, imposed by any Taxing Authority, which taxes shall include all income or profits taxes (including federal income taxes, state income taxes and any liability for the payment of any combined or consolidated tax), gross receipts taxes, sales taxes, use taxes, real property gains or transfer taxes, ad valorem taxes, property taxes, value-added taxes, franchise taxes, production taxes, severance taxes, windfall profit taxes, withholding taxes, payroll taxes, employment taxes, social security, excise taxes and other obligations of the same or similar nature to any of the foregoing, whether disputed or not.

“Tax Audit” has the meaning set forth in Section 6.3(e).

“Taxing Authority” means any Governmental Entity exercising any authority to impose, regulate, levy, assess or administer the imposition of any Tax.

“Tax Items” means all items of income, gain, loss, deduction and credit or other items.

“Tax Returns” shall mean any report, return, information statement or return, payee statement, notice, form, or other document or information required to be provided to any Governmental Entity, with respect to Taxes, including any return of an affiliated, combined or unitary group.

“Territory” means the District of Columbia, the states of Connecticut, Delaware, Maine, Maryland, New Hampshire, New Jersey, New York, and Rhode Island,  and the commonwealths of Massachusetts and Pennsylvania.

“Threshold” has the meaning set forth in Section 9.4(d).

“Tracking Systems” means the New England Power Pool Generation Information System, the PJM Environmental Information Services Generation Attributes Tracking System, any successor to either such system, and any other system that generates and/or accounts for

Renewable Energy Credits in any jurisdiction in which Seller or SENY has any Attribute Law Requirements.

“Transportation and Storage Agreements” means contracts for transportation and storage capacity with respect to Gas.  

ARTICLE II

PURCHASE AND SALE OF THE RETAIL BUSINESS

2.1

Agreement to Purchase and Sell the Acquired Assets; Assumption of Certain Liabilities.  Upon the terms and subject to the conditions of this Agreement, Seller agrees to sell, assign, transfer, convey and deliver, or cause to be sold, assigned, transferred, conveyed and delivered, to Buyer and Buyer agrees to purchase and acquire all of the Acquired Assets  and to assume the Assumed Liabilities on the Closing Date.

(a)

Acquired Assets.  The “Acquired Assets” consist of all of the rights, title and interests of Seller and its Affiliates in and to the following assets as existing on the Closing Date:

(i)

all Select Contracts to the extent contained in Schedules 1.1(a), 1.1(b), 1.1(c), 1.1(d), 1.1(e), 1.1(i), 1.1(j), 1.1(k) and 1.1(l);

(ii)

the SENY Shares;

(iii)

all claims of Seller against third parties relating to the Acquired Assets or Assumed Liabilities, whether known or unknown, fixed or contingent, but only to the extent relating to periods occurring on and after the Closing Date;

(iv)

the Seller Intellectual Property;

(v)

subject to and in accordance with Section 6.4, all rights of Seller relating to deposits and other performance assurance provided by Customers to Seller in connection with Retail Service Contracts (other than Administered Contracts) relating to periods occurring on and after the Closing Date; and

(vi)

subject to Section 6.5(b), the Acquired Records.  

(b)

Excluded Assets.  Notwithstanding anything in this Agreement to the contrary, Buyer shall not acquire and shall have no rights as a result of this Agreement, the Bill of Sale or the Assignment and Assumption Agreement, to any assets, rights, title, benefits, privileges or interests of Seller and its Affiliates other than the Acquired Assets (collectively, the “Excluded Assets”), which are not part of the purchase and sale contemplated hereunder. The Excluded Assets are excluded from the Acquired Assets and shall remain the property of Seller after the Closing. The Excluded Assets include the following:

(i)

all trade credits and all accounts payable, instruments and general intangibles attributable to the Select Contracts and existing or accrued with respect to any period of time prior to the Closing Date;

(ii)

all claims of Seller against third parties (including collections actions), whether known, unknown, fixed or contingent, (A) relating to the Acquired Assets or Assumed Liabilities, but only to the extent relating to periods occurring prior to the Closing Date, including the claims set forth on Schedule 2.1(b)(ii), and (B) relating to the other Excluded Assets and Excluded Liabilities;

(iii)

any proceeds, income or revenues, and any security or other deposits made or accrued under the Select Contracts or attributable to any of the other Excluded Assets; excluding, however, those deposits and other performance assurance provided by Customers under Retail Service Contracts and included in the Acquired Assets;

(iv)

the Administered Contracts;

(v)

the Rejected Contracts;

(vi)

the Retained Accounts Receivable; and

(vii)

the Retained Syracuse Assets.

(c)

Assumed Liabilities.  On the Closing Date, Buyer shall assume, satisfy and shall agree to pay, perform or discharge all Liabilities of Seller and its Affiliates related to, and/or arising from, the Acquired Assets (the “Assumed Liabilities”), including:

(i)

all Liabilities of Seller and its Affiliates under the Select Contracts that are assigned to Buyer at the Closing, accruing on and after the Closing Date;

(ii)

all Liabilities of Seller and its Affiliates under the Select Contracts that are Administered Contracts and are subsequently assigned to Buyer following the Closing, accruing on and after the Closing Date (in each case as such Select Contracts are assigned, except as otherwise provided in (vii), (viii) and (ix) below);

(iii)

all Liabilities of Seller and its Affiliates with respect to the Acquired Assets other than Select Contracts and the SENY Shares, accruing on and after the Closing Date;

(iv)

all Liabilities of Seller with respect to the SENY Shares;

(v)

any trade accounts payable relating to the Acquired Assets (including accounts payable under Sourcing Contracts assigned to Buyer) relating to periods on and after the Closing Date;

(vi)

all Liabilities of Seller and its Affiliates for Cancels/Rebills directly or indirectly issued with respect to any of the Acquired Assets (including the Partner Agreements and the SENY Contracts) to the extent not an Excluded Liability;

(vii)

subject to, and in accordance with, Section 6.13(d), all Liabilities of Seller and its Affiliates for AE/CC Commissions with respect to the Contracts for deliveries occurring on or after the Closing Date;

(viii)

all Liabilities of Seller and its Affiliates for Broker Fees under the Contracts to the extent not an Excluded Liability; and

(ix)

all Liabilities of Seller and its Affiliates for fees and/or other payments to Counterparties to the Program Agreements to the extent not an Excluded Liability.

(d)

Excluded Liabilities.  Buyer shall not assume, satisfy or perform the following Liabilities of Seller (the “Excluded Liabilities”):

(i)

except (A) as may otherwise be provided in the Administration Agreement, and (B) the other provisions of this Agreement with respect to Administered Contracts, any Liabilities of Seller to the extent such Liabilities are in respect of, or arise from, the obligations to be performed during the period prior to the Closing Date;

(ii)

any trade accounts payable related to the Acquired Assets (including accounts payable under Sourcing Contracts assigned to Buyer) and resulting from periods prior to the Closing Date;

(iii)

subject to, and in accordance with, Section 6.13(d), all Liabilities of Seller for that portion of AE/CC Commissions associated with respect to Retained Accounts Receivable or due to obligations after the Closing with respect to non-Hired Employees (as described in Section 6.13(d));

(iv)

all Liabilities of Seller for that portion of Broker Fees due and payable with respect to Retained Accounts Receivable;  

(v)

all Liabilities of Seller for that portion of fees and/or other payments to Counterparties to the Program Agreements with respect to (A) Retained Accounts Receivable to the extent that such fees and/or other payments are determined on such basis; or (B) periods before the Closing Date to the extent that such fees and/or other payments are determined based on time;

(vi)

all Liabilities of Seller or its Affiliates for Cancels/Rebills relative to periods prior to the Closing Date which Cancels/Rebills become known (A) within one year after the Closing Date with respect to (x) the New York Independent System Operator and (y) New England LDC seasonal reconciliations with respect to Gas, and (B) six (6) months after the Closing Date with respect to all other Cancels/Rebills;

(vii)

all Liabilities of SENY identified in Section 3.9 of the Seller’s Disclosure Schedule with respect to Taxes arising from or related to the period prior to Closing;

(viii)

all Liabilities of SENY with respect to periods prior to the Closing Date related to (A) the UCC-1 financing statement in the State of Delaware (Filing No. 42483552, filed on August 26, 2004) naming HSBC Bank USA, National Association as the secured party, and (B) the UCC-1 financing statement in the State of Delaware (Filing No. 52071307, filed on July 6, 2005) naming Orange and Rockland Utilities, Inc. as the secured party; and

 (vii)

any Liabilities of Seller to Buyer arising under or pursuant to this Agreement.

2.2

Purchase Price; Payment.  

(a)

Purchase Price.  The consideration for the Acquired Assets shall be (i) Forty Four Million Dollars ($44,000,000.00) (the “Purchase Price”) payable by Seller to Buyer, as may be subsequently adjusted pursuant to Section 2.2(c), and (ii) Buyer’s assumption of the Assumed Liabilities.  In the event that the Closing does not occur until  July 31, 2006, the Purchase Price shall be Forty One Million Dollars ($41,000,000.00), as may be subsequently adjusted pursuant to Section 2.2(c), and in any event the applicable Purchase Price shall be paid in accordance with Section 2.2(b) below.

(b)

Payment of Purchase Price.  Subject to the satisfaction or waiver of all conditions contained herein, Seller shall pay the Purchase Price to Buyer by wire transfer of immediately available United States funds in accordance with Buyer’s instructions as follows:  (i) an amount equal to thirty-three percent (33%) of the Purchase Price (rounded up to the nearest dollar) at the Closing; (ii) an amount equal to thirty-three percent (33%) of the Purchase Price (rounded up to the nearest dollar) no later than December 31, 2006; and, (iii) the remaining unpaid Purchase Price no later than December 31, 2007; provided that, if (x) Buyer repudiates this Agreement or the Administration Agreement; or (y) Buyer has fraudulently, willfully or through failure to comply with Applicable Laws committed a breach of a material obligation under this Agreement or under the Administration Agreement for which all cur e periods, if any, have expired, or (z) there is a preliminary adjudication in Seller’s favor with respect to an indemnification obligation of Buyer under either this Agreement or the Administration Agreement for which Seller has demanded payment but payment has not been made by Buyer, or (xx) there is a

Downgrade Event for which Buyer has not posted Alternative Credit Support to Seller, then Seller shall be entitled to retain a portion of the unpaid Purchase Price equal to Damages that Seller determines in good faith it may be entitled to as a result thereof, as collateral for Buyer’s obligations pending final resolution of any such matter, provided that any such withheld Purchase Price shall be paid to Buyer within five (5) Business Days after a cure, if any, has been effected.

(c)

Purchase Price Adjustment.  The Purchase Price shall be adjusted as follows:  

(i)   A calculation of the mark-to-market of the Retail Service Contracts, SENY Contracts for the retail sale of Power and Gas, Sourcing Contracts, Partner Agreements, Transportation and Storage Agreements, and Renewable Energy Contracts (including any termination or modification to such Contracts, but excluding Contracts that expire in accordance with their terms prior to the Closing Date) consummated prior to the Closing Date, but not included in the applicable Schedules as of the Agreement Date, for both Power and Gas will be performed in accordance with the methodologies set forth on Schedule 2.2(c)(i) – Natural Gas and Schedule 2.2(c)(i) – Electricity.  The results of the foregoing calculations shall be aggregated, producing a total mark-to-market adjustment to the Purchase Price ("MTM Adjustment").  If the MTM Adjustment is negative, then the Purchase Price paid by Seller shall be increased by such negative amount.  If the MTM Adjustment is positive, then the Purchase Price paid by Seller shall be reduced by such positive amount. Seller will provide Schedule Updates of such Contracts two (2) Business Days prior to Closing pursuant to Section 6.14.  From those Schedule Updates, Buyer will calculate and provide to Seller an initial MTM Adjustment (“Initial MTM Adjustment”) on the Business Day prior to Closing.  All values to be updated on Schedule 2.2(c)(i) – Natural Gas and Schedule 2.2(c)(i) – Electricity will be as of the close of business on the Business Day prior to the Closing.    The Initial MTM Adjustment will be paid or credited, as applicable, to the installment of the Purchase Price due at the Closing pursuant to Section 2.2(b)(i).  For any Retail Service Contracts, SENY Contracts for the retail sale of Power and Gas, Sourcing Contracts, Partner Agreements, Transportatio n and Storage Agreements, and Renewable Energy Contracts subject to the MTM Adjustment and not included in the Initial MTM Adjustment, Seller will provide Schedule Updates of all such Contracts not reflected on the prior update prior to the seventh (7^th) Business Day following Closing, pursuant to Section 6.14.  Buyer will calculate and provide to Seller a supplemental MTM Adjustment (“Supplemental MTM Adjustment”) one (1) Business Day following receipt of the Schedule Update.  In calculating the Supplemental MTM Adjustment, the applicable market prices used by Buyer shall be determined as of the close of business on the Business Day immediately preceding the calculation date.  The Purchase Price shall be adjusted in accordance with the foregoing based on such Supplemental MTM Adjustment and such payment or credit, as applicable, will be paid by Seller or Buyer within ten (10) days following receipt by Seller of the Supplemental MTM Adjustment.  During the Inte rim Period,

Seller agrees to use Commercially Reasonable Efforts to hedge with sourcing positions (A) open electric basis positions in the Retail Business existing as of March 6, 2006; and (B) transactions entered into or modified after March 6, 2006.  The Parties shall negotiate in good faith to resolve any differences in the calculations made by Buyer in accordance with this Section 2.2(c)(i).  In the event that the Parties are unable to resolve such differences, the undisputed portion of applicable adjustment shall be paid or credited, as applicable, in accordance herewith and the disputed portion shall be submitted to an independent calculation agent, as mutually selected by the Parties, who shall resolve the disputed calculations within twenty (20) days of submission to such calculation agent and in which case the adjustment as determined by such calculation agent shall be final and binding upon the Partie s.  The payment or credit, as applicable, shall include interest computed at the Prime Rate from the date that such payment or credit was due until the date of payment.

(ii)   To the extent that the Closing occurs on either June 30, 2006 or July 31, 2006, the Parties agree to determine, in good faith, the amount of an adjustment to the Purchase Price, proportionate to an allocation of Twenty Million Dollars ($20,000,000) for Gas Customers and Thirty Five Million Dollars ($35,000,000) for Power Customers, applicable to a change by more than five percent (5%) in the Base Annualized Volume for Gas or Power, as applicable.  To effect the foregoing, an increase of more than five percent (5%) shall result in a reduction in the Purchase Price paid by Seller based on such adjustment to such allocation, while a decrease of more than five percent (5%) shall result in an increase in the Purchase Price paid by Seller based on such adjustment to such allocation; provided that the Purchase Price adjustment calculation shall apply only to that portion of the change in Base Annualize d Volume (whether the change is an increase or a decrease) in excess of five percent (5%).   

(iii)  Any adjustments to the Purchase Price to be made in accordance with the provisions of Section 6.23(b) shall be netted as an adjustment in Seller’s favor against Seller’s payment to Buyer made in accordance with Section 2.2(b)(i) above.  Any adjustments to the Purchase Price to be made in accordance with the provisions of Section 6.6 and Section 6.19(f) shall be aggregated and netted as an adjustment in Seller’s favor against Seller’s payment to Buyer made in accordance with Section 2.2(b)(ii) above.  Any adjustment to the Purchase Price to be made in accordance with the provisions of  Section 6.3(d) shall be added to Seller’s payment to Buyer on the next applicable payment date provided in Section 2.2(b) following determination of such adjustment, and if the Purchase Price has been paid in full, as an independent payment from Seller to Buyer following such determina tion.

(d)

Additional Assurances. In the event that either Seller Guarantor or Buyer experiences a  Downgrade Event, then the other Party shall have the right to demand in writing that credit support be provided (“Alternative Credit Support”) in one of the following forms, to be elected by the Party providing the Alternative Credit Support: (A)

an irrevocable letter of credit in a form attached hereto as Schedule 2.2(d) that shall be renewed annually and remain effective as long as there are any outstanding obligations between the Parties; or (B) cash, in each case in an amount determined by the Party demanding Alternative Credit Support in a commercially reasonable manner.  Such Alternative Credit Support hereunder shall be furnished to the requesting Party within five (5) Business Days after demand.  The provision of Alternative Credit Support hereunder constitutes a “margin payment” under the United States Bankruptcy Code.  “Credit Rating” shall mean the rating assigned to the Buyer or Seller Guarantor or their respective Guarantor by Moody’s and S&P for the senior long term unsecured debt not supported by third party credit enhancement (other than by repayment of its debt).  Any de mand issued by a Party for Alternative Credit Support as a result of a Downgrade Event shall be deemed to have occurred prior to the effective date of such Downgrade Event.  In the event that the Credit Rating of Buyer or Seller Guarantor is restored to a level that does not constitute a Downgrade Event, then the Alternative Credit Support shall be returned within five (5) Business Days after the written request therefor (accompanied by reasonable evidence of such Credit Ratings).

(e)

Seller Additional Assurances.  On the Agreement Date, simultaneously with the execution and delivery of this Agreement, Seller shall deliver to Buyer the Seller Guaranty executed by the Seller Guarantor.

2.3

Provisions Regarding Administered Contracts.  

(a)

If (i) any of the Contracts is not assignable or transferable at the Closing by virtue of the provisions thereof, or under Applicable Law without the consent of a third party (including a Governmental Entity); (ii) the attempted assignment of any of the Contracts at the Closing would be ineffective or would adversely affect the rights and obligations of Seller under such Contract; (iii) any of the Contracts is not assignable or transferable at the Closing without novation, and/or (iv) any of the Contracts is assignable or transferable at the Closing, whether by virtue of the provisions thereof, under Applicable Law and/or in connection with a third party consent and/or novation, but such assignment or transfer would not result in the release of Seller and its Affiliates from all obligations thereunder (each of the foregoing being an “Administered Contract”), then this Agreement and the related in struments of transfer shall not constitute an assignment or transfer thereof or of any claim, right or benefit arising thereunder or resulting therefrom, unless or until any such release, consent and/or novation is obtained; provided, however, that Seller reserves the right, in its sole discretion (A) in connection with the Closing (or, after the Closing, pursuant to the Administration Agreement), to designate as an Acquired Asset any Contract that would otherwise qualify as an Administered Contract pursuant to clause (iv) of the definition thereof, and Buyer shall accept such assignment of such Contract, and (B) to terminate prior to Closing any Sponsorship Contract that Seller determines in its sole discretion would otherwise become an Administered Contract as of the Closing Date.  

(b)

At the Closing, the Parties shall enter into an Administration Agreement in the form of Exhibit D with respect to the Administered Contracts.

(c)

Each Administered Contract shall automatically and without further action of the Parties be assigned to Buyer and shall become an Acquired Asset upon Seller’s receipt of a fully executed Consent to Assignment and Release, or upon a novation of the Administered Contract under which all of the obligations of Seller and/or its Affiliates are terminated, and to the extent not already constituting Assumed Liabilities, all of  the Liabilities of Seller and its Affiliates related to, and/or arising from, such Administered Contract accruing on and after the Closing Date shall constitute Assumed Liabilities; accordingly, such Administered Contract shall be governed pursuant to the terms of this Agreement as if it had been transferred to Buyer as of the Closing Date.

2.4

Back-to-Back Agreement.

(a)

The Parties agree that if (i) a Consent to Assignment and Release, and/or (ii) any Seller Regulatory Approvals and/or Buyer Regulatory Approvals, as applicable, in each case with respect to a Sourcing Contract is not obtained before the Closing, the Parties shall, unless mutually agreed otherwise, enter into a Back-to-Back Agreement at the Closing in accordance with this Section 2.4 with respect to each such Sourcing Contract (collectively, the "Backed Transactions").  

(b)

The Parties agree that the general terms and conditions of any Back to Back Agreement entered into under this Section 2.4 shall be governed by the applicable Master Agreement for the transactions contemplated under the Sourcing Contract.  If the Parties do not have such a Master Agreement in place as of the Agreement Date, the Parties shall execute and deliver such Master Agreement simultaneously with the execution and delivery of the Back-to-Back Agreement.  It is the intent of the Parties that the confirmations detailing the commercial terms of any such Back to Back Agreement that is entered into by the Parties as contemplated herein shall: (i) fully transfer to Buyer all of Seller’s risks under the relevant Sourcing Contracts to the extent of the related Backed Transactions, including risks of changes in the market(s) for Power and Gas, future changes in the requirements, rules and procedures of System Operators, Pipeline Administrators, LDCs and Governmental Entities and changes to the interpretation and application of such requirements, rules and procedures, and defaults by or disagreements with the Counterparties concerning application and interpretation of such Backed Transactions related to periods after the Closing Date; provided, however, that Seller shall not transfer either the obligation or the right to post or receive, as applicable, margin or collateral under such Sourcing Contracts as such rights and obligations shall be retained by Seller under such Sourcing Contracts until such time as they are assigned; (ii) provide to Buyer the full beneficial interest of the revenues to or from Counterparties for Power and Gas products and performance of the contract obligations under the relevant Backed Transactions during the term of the Back-to-Back Agreement; and (iii) provide for an agency relationship in which Buyer acts as agent on behalf of Seller with respect to the Backed Transactions, w ith the same general agency authorizations and limitations and such other adjustments to applicable covenants, representations, warranties and remedies to reflect that agency relationship consistent with those set forth in the Administration Agreement.  The Parties agree that any Back-to-Back Agreement entered into pursuant to

this Agreement shall reflect this intent.  The Back-to-Back Agreement shall also provide that any ambiguity concerning any provision of the Back-to-Back Agreement relating to such risks or benefits or their interpretation or application under future circumstances, regardless of whether such future circumstances were contemplated by Parties, shall be interpreted in a way that is consistent with this intent.    Further, the Parties agree that indemnification and limitations on liability will be addressed in the Back-to-Back Agreement in a manner consistent with the provisions of this Agreement.  To the extent that any Master Agreement between the Parties needs to be amended to accomplish the intent of this Section 2.4, the Parties shall cooperate to make such amendments.

(c)

In the event that Seller and Buyer enter into the Back-to-Back Agreement, (i) Buyer shall, as Seller’s agent, use Commercially Reasonable Efforts to pursue (and Seller shall cooperate and provide assistance as reasonably requested by Buyer) obtaining the Consents to Assignment and Release, and if outstanding, Buyer Regulatory Approvals for each of the applicable Sourcing Contracts subject to a Back-to-Back Agreement; and (ii) Seller shall continue to pursue (and Buyer shall cooperate and provide assistance as reasonably requested by Seller) obtaining, if outstanding, the Seller Regulatory Approvals for each of the applicable Sourcing Contracts subject to a Back-to-Back Agreement.

(d)

At the time that the receipt of a Consent to Assignment and Release from the relevant Counterparty, and/or the receipt of Seller Regulatory Approval and/or Buyer Regulatory Approval, as applicable, with respect to any Sourcing Contract under the Back-to-Back Agreement, the Parties shall cooperate and, as promptly as practicable after receipt of such Consent to Assignment and Release and any such outstanding approvals, execute such documents or instruments necessary to effect the assignment of the relevant Sourcing Contract(s) in a manner consistent with Section 6.17.  In addition, with respect to those Sourcing Contracts subject to the Back-to-Back Agreement, the Back-to-Back Agreement shall specify that it terminates with respect to such Sourcing Contracts and related Backed Transactions upon such assignment to Buyer.

(e)

If the Parties have entered into a Back-to-Back Agreement, this Section 2.4 shall survive the Closing until the full performance of all obligations under the Back-to-Back Agreement and the later of (i) the full performance and termination of all of Backed Transactions in accordance with their respective terms and without liability to Seller and its Affiliates, or (ii) the assignment of all of the Backed Transactions in accordance with Section 2.4(d).

2.5

Allocation.  Seller shall prepare an allocation of the Purchase Price among the Acquired Assets in accordance with the fair market value of such Assets and deliver such allocation to the Buyer as soon as practicable after the Closing Date, but in any event no later than forty five (45) days following such date. Buyer shall timely and properly prepare, execute, file and deliver all such documents, forms and other information as Seller may reasonably request to prepare such allocation.  Buyer and Seller shall (i) agree upon this allocation and set it forth in a writing signed by all parties as soon as practicable after the Closing Date, but in any event no later than sixty (60) days following such date; (ii)  report (and cause their respective Affiliates to report) the United States tax consequences of the transactions contemplated herein,

and in particular, the information required under § 1060(b) of the Code, in a manner consistent with such allocation; (iii) not take any position inconsistent with the allocation set forth in the writing described above in preparing financial statements, returns, reports to shareholders or government authorities or otherwise; (iv) not take any tax position inconsistent with such allocation in connection with any refund claim, audit or returns, investigation, administrative proceeding, litigation, or other civil or judicial proceeding in respect to returns; and (v) each furnish the other with copies of all the Form 8594 (Asset Acquisition Statement Under Section 1060) filed with the IRS with regard to this transaction by such party or any Affiliate thereof, pursuant to §1060 of the Code, as a result of the consummation of the transactions contemplated hereby, within thirty (30) days of the filing of such forms with the United States.

ARTICLE III

REPRESENTATIONS AND WARRANTIES OF SELLER

Seller represents and warrants to Buyer as of the Agreement Date, except as otherwise set forth on Schedule 3 (the “Seller’s Disclosure Schedule”), as follows:

3.1

Existence and Compliance with Applicable Law.  Seller (a) is a corporation duly incorporated, validly existing and in good standing under the laws of its jurisdiction of incorporation; (b) is duly qualified to do business in those jurisdictions in which it is necessary for the conduct of the Retail Business, except for failures to so qualify which in the aggregate are not material to the Retail Business, and (c) has all requisite corporate power and authority and the legal right to own and operate its properties and to conduct the Retail Business as currently conducted.

3.2

Power and Authorization; Conflicts.  Subject to receipt of the Seller Regulatory Approvals, the execution, delivery and performance by Seller of this Agreement and, upon execution and delivery to Buyer and each of the Ancillary Documents to which Seller is a party, and the consummation by Seller of the transactions contemplated hereby and thereby (a) are within Seller’s corporate powers and authority, (b) have been duly authorized by all necessary corporate action on the part of Seller, and, (c) do not and will not, with the passing of time or the giving of notice or both, (i) contravene any of Seller’s or SENY’s organizational documents, (ii) result in a material violation of any Applicable Law, (iii) to Seller’s Knowledge require any consent, license, approval or authorization of, or other action by, or any notice or filing with, any Governmental Entity other than as set forth in Section 3.2 of the Seller’s Disclosure Schedule, or (iv) result in the material breach, default or termination of any agreement to which  Seller or SENY is a party or by which Seller or SENY or any of their respective property is bound, which breach, default or termination will materially and adversely affect Seller’s ability to consummate the transactions contemplated by this Agreement or the Ancillary Documents.

3.3

Enforceability.  This Agreement has been, and upon execution and delivery to Buyer and each of the Ancillary Documents to which Seller is a party will have been, duly executed and delivered by Seller.  This Agreement is, and upon execution and delivery to Buyer and each of the Ancillary Documents to which Seller is a party evidencing any obligation of

Seller will be, the legal, valid and binding obligation of Seller, enforceable against it in accordance with its terms, except where enforceability may be limited or otherwise affected by bankruptcy, insolvency or other similar laws affecting creditors’ rights generally and except where enforceability is subject to the application of equitable principles or remedies.

3.4

Contracts; Validity.  The Select Contracts are legal, valid and binding agreements of Seller, enforceable against Seller, in accordance with their terms and, to Seller’s Knowledge, each Select Contract is a legal, valid and binding agreement of each other party thereto, enforceable against such party in accordance with its terms, except in each case where enforceability may be limited or otherwise affected by Applicable Law, bankruptcy, insolvency or other similar laws affecting creditors’ rights generally and except where enforceability is subject to the application of equitable principles or remedies. Except as set forth in Section 3.4 of the Seller’s Disclosure Schedule:

(a)  Schedule 1.1(e) accurately sets forth in all material respects for each Retail Service Contract for the sale of Power, the Counterparty, start date (with deliveries starting before or during June 2006 indicated as June 1, 2006), end date, delivery location and price charged to Customers excluding applicable transaction Taxes and pass-through and other reimburseable costs (provided that the variable portion of pricing information for Retail Service Contracts listed as “COMPLEX” is set forth in the coordinate Retail Service Contracts, true and correct copies of which, including the pricing mechanisms thereof, are attached to Schedule1.1(e)).  Any actual usage for any such Retail Service Contracts included in Schedule 1.1(e) accurately represents the historical billed volumes invoiced by Seller to such Counterparty (indicated by an “A” in such Schedule). & nbsp;To Seller’s Knowledge, there are no material outstanding adjustments to such historical billed volumes set forth on Schedule 1.1(e) that have not been reflected in such data. Any historical usage for any such Retail Service Contracts included in Schedule 1.1(e) accurately represents data obtained from the applicable LDC (indicated by an “H” in such Schedule).

(b)  Schedule 1.1(e) accurately sets forth in all material respects for each Retail Service Contract for the sale of Gas, the Counterparty, start date (with deliveries starting before or during June 2006 indicated as June 1, 2006), end date and delivery location.  For each Retail Service Contract for Gas, Seller represents that the sum of the monthly price components set forth in Schedule 1.1(e), when applied to the related estimated contracted-for volumes as weighting factors, accurately sets forth, in all material respects, the monthly price charged to the applicable Customer (excluding applicable transaction Taxes and pass-through and other reimbursable costs); provided, however, that (A) the foregoing representation excludes pricing under Retail Service Contracts set forth in their entirety in Schedule1.1(e), in which case Schedule1.1(e) includes true and correct copies of such Retail Servic e Contracts, including the pricing mechanisms thereof; (B) as projections, such estimated contracted-for volumes are subject to the provisions of Section 9.6(c) such that Seller makes no representation and warranty to such estimated contracted-for volumes for any purpose whatsoever, other than their use as weighting factors in Seller's pricing calculations; and (C) pricing periods reflect production months.  Any actual usage for any such Retail Service Contracts included in Schedule 1.1(e) accurately represents the historical billed volumes invoiced by Seller to such Counterparty, except that actual usage for billing purposes reported by LDCs has been adjusted as follows: (i)

business meter level data was adjusted for losses to the citygate, using loss factors provided by the applicable LDC; and (ii) usage data has been converted into decatherms using industry standard british thermal units methodology to the extent that an LDC reported such usage in other units of measurement (including ccf). To Seller’s Knowledge, there are no material outstanding adjustments to such historical billed volumes set forth on Schedule 1.1(e) that have not been reflected in such data.

(c)   Schedule 1.1(i) accurately sets forth in all material respects for each Sourcing Contract of Seller (excluding any such agreements that are SENY Contracts, which agreements are included on Schedule 1.1(f) instead), the Counterparty, start date (with deliveries starting before or during June 2006 indicated as June 1, 2006), end date, delivery location, price, peak volume or off-peak volume (as applicable), block (as applicable) and contracted-for volumes.

(d)  Schedule 1.1(q) sets forth in all material respects a complete and accurate list of AE/CC Commissions for each Retail Service Contract listed on Schedule 1.1(e) and SENY Contract for the sale of retail Power and Gas listed on Schedule 1.1(f), in each case to the extent that such Contracts are subject to the Commission Plan.

(e)  Schedule 1.1(a) sets forth in all material respects a complete and accurate list of Broker Fees payable under the Billing and Marketing Representative Agreements with respect to each Retail Service Contract listed on Schedule 1.1(e) and SENY Contract for the sale of retail Power and Gas listed on Schedule 1.1(f), in each case to the extent that such Contracts are subject to Billing and Marketing Representative Agreements.

(f)   True and correct copies of the Other Select Agreements, including any material amendments thereto are included in Schedule 1.1(l).

(g)  Schedule 1.1(b) accurately sets forth in all material respects for the Partner Agreements with each of Agway Energy Services, Inc. and Strategic Power Management, Inc., the start date (with deliveries starting before or during June 2006 indicated as June 1, 2006), end date, delivery location, price and contracted for Power and/or Gas sales volumes (to the extent indicated as fixed on Schedule 1.1(b)).  True and correct copies of the Partner Agreement, including any amendments thereto, with IDT Energy, Inc. is included in Schedule 1.1(b); provided, however, that any Schedule Updates with respect to any transactions under the Partner Agreement with IDT Energy, Inc. shall also include representations as to the start date (with deliveries starting before or during June 2006 indicated as June 1, 2006), end date, delivery location, price and contracted for Power and/or Gas sales volumes (to the extent indi cated as fixed on any such Schedule Update).  There was no effective Partner Agreement with Robison Energy, LLC as of March 6, 2006 that will remain in effect after May 31, 2006.

(h)  True and correct copies of the Program Agreements of Seller (excluding any such agreements that are SENY Contracts, which agreements are included on Schedule 1.1(f) instead), including any material amendments thereto are included in Schedule 1.1(c).

(i)  True and correct copies of the Renewable Energy Contracts, including any material amendments thereto are included in Schedule 1.1(d).

(j)  True and correct copies of the Sponsorship Contracts, including any material amendments thereto are included in Schedule 1.1(j).

(k)  True and correct copies of the Transportation and Storage Agreements, including any material amendments thereto are included in Schedule 1.1(k).

The foregoing representations are made with respect to the Schedules referenced therein as of the Agreement Date with respect to the dates indicated thereon (if applicable).

3.5

Absence of Certain Events.  Except as set forth in Section 3.5 of the Seller’s Disclosure Schedule, as of April 11, 2006, neither Seller, nor to Seller’s Knowledge any Counterparty to a Select Contract, is in material default under any such Select Contract.  For purposes of the foregoing, a default under any Retail Service Contract shall not constitute a material default unless (a) the Customer to such Retail Service Contract has (i) repudiated such Retail Service Contract in violation of the terms thereof, or (ii) failed to pay amounts due under such Retail Service Contract for more than sixty (60) consecutive days after the contractual due date and the aggregate amount delinquent under such Retail Service Contract exceeds Ten Thousand Dollars ($10,000), or (b) the Seller has received written notice that such Customer has become Bankrupt.

3.6

Legal Proceedings.  Except as set forth in Section 3.6 of the Seller’s Disclosure Schedule, as of the Agreement Date, and except for collection actions in the ordinary course of business and matters of general applicability in and to the markets in which the Contracts and the Retail Business are governed and/or performed, there is no suit, action, claim, arbitration or proceeding pending, or to Seller’s Knowledge threatened, against Seller or SENY before any Governmental Entity directly concerning the Acquired Assets.  For purposes of the foregoing, a potential dispute under any Retail Service Contract or SENY Contract for the retail sale of Power or Gas shall not constitute a threatened claim or proceeding unless the aggregate amount in potential dispute under such Contract exceeds Ten Thousand Dollars ($10,000).

3.7

Certain Representations Regarding SENY and the SENY Shares.  

(a)

SENY (i) is a corporation duly incorporated, validly existing and in good standing under the laws of its jurisdiction of incorporation; (ii) is duly qualified to do business in the State of New York; and (iii) has all requisite corporate power and authority and the legal right to own and operate its properties and to conduct its business as currently conducted.

(b)

The SENY Contracts are legal, valid and binding agreements of SENY, enforceable against SENY, in accordance with their terms and, to Seller’s Knowledge, each SENY Contract is a legal, valid and binding agreement of each other party thereto, enforceable against such party in accordance with its terms, except in each case where enforceability may be limited or otherwise affected by Applicable Law, bankruptcy, insolvency or other similar laws affecting creditors’ rights generally and except where

enforceability is subject to the application of equitable principles or remedies. Except as set forth in Section 3.7(b) of the Seller’s Disclosure Schedule:

(i)  Schedule 1.1(f) accurately sets forth, in all material respects, for each SENY Contract for the retail sale of  Power, the Counterparty, start date (with deliveries starting before or during June 2006 indicated as June 1, 2006), end date, delivery location and price charged to Customers excluding applicable transaction Taxes and pass-through and other reimburseable costs.  Any actual usage for any such contracts included in Schedule 1.1(f) accurately represents the historical billed volumes invoiced by SENY or its Affiliates to such Counterparty (indicated by an “A” in such Schedule).  To Seller’s Knowledge, there are no material outstanding adjustments to such historical billed volumes set forth on Schedule 1.1(f) that have not been reflected in such data.  Any historical usage for any such contracts included in Schedu le 1.1(f) accurately represents data obtained from the applicable LDC (indicated by an “H” in such Schedule).  

(ii)  Schedule 1.1(f) accurately sets forth, in all material respects, for each SENY Contract for the retail sale of  Gas, the Counterparty, start date (with deliveries starting before or during June 2006 indicated as June 1, 2006), end date and delivery location.  For each SENY Contract for the retail sale of Gas, Seller represents that the sum of the monthly price components set forth in Schedule 1.1(f), when applied to the related estimated contracted-for volumes as weighting factors, accurately sets forth, in all material respects, the monthly price charged to the applicable Customer (excluding applicable transaction Taxes and pass-through and other reimbursable costs); provided, however, that (A) the foregoing representation excludes pricing under such SENY Contracts set forth in their entirety in Schedule1.1(f), in which case Schedule1.1(f) includes true and correct copies of such SENY Contracts, including the pricing mechanisms thereof; (B) as projections, such estimated contracted-for volumes are subject to the provisions of Section 9.6(c) such that Seller makes no representation and warranty to such estimated contracted-for volumes for any purpose whatsoever, other than their use as weighting factors in SENY's pricing calculations; and (C) pricing periods reflect production months.    Any actual usage for any such SENY Contracts included in Schedule 1.1(e) accurately represents the historical billed volumes invoiced by Seller to such Counterparty, except that (A) a zero under usage in Schedule 1.1(f) means that no historical billing information is available, and (B) actual usage for billing purposes reported by LDCs has been adjusted as follows: (1) business meter level data was adjusted for losses to the citygate, using loss factors provided by the applicable LDC; and (2) usage data has been converted into decatherms using industry standard british thermal units methodology to the extent that an LDC reported such usage in other units of measurement (including ccf).  To Seller’s Knowledge, there are no material outstanding adjustments to such historical billed volumes set forth on Schedule 1.1(f) that have not been reflected in such data.

(iii)  Schedule 1.1(f) accurately sets forth in all material respects for each Sourcing Contract of SENY (excluding any such agreements that are Select Contracts, which agreements are included on Schedule 1.1(i) instead), the Counterparty, start date (with deliveries starting before or during June 2006 indicated as June 1, 2006), end date,

delivery location, price, peak volume or off-peak volume (as applicable), block (as applicable) and contracted-for volumes.

(iv)  True and correct copies of all other SENY Contracts (other than those referenced in subsections (i),(ii) and (iii) above), including any material amendments thereto are set forth on Schedule 1.1(f), except (i) SENY Contracts with System Administrators, LDCs and certain Pipeline Administrators have been listed on Schedule 1.1(f), and Seller only represents as to such Contracts that to Seller’s Knowledge, as of the Agreement Date, such listing is complete in all material respects (provided, that Seller shall submit a Schedule Update to Buyer regarding such listing as of the Closing Date and without qualification as to Seller’s Knowledge), and (ii) the SENY Contract with Strategic Power Management, Inc. is excluded from the foregoing representation (and is instead included in the representation set forth in Section 3.4(g)).

The foregoing representations are made with respect to Schedule 1.1(f) as of the Agreement Date with respect to the dates indicated thereon (if applicable).

(c)

Section 3.7(c) of the Seller’s Disclosure Schedule contains a list of all material Permits, which are held by or applicable to SENY in the operation of its business in the State of New York.  

(d)

Except as set forth in Section 3.7(d) of the Seller’s Disclosure Schedule hereto, as of April 11, 2006, neither SENY, nor to Seller’s Knowledge any Counterparty to a SENY Contract, is in material default under any such SENY Contract.  For purposes of the foregoing, a default under any SENY Contract for the retail sale of Power or Gas shall not constitute a material default unless (i) the Customer to such SENY Contract has (A) repudiated such SENY Contract in violation of the terms thereof, or (B) the Customer to such SENY Contract has failed to pay amounts due under such SENY Contract for more than sixty (60) consecutive days after the contractual due date and the aggregate amount delinquent under such SENY Contract as of the Agreement Date exceeds Ten Thousand Dollars ($10,000), or (ii) the Seller or SENY has received written notice that such Customer has become Bankrupt.  

(e)

The authorized capital stock of SENY consists of 10,000 shares of Common Stock, par value $1.00 per share.  The SENY Shares are all of the shares of SENY issued and outstanding.  SENY does not have outstanding any stock or securities convertible into or exchangeable for any shares of its capital stock, nor does it have outstanding any rights, options or warrants to subscribe for or purchase its capital stock or any stock or securities convertible into or exchangeable for its capital stock, nor has it reserved any shares of capital stock for issuance upon exercise or conversion of any rights, options or warrants to subscribe for or to purchase its capital stock or any stock or securities convertible into or exchangeable for its capital stock.  All of the SENY Shares are owned beneficially and of record by Seller, free and clear of all Encumbrances, and the SENY shares are duly authorized, validly is sued, fully paid and nonassessable.

(f)

SENY has no employees and no employee benefit plans.

(g)

All material SENY Liabilities of any type have been included in Section 3.7(g) of the Disclosure Schedule.

3.8

Title to Assets.  Except as described with respect to the SENY Shares in Section 3.7(e), Seller owns the Acquired Assets free and clear of all Encumbrances, except Encumbrances that may arise in the ordinary course of business or are listed in Section 3.8 of the Seller’s Disclosure Schedule (“Permitted Encumbrances”).  

3.9

Tax Returns and Audits.  Except as set forth in Section 3.9 of the Seller’s Disclosure Schedule:

(a)

SENY has duly filed with the appropriate Taxing Authority all Tax Returns with respect to Taxes of SENY that it has been or is required to file on or prior to the Closing Date, other than such Tax Returns for which an extension has been timely requested.  

(b)

SENY is not delinquent in the payment of any Taxes nor has it requested any extension of time within which to file any Tax Return which return has not since been or will not be timely filed.  

(c)

No deficiency for any Taxes has been asserted or assessed against SENY or which has not been paid.  

(d)

No litigation regarding Taxes of SENY is currently pending, there are no outstanding agreements or waivers extending the statutory period of limitations applicable to any Tax Returns required to be filed by or with respect to SENY, and none of the Tax Returns are currently being audited or examined by any taxing authority.

3.10

Availability of Financing.  Seller will have as of the Closing sufficient funds available to consummate the transactions contemplated under this Agreement and to timely perform all of its obligations under this Agreement.  

ARTICLE IV

REPRESENTATIONS AND WARRANTIES OF BUYER

Buyer represents and warrants to Seller as of the Agreement Date, except as otherwise set forth on Schedule 4 (the “Buyer’s Disclosure Schedule”), as follows:

4.1

Existence and Compliance with Applicable Law.  Buyer (a) is a corporation, validly existing and in good standing under the laws of the jurisdiction of its formation; (b) is duly qualified to do business in those jurisdictions in which it is necessary for the conduct of its business and to fulfill its obligations following the Closing hereunder, except for failures to so qualify which in the aggregate are not material to Buyer or affect its obligations hereunder; and (c) has all requisite power and authority and the legal right to own and operate its properties and

to conduct its business as currently conducted and as required to be conducted in fulfillment of its obligations hereunder.

4.2

Power and Authorization; Conflicts.  Subject to receipt of the Buyer Regulatory Approvals, the execution, delivery and performance by Buyer of this Agreement, and, upon execution and delivery to Seller and each of the Ancillary Documents to which Buyer is a party, and the consummation by it of the transactions contemplated hereby and thereby (a) are within Buyer’s powers and authority, (b) have been duly authorized by all necessary corporate action on the part of Buyer, and (c) do not and will not, with the passing of time or the giving of notice or both, (i) contravene Buyer’s organizational documents, (ii) result in a material violation of any Applicable Law, (iii) to Buyer’s knowledge require any consent, license, approval or authorization of, or other action by, or any notice or filing with, any Governmental Entity or any other Person other than such as have already been obtained, or (iv) result in the breach, default or termination of any agreement to which Buyer is a party or by which Buyer or any of its property is bound, which breach, default or termination will materially and adversely affect Buyer’s ability to consummate the transactions contemplated by this Agreement or the Ancillary Documents to which Buyer is a party.

4.3

Enforceability.  This Agreement has been, and upon execution and delivery to Buyer and each of the Ancillary Documents to which Buyer is a party will have been, duly executed and delivered on behalf of Buyer.  This Agreement is, and upon execution and delivery to Seller and each of the Ancillary Documents to which Buyer is a party evidencing any obligation of Buyer will be, the legal, valid and binding obligation of Buyer, enforceable against it in accordance with its terms, except where enforceability may be limited or otherwise affected by bankruptcy, insolvency or other similar laws affecting creditors’ rights generally and except where enforceability is subject to the application of equitable principles or remedies.

4.4

Availability of Financing.  Buyer will have as of the Closing sufficient funds available to consummate the transactions contemplated under this Agreement and to timely perform all of its obligations under this Agreement.  

4.5

Experience of Buyer.  (a) Buyer has knowledge and experience in transactions of the type engaged in by Seller in the conduct of its Retail Business, in the retail electric power and natural gas industry generally, including the nature of full and firm requirements transactions and the responsibilities related to retail electric power and natural gas customers, and in the Retail Business of Seller as it relates to performing and administering the Contracts and that Buyer is therefore capable of evaluating the risks and merits of purchasing and accepting the assignment of the Acquired Assets, and assuming the Assumed Liabilities; and (b) Buyer has relied on its own independent investigation of, and judgment with respect to the Acquired Assets and the Assumed Liabilities and the advice of its own legal, tax, economic, and other advisors, and, except for the express repres entations set forth in this Agreement or in any Ancillary Document, Buyer has not relied on any information, comments, statements, or representations furnished by Seller or any representative of, or consultants or advisors engaged by, Seller or agent thereof in determining to enter into this Agreement.  

4.6

Performance of Contracts; Master Agreements.

(a)

Except as set forth in Section 4.6(a) of the Buyer’s Disclosure Schedule, Buyer possesses all necessary Permits for Buyer to perform its obligations under the Contracts and under the Administration Agreement, including (i) Permits to sell natural gas and electric power at retail in each jurisdiction in the Territory, and (ii) market based rate authority from FERC.  All of such Permits are in full force and effect, and except as set forth in Section 4.6(a) of the Buyer’s Disclosure Schedule, there is no action or proceeding pending, or to Buyer's knowledge threatened, against Buyer or any of its Affiliates before any Governmental Entity concerning any of such Permits.

(b)

Except as set forth in Section 4.6(b) of the Buyer’s Disclosure Schedule, Buyer has entered into all agreements, tariffs and/or other documents and maintains accounts as required by each LDC, LDC Pools, System Operator, and Pipeline Administrator as necessary for Buyer to perform its obligations under the Contracts and under the Administration Agreement, and Buyer is in full compliance with all Market Rules and Procedures, LDC Rules and natural gas pipeline tariffs applicable to the Contracts.  Except as set forth in Section 4.6(b) of the Buyer’s Disclosure Schedule, there is no action or proceeding pending, or to Buyer's knowledge threatened, against Buyer or any of its Affiliates alleging any noncompliance with any of such Market Rules and Procedures, LDC Rules and/or tariffs.

(c)

Section 4.6(c) of the Buyer’s Disclosure Schedule sets forth all Master Agreements between Buyer and any Counterparty to a Sourcing Contract.

(d)

Buyer has, or will have as of the Closing, a clearing broker able to process the transfer of the Smith Barney Trades to Buyer.

4.7

Securities Laws.  Buyer is acquiring the SENY Shares solely for the purpose of investment and not with a view to, or for sale in connection with, any distribution thereof in violation of the Securities Act.  Buyer acknowledges that the SENY Shares are not registered under the Securities Act or any state securities laws, and that such SENY Shares may not be transferred or sold except pursuant to the registration provisions of the Securities Act and any applicable such state securities laws or an exemption therefrom.  Buyer is knowledgeable, sophisticated and experienced in business and financial matters of the type contemplated by this Agreement and is able to bear the economic risks associated with its purchase of the SENY Shares.  Buyer is an “accredited investor” as defined in Regulation D promulgated pursuant to the Securities Act.

4.8

Legal Proceedings.  Except as set forth in Section 4.8 of the Buyer’s Disclosure Schedule, and except for matters of general applicability in and to the markets in which Buyer and its Affiliates conduct business, there is no suit, action, claim, arbitration or proceeding pending, or to Buyer's knowledge threatened, against Buyer or any of its Affiliates before any Governmental Entity that could be reasonably expected to adversely affect the ability of Buyer  to perform all of their respective obligations under this Agreement and each of the Ancillary Documents to which each is a party.

ARTICLE V

CLOSING; SETTLEMENT

5.1

Closing.  Subject to Sections 5.2, 5.3, 7.1 and 7.2, the Closing of the transactions contemplated by this Agreement (the “Closing”) will take place at 10:00 a.m. Eastern Prevailing Time, in the offices of Day, Berry & Howard, LLP in Hartford, Connecticut, on May 31, 2006, or at such other time or place or in such manner as may be agreed by the Parties and shall be effective at 10:00 a.m. on June 1, 2006 with respect to all Contracts relating to Gas and 12:01 a.m. on June 1, 2006 for all other transactions hereunder (collectively hereinafter referred to herein as the “Closing Date”); provided that, in the event that the Closing occurs on June 30, 2006, the Closing shall be effective as of 10:00 a.m. on July 1, 2006 with respect to all Contracts relating to Gas and 12:01 a.m. on July 1, 2006 for all other transactions hereunder; provided further that in the event that the Closing occurs o n July 31, 2006, the Closing shall be effective as of 10:00 a.m. on August 1, 2006 with respect to all Contracts relating to Gas and 12:01 a.m. on August 1, 2006 for all other transactions hereunder, and in the case of a Closing on either June 30, 2006 or July 31, 2006, the definition of Closing Date shall relate to such date.

5.2

Deliveries by Seller at Closing.  At the Closing, Seller will deliver the following to Buyer, each in form and substance reasonably satisfactory to Buyer:

(a)

A certificate executed on behalf of Seller by a duly authorized officer thereof, dated as of the Closing representing and certifying as to the matters set forth in Section 7.1(c) and Section 7.2(a), (b), and (d);

(b)

A certificate executed by an authorized officer of Seller certifying (i) the authority and true signature of the person or persons executing this Agreement, the Administration Agreement and the Ancillary Documents on behalf of Seller, and (ii) the authority of Seller (including resolutions adopted by Seller) to enter into and perform this Agreement, the Administration Agreement and the Ancillary Documents;

(c)

The Bill of Sale;

(d)

The Assignment and Assumption Agreement;

(e)

The SENY Shares, endorsed in blank for transfer to Buyer, without legends (other than customary provisions regarding the absence of registration);

(f)

Resignations of the SENY directors and officers;

(g)

The Administration Agreement;

(h)

Schedule Updates contemplated in Section 6.14;

(i)

All of the Renewable Energy Credits in Seller’s account in each Tracking System, subject to Buyer’s obligations under Section 6.20;

(j)

The Back-to-Back Agreement, if applicable; and

(k)

The portion of the Purchase Price payable to Buyer at Closing.

5.3

Deliveries by Buyer at Closing.  At the Closing, Buyer will deliver the following to Seller, each in form and substance reasonably satisfactory to Seller:

(a)

A certificate executed by a duly authorized representative of Buyer, dated as of the Closing representing and certifying as to the matters set forth in Sections 7.1(a), (b), and (d) and Section 7.2(c);

(b)

A certificate executed by an authorized officer of Buyer certifying (i) the authority and true signature of the person or persons executing this Agreement, the Administration Agreement and the Ancillary Documents on behalf of Buyer, and (ii) the authority of Buyer to enter into and perform this Agreement, the Administration Agreement and the Ancillary Documents;

(c)

he Bill of Sale;

(d)

The Assignment and Assumption Agreement;

(e)

To the extent obtained by the Closing in accordance with Section 6.6, written evidence, satisfactory to Seller, of the replacement of the NU Guarantees with respect to Select Contracts assigned to Buyer at the Closing and any SENY Contracts;

(f)

The Administration Agreement;

(g)

The Back-to-Back Agreement, if applicable; and

(h)

A complete list of Hired Employees certified by an authorized representative of Buyer.

ARTICLE VI

COVENANTS OF THE PARTIES

6.1

Seller’s Conduct of Retail Business Prior to Closing.

(a)

From the Agreement Date until the Closing Date (unless Buyer shall otherwise consent in writing or unless otherwise expressly permitted hereunder) Seller shall conduct the Retail Business in the ordinary course.  In doing so, Seller and SENY shall have the right to renew or extend existing Contracts according to their terms and to engage in new business, including entering into new Contracts in accordance with current policies, procedures, practices and controls.  

(b)

Buyer shall have the right, by written notice given to Seller within five (5) Business Days after the Agreement Date, to reject any Contracts (“Rejected Contracts”) of Customers identified in Section 3.5 or 3.7(d) of the Seller’s Disclosure Schedule; provided that (i) Buyer shall not have the right to reject any Contracts with Governmental Entities; and (ii) if a Customer pays amounts to Seller as a result of and/or in connection with the actions taken by Seller to terminate service pursuant to such Contract and such payment results in such Customer no longer being in material default under such Contract for nonpayment pursuant to the terms of Section 3.5 or 3.7(d) (as the case may be), then Buyer’s right of rejection shall be automatically rescinded and such previously Rejected Contract shall be an Acquired Asset or Administered Contract, as applicable.  Buyer acknowledges that the rejection of o ne or more Contracts in accordance with the foregoing shall not affect in any manner any other Contracts with the affected Customer that are not Rejected Contracts.

(c)

Schedule 6.1(c) sets forth as of April 11, 2006, Customers (other than Governmental Entities) that are not listed in Sections 3.5 or 3.7(d) of the Seller’s Disclosure Schedule and have failed to pay amounts due for more than thirty (30) consecutive days after the contractual due date and the aggregate amount of such delinquency exceeds Ten Thousand Dollars ($10,000).  Within ten (10) days after the Agreement Date, Buyer shall provide written notice to Seller identifying any of the Customers whose Contract Buyer would exercise the right to reject under this Section 6.1(c) if, as a result of such Customer’s continued failure, Seller updated Section 3.5 or 3.7(d) of the Seller’s Disclosure Schedule to include such Customer, in which case Seller shall have the right to terminate or cause the termination of the relevant Contracts; provided that the foregoing shall not create any right of Buyer to reject any such Contract that Seller has not terminated if such Customer ultimately does not qualify for inclusion by Seller in an update to Section 3.5 or 3.7(d) of the Seller’s Disclosure Schedule.  

(d)

Buyer’s failure to provide the notices of rejection set forth in (b) and (c) above shall result in the Buyer’s irrevocable waiver of its right to reject the applicable Contract.

(e)

Seller shall have the right to terminate or cause the termination of any Contracts prior to the Closing Date if the Counterparty (i) has become Bankrupt, (ii) has failed to pay amounts due under such Contract for more than sixty (60) days after the contractual due date, or (iii) is in default of a material obligation under such Contract; provided that Seller shall notify Buyer of such intent to terminate, and if Buyer objects to such termination within three (3) days after receipt of Seller’s notice, the Parties shall negotiate in good faith an arrangement to appropriately share the credit risk associated with such Contract in lieu of termination.  In the event that Seller is unable to terminate a Rejected Contract prior to the Closing Date, Buyer agrees to perform such Rejected Contract as an Administered Contract under the Administration Agreement until such Rejected Contract is terminated; provided that if such Rejected Co ntract is terminated, then all payments received on account of such Rejected Contract (including any deposits or other Performance Assurance) shall be applied in priority to the accounts receivable associated with the period of service furnished by Buyer; provided, further, that if any balance remains due with respect to Buyer’s account receivable for more than thirty (30) days after the contractual due date, Seller shall pay the amount of such shortfall to Buyer, in which case Seller shall be entitled to such account receivable.

(f)

Notwithstanding anything to the contrary herein, Buyer shall not have the right to reject any Contract of Customers identified in an update to Section 3.5 or 3.7(d) of the Seller’s Disclosure Schedule, unless such update resulted from a failure of Seller to initially disclose such Customer in Section 3.5 or 3.7(d) of the Seller’s Disclosure Schedule or Schedule 6.1(c), or Buyer has indicated its intent to reject such Contract in accordance with Section 6.1(c).  

(g)

Any changes in the composition of the Contracts between the Agreement Date and the Closing Date shall be reflected in the Schedules to this Agreement delivered at the Closing pursuant to Section 5.2(h), and such change shall not constitute a breach of this Agreement.

6.2

Fees and Expenses.  Except as otherwise expressly provided in this Agreement, all fees and expenses, including fees and expenses of counsel, incurred in connection with this Agreement and the Administration Agreement, if applicable, and the transactions contemplated by this Agreement and the Administration Agreement, including fees and expenses incurred by the Parties in connection with the Buyer Regulatory Approvals and Seller Regulatory Approvals, shall be paid by the Party incurring such fee or expense.

6.3

Taxes.

(a)

All transfer, documentary, sales, use, value added, recording, registration, filing and other such Taxes and fees (including any penalties and interest), whether levied on Buyer, Seller or SENY, or their respective Affiliates, incurred in connection with the consummation of the transactions contemplated by this Agreement and the transfer of the Acquired Assets (other than Taxes on income or gain recognized by Seller on such transfer) shall be paid by Buyer, and Buyer shall, at its own expense, file all necessary tax returns, forms and documentation with respect to all such taxes and fees.  Seller shall cooperate with the filing of such Tax Returns.

(b)

All Taxes, including the rights to the refund of any such Taxes, arising under, or relating to, the Acquired Assets for the period prior to the Closing Date shall be the sole and exclusive responsibility and right of Seller.

(c)

All Taxes arising under or relating to the Acquired Assets for the period on or after the Closing Date and the Administered Contracts subject to the Administration Agreement on or after the Closing Date, shall be the sole and exclusive responsibility of Buyer.  To the extent that Buyer cannot pay such Taxes directly due to Applicable Law, Buyer shall provide Seller with a complete and accurate Tax Return and the full amount due with respect such Taxes at least thirty (30) days before the tax filing and due date, and Seller shall file such Tax Return and pay such Taxes when due; provided that if Buyer fails to comply with the foregoing, Seller reserves the right, without prejudice to Seller's right and remedies against Buyer, to prepare and make such filing and pay such Taxes in compliance with Applicable Law, and Buyer shall reimburse Seller for the preparation costs incurred by Seller and any such Tax payme nts within ten (10) Business Days after Seller's request for reimbursement, together with interest at that rate applicable to delinquent payments of such Tax from the date that Seller paid such Tax.

(d)

Seller shall prepare and timely file or shall cause to be prepared and timely filed and shall remit or cause to be remitted any Taxes due in respect of the following Tax Returns with respect to the Acquired Assets (including ownership of SENY): (i) all Tax Returns for any taxable period ending prior to the Closing Date; and (ii) all other Tax Returns required to be filed (taking into account extensions) prior to the Closing Date.  Buyer shall prepare and timely file or shall cause to be prepared and timely filed all Tax Returns that are required to be filed by or with respect to the Acquired Assets or SENY for taxable years or periods beginning on and ending after the Closing Date.  Buyer shall remit or cause to be remitted any Taxes due in respect of such Tax Returns.  If Buyer is required to file any Tax Return for a taxable period beginning before and ending after the Closing Date, Buyer shall c ause such Tax Return to be filed and shall be responsible for the payment of any Tax for such period.  However, Seller shall pay to Buyer, as an adjustment to the Purchase Price, the amount by which the Tax attributable to the period prior to the Closing Date exceeds the amount of such Tax paid (including payments of estimated Tax) prior to the Closing Date.  The Tax attributable to the period prior to the Closing Date shall be determined using the Tax accounting methods and Tax elections used by Seller or SENY before the Closing Date.  Buyer shall compute the amount of the Tax attributable to the period prior to the Closing Date and shall notify Seller of such amount in writing no later than forty-five (45) days prior to filing the Tax Return.  Within twenty (20) days after the date of such notification, Seller shall pay to Buyer or Buyer shall pay to Seller, as appropriate, the difference between (i) the amount of Tax determined by Buyer as attributable to the portion of the period prio r to the Closing Date, and (ii) the amount of the Tax for the taxable period paid (including payments of estimated Tax) prior to the Closing Date by Seller, unless within fifteen (15) days after such date, Seller notifies Buyer in writing that Seller disagrees with the computation of any such amount.  In that case, the Parties shall proceed in good faith to determine the correct amount, and Seller’s payment to Buyer, or Buyer’s payment to Seller, shall be due the later of (i) the time specified in the immediately preceding sentence and (ii) ten (10) days after Seller and Buyer agree to the amount payable.  If Seller is permitted but not required under applicable state or local Tax laws to treat the day prior to the Closing Date as the last day of a taxable period, the parties shall treat such day as the last day of a taxable period.  The Parties shall treat SENY as if it ceased to be part of the affiliated group of corporations of which Seller is a member within the meaning of Sectio n 1504 of the IRC, and any comparable or similar provision of state, local or foreign laws or regulations, as of the close of business on the day prior to the Closing Date.

(e)

The Parties shall cooperate and share all required information on a timely basis in order to timely file all Tax Returns, reports, returns, schedules and any other documents required to be filed with respect to Taxes and all claims for refunds of Taxes and for the preparation of any audit, and for the prosecution or defense of any claim or proceeding relating to any proposed adjustment.  Each Party shall retain or cause to be retained all Tax Returns, and books and records pertinent to the Retail Business until the applicable period for assessment under Applicable Law (giving effect to any and all extensions or waivers) has expired, and to abide by or cause the abidance with all record retention agreements entered into with any Governmental Entity.  After the Closing, each

Party will give the other reasonable notice prior to discarding or destroying any such Tax Returns, and books and records relating to Tax matters, in which case each Party will allow the other upon request to take possession of such Tax Returns, and books and records at the requesting Party’s expense.  The Parties shall cooperate with each other in the conduct of any audit or other proceedings involving the Acquired Assets for any Tax purpose; provided that Seller shall have the sole right to represent SENY’s interests in any audit or examination by any Governmental Entity (“Tax Audit”) relating to taxable periods ending prior to the Closing and to employ counsel of its choice at Seller's expense.  In the case of a period that begins before and ends after Closing, Seller shall be entitled to participate at Seller's expense in any Tax Audit relating in any part to Taxes a ttributable to the portion of such period deemed to end on or before the Closing Date, but Buyer shall control the Tax Audit.  None of Buyer, any of its Affiliates or SENY may settle or otherwise dispose of any Tax Audit for which Seller may have a liability under this Agreement, or which may result in an increase in Seller’s liability under this Agreement, in each case without the prior written consent of Seller.

(f)

Any payment by Buyer or Seller under this Section 6.3 will be deemed an adjustment to the Purchase Price.

(g)

Notwithstanding any other provision of this Agreement, the covenants and obligations set forth in this Section 6.3 shall survive until, and any claim for indemnification with respect thereto must be made prior to, the expiration of the applicable statute of limitations with respect to the underlying Tax claim (including any valid extensions).

(h)

Buyer agrees to make the election described in Reg. Section 1.1502-21T(b)(3)(ii)(B) to relinquish, with respect to all consolidated net operating losses attributable to the Company, the portion of the carryback period for which SENY was a member of the consolidated group which included Seller.

(i)

Seller shall cause the common parent of the affiliated group of corporations filing a consolidated federal income Tax Return which includes SENY (the “Seller Group”), to be included in the consolidated federal income Tax Returns (and the state income Tax Returns of any state that permits consolidated, combined or unitary income Tax Returns, for which an election has been made if any) of Seller Group for all periods ending on or before or which include the Closing Date, all Tax Items of SENY which are required to be included therein, shall file timely all such Tax Returns with the appropriate taxing authorities and shall pay timely all taxes due with respect to the periods covered by such Tax Returns.

(j)

Any Tax Return to be prepared pursuant to the provision of this Section 6.3 shall be prepared in a manner consistent with practices followed in prior years with respect to similar Tax Returns, except for changes required by changes in Applicable Law.

(k)

Effective as of the Closing Date, any tax indemnity, sharing, allocation or similar agreement or arrangement that may be in effect prior to the Closing Date between

or among the Seller Guarantor and SENY, shall be extinguished in full, and any Liabilities or rights existing under any such agreement or arrangement shall cease to exist and shall no longer be enforceable.

(l)

(i)  Seller and each member of Seller Group shall grant to Buyer (or its designees) access at all reasonable times to all of the information, books and records relating to SENY within the possession of Seller or any member of Seller Group (including work papers and correspondence with taxing authorities), and shall afford Buyer (or its designees) the right (at Buyer’s expense) to take extracts therefrom and to make copies thereof, to the extent reasonably necessary to permit Buyer (or its designees) to prepare Tax Returns, to conduct negotiations with Tax authorities, and to implement the provisions of, or to investigate or defend any claims between the Parties arising under, this Section 6.3. (ii) Buyer shall grant or cause SENY to grant to Seller (or its designees) access at all reasonable times to all of the information, books and records relating to SENY within the possession of Buyer or SENY (inclu ding work papers and correspondence with taxing authorities), and shall afford Seller (or its designees) the right (at Seller’s expense) to take extracts therefrom and to make copies thereof, to the extent reasonably necessary to permit Seller (or its designees) to prepare Tax Returns, to conduct negotiations with Tax authorities, and to implement the provisions of, or to investigate or defend any claims between the Parties arising under, this Section 6.3. (iii) Each of the parties hereto will preserve and retain all schedules, work papers and other documents relating to any Tax Returns of or with respect to SENY or to any claims, audits or other proceedings affecting SENY until the expiration of the statute of limitations (including extensions) applicable to the taxable period to which such documents relate or until the final determination of any controversy with respect to such taxable period, and until the final determination of any payments that may be required with respect to such taxable period un der this Agreement.

(m)

If Buyer notifies Seller in writing no fewer than two (2) Business Days prior to the Closing that Buyer is irrevocably electing to make an election under Section 338(g) and 338(h)(10) of the Code and any similar state law elections in all applicable states (the "Elections"), the Seller shall cause the common parent of the "selling group" of SENY (as defined in Treasury Reg. Section 1.338-2(c)(16)) to join Buyer in making timely Elections with respect to the sale and purchase of the SENY Stock pursuant to this Agreement, and each Party shall provide to the other all necessary information to permit such Elections to be made.  The Seller and the Buyer shall, as promptly as practicable following the Closing Date, take or cause to be taken all actions necessary and appropriate (including filing such forms, returns, schedules, and other document as may be required) to effect and preserve timely the Elections.  In connection with such Elections, Seller and the Buyer shall act together in good faith to (i) determine and agree upon the “aggregate deemed sale price” for the assets of SENY (within the meaning of Treasury Regulation Section 1.338-4T) and the "adjusted grossed-up basis" for the assets of SENY (within the meaning of Treasury Regulation Section 1.338-5) and (ii) agree upon appropriate allocations (the "Allocations") of the “aggregate deemed sale price” and "adjusted grossed-up basis" among the assets of SENY in accordance with Section 338(b)(5) of the Code and the Treasury Regulations promulgated thereunder.  The Seller shall calculate gain or loss, if any, resulting from the Elections in a manner consistent with the

Allocations in any Tax return or otherwise and Buyer shall allocate the "adjusted grossed-up basis" among the assets of SENY in a manner consistent with the Allocations and shall not take any position inconsistent with the Allocations in any Tax return or otherwise.  If the Parties are unable to agree upon the calculations of either (i) “aggregate deemed sale price” for the assets of SENY, (ii) the "adjusted grossed-up basis” for the assets of SENY or (iii) the Allocations, then, independent tax counsel or a nationally recognized public accounting firm, in each case mutually acceptable to Seller and Buyer, shall be engaged to decide the dispute, the cost of such counsel or accounting firm to be shared equally by Seller and Buyer.

6.4

Collection of Receivables; Account Billings Following Closing.

(a)

Seller shall be entitled to receive all amounts due and payable for products and services provided or supplied and which will become payable under the Retail Service Contracts and the SENY Contracts for the retail sale of Power or Gas for or relating to the period prior to the Closing Date.  Buyer shall be entitled to receive and collect all amounts due and payable under such Contracts for and relating to the period on and after the Closing Date.  The Parties shall coordinate and develop a methodology and protocol for effecting such allocation.

(b)

After the Closing Date, Seller shall bill and collect receivables under the Retail Service Contracts and the SENY Contracts for the retail sale of Power or Gas for products and services provided or supplied during the billing cycle in effect for each Customer as of the Closing Date  (the “Receivables Proration Period”).  To effect the entitlements set forth in Section 6.4(a), receivables with respect to the Receivables Proration Period shall be prorated between Seller and Buyer using the average billing charge per day over the billing cycle such that Seller shall have the benefit of that portion of any such receivable related to products and services provided or supplied prior to the Closing Date, and Buyer shall have the benefit of that portion of any such receivable related to products and services provided or supplied on and after the Closing Date.  After such invoicing with res pect to the Receivables Proration Period, Buyer shall be responsible for any and all billings and collections with respect to the Acquired Assets. Where permitted by the applicable LDC, Buyer will have the option, at its own expense, to cause such LDC to perform a meter read as of the Closing Date, in which case such actual usage data will be used for allocation for the Receivables Proration Period in lieu of the proration otherwise provided hereunder.

(c)

In order to effect Section 6.4(a) above, Buyer shall permit and cause each payment received from a Customer to be applied in the following order: first, against the invoice, if any, indicated with the payment; second, if the amount of the payment equals the amount reflected on any outstanding invoice, against such invoice; third, if a payment cannot be allocated by following the first two steps, then Buyer and Seller shall cooperate to contact the Customer to determine the Customer’s payment intent; fourth, for receipts during the sixty (60) days after the Closing Date, if the Customer’s payment intent cannot be determined, then Seller shall be entitled to such payment (to the extent of any Retained Accounts Receivables with respect to such Customer only, with any remaining amount to

be retained by Buyer); fifth, for receipts more than sixty (60) days after the Closing Date and up to one hundred and twenty (120) days after the Closing Date, if the Customer’s payment intent cannot be determined, then such payment shall be divided equally between Buyer and Seller, provided that if such payment would satisfy entirely the Retained Accounts Receivable or the accounts receivable due Buyer with respect to such Customer, any balance remaining shall be paid to the other Party to the extent of its remaining receivables, and any remaining amount thereafter (if any) will be at Buyer’s election either applied to Customer’s account with Buyer or returned to the Customer; and sixth, for receipts more than one hundred and twenty (120) days after the Closing Date, if the Customer’s payment intent cannot be determined, then Buyer shall be entitled to such payment to the extent of any outstanding receivables of Buyer with respect to such Customer only, with any remaining amount to be paid to Seller, provided that if such payment would satisfy entirely the Retained Accounts Receivable or the accounts receivable due Buyer with respect to such Customer, any balance remaining shall be paid to the other Party to the extent of its remaining receivables, and any remaining amount thereafter (if any) will be at Buyer’s election either applied to Customer’s account with Buyer or returned to the Customer.  Seller shall retain all prepayments, deposits, letters of credit and other performance assurance supplied by each Customer of Seller or SENY and any Counterparty to a Partner Agreement, for a period of sixty (60) days after the Closing, and thereafter such prepayments, deposits, letters of credit and other performance assurance shall be held by Buyer and become Buyer’s responsibility; provided that, neither Seller nor Buyer may draw upon more than fifty percent (50%) of any suc h prepayments, deposits, letters of credit or other performance assurance (as constituted as of the Closing Date) unless the underlying Contract has been terminated and the accounts receivable due the other Party have been paid in full.

(d)

Buyer and Seller shall cooperate regarding any Cancels/Rebills received by either of them with respect to the Contracts following the Closing.  The Parties shall prepare a joint reconciliation that net settles any Cancels/Rebills, in the aggregate in excess of Fifty Thousand Dollars ($50,000), over the term of the Reconciliation Period paid or received by a Party not responsible for such Cancels/Rebills hereunder at intervals of thirty (30), sixty (60), one hundred eighty (180) days and one year in each case, following the Closing Date (such periods collectively, the “Reconciliation Period”).

(e)

Seller reserves the right to employ any commercially reasonable means in its sole discretion in the collection of delinquent Retained Accounts Receivable by it.  In the event that a particular Customer is delinquent in payments to both Seller and Buyer, Seller and Buyer agree to coordinate their collection efforts.

(f)

In connection with the implementation of this Section 6.4, the Parties shall develop a methodology and protocol for effecting the allocation hereunder of responsibility for AE/CC Commission, Broker Fees and fees and/or other payments under Program Agreements, and each Party shall promptly furnish after request from the other Party reasonable documentation supporting such allocation.  Without limiting the generality of the foregoing, Seller shall have the right, with respect to that portion of Customer payments on invoices issued for the Receivables Proration Period that otherwise

would be due to Buyer pursuant to Section 6.4(b), to (i) retain therefrom amounts necessary to reimburse AE/CC Commissions and fees and/or other payments under Program Agreements paid by Seller, but attributable to the period allocated to Buyer pursuant to Section 6.4(b) and subject to Section 6.13(d); and (ii) deduct therefrom for payments to the appropriate Counterparties that portion of Broker Fees and fees and/or other payments under Program Agreements relating to that portion of the Receivables Proration Period allocated to Buyer pursuant to Section 6.4(b).  

(g)

If the Hired Employees include a material portion (whether by number, seniority, function, experience or otherwise) of Seller's billing and collection unit, Seller, by written notice given to Buyer after the Closing, may request that Buyer provide, at no cost to Seller, all or any portion of the billing and collection services contemplated to be performed by Seller under this Section 6.4.  In any such event, the Parties shall reasonably coordinate the provision of such services by Buyer.

(h)

Administered Contracts subject to the Administration Agreement shall be treated in a manner consistent herewith.

(i)

Seller reserves the right to use copies of the Seller Intellectual Property in connection with billing and collection of Retained Accounts Receivable by Seller.

(j)

This Section 6.4 shall survive the Closing for the period necessary to give full effect to its terms.

6.5

Access to Information.  

(a)

After the Agreement Date and until the Closing, at Buyer’s request and upon reasonable prior notice to Seller, Buyer shall have reasonable access (at Buyer’s sole cost and expense) during Seller’s normal business hours to, and Seller shall cause its officers and employees to furnish to Buyer, the files of Seller relating to the Retail Business, not constituting Proprietary Information of Seller or its Affiliates.  Buyer acknowledges that following the Agreement Date, Seller may have limited resources to assist Buyer in identifying and obtaining such additional information.  Seller reserves the right to establish procedures for such access (including prohibitions on copying) in a manner reasonably necessary to comply with confidentiality provisions or other limitations on disclosure that are binding on Seller and/or its Affiliates.

(b)

On and after the Closing Date, Buyer shall have access to copies of (i) all Contracts (including amendments thereto) in Seller’s possession (including SENY Contracts); and (ii) credit files, customer files, other non-proprietary or confidential corporate records related to the Acquired Assets, and personnel records with respect to Hired Employees subject to obtaining any consents and releases with respect thereto or as otherwise required under Applicable Law (“Acquired Records”); provided, that Seller is permitted to retain SENY documents that are not related to the Retail Business, and such documents are not Acquired Records.  Within thirty (30) days after the Closing Date, Seller shall deliver to Buyer all original copies of Contracts in its possession, as

well as the Contracts or Acquired Records.  Buyer agrees that Seller may retain copies of any Acquired Records it reasonably needs to fulfill its obligations under this Agreement or the Administration Agreement, or related to its obligations under Applicable Law or the winding-down of its business.

(c)

For a period equal to the later of (i) two (2) years following the Closing Date, and (ii) the expiration or termination of the Administration Agreement, Buyer grants to Seller reasonable access to the books and records of SENY to the extent that such access may be reasonably required by Seller, including access required in order for Seller to meet its obligations regarding access to information under Section 5.2(c) of that certain Stock Purchase Agreement, dated as of September 28, 2001, between Seller and Niagara Mohawk Holdings, Inc.

6.6

Consents; Performance Guarantees.  

(a)

Prior to Closing, Seller shall notify in writing the Counterparties of the sale of the Retail Business.  In connection with and/or shortly after such written notice, Seller shall use Commercially Reasonable Efforts to obtain any required consents to the assignment and/or novations of the Contracts as determined by Seller, in such form (including a Consent to Assignment and Release) and by such means as mutually agreed by Buyer and Seller.  Buyer shall use Commercially Reasonable Efforts to assist Seller and its Affiliates in obtaining any and/or all of such consents or novations; provided that after the Agreement Date but before the Closing Date, Buyer shall not directly or indirectly contact and/or solicit, including through press releases, advertising, direct mail and/or other communications, any Counterparties without Seller's prior written consent.

(b)

Without limiting the generality of subsection (a) above, and subject to subsection (c) below, within five (5) Business Days after the request of Seller or following the Closing with respect to Contracts where consents or novations have been obtained, the Buyer shall (a) replace all surety bonds issued to Counterparties as set forth in Schedule 1.1(n) to be effective as of the Closing Date, or (b) use Commercially Reasonable Efforts to provide reasonable credit assurance, performance assurance and/or other undertakings in connection with each Contract, such that neither Seller nor any of its Affiliates, including NU, have any obligations with respect to any such guarantees or undertakings after the Closing Date with respect to performance under such Contracts after the Closing Date.  

(c)

Prior to Closing, Buyer shall use Commercially Reasonable Efforts to substitute or replace, or provide for the substitution or replacement effective as of the Closing, of those performance guaranties and letters of credit by or on behalf of SENY, including those listed on Schedule 1.1(n) (“SENY Assurances”), in a reasonable form such that neither Seller nor any of its Affiliates, including NU, have any obligations with respect to any such SENY Assurances after the Closing Date with respect to supply or delivery on and after the Closing Date. With respect to any SENY Assurances that Buyer cannot substitute or replace prior to the Closing, Buyer agrees to indemnify Seller and its Affiliates for any Damages that Seller or its Affiliates suffer related to such

SENY Assurances with respect to supply or delivery on and after the Closing Date until Buyer is able to provide such substitution or replacement.  All security deposits of cash with third parties by or on behalf of SENY, including those listed on Schedule 1.1(n) shall be left in place with such third parties, and the Purchase Price shall be adjusted in Seller’s favor dollar for dollar with respect to such deposits as provided in Section 2.2(c).   Seller agrees to indemnify Buyer pursuant to Article IX for any Damages that Buyer suffers related to application by a Person withdrawing such security deposits for supply or delivery obligations of Seller prior to the Closing Date in an amount that varies from such Purchase Price adjustment.

(d)

This Section 6.6 shall survive the Closing for the period necessary to give full effect to its terms.

6.7

Maintenance of Contracts Pending the Closing Date.  In addition to the provisions set forth in Section 6.1, between the Agreement Date and the Closing Date, Seller will not, and will cause SENY not to, grant, create or suffer to exist any Encumbrance on any of the Contracts, except for Permitted Encumbrances, unless otherwise consented to in writing by Buyer which consent shall not be unreasonably withheld, conditioned or delayed.  The Parties acknowledge and agree that Seller or its Affiliates may, for Contracts that have been assigned to Buyer, provide notice of termination (effective as of the Closing Date) of NU Guarantees under any Contracts or arrangements with other Persons; provided that the notice of termination does not constitute a breach of the underlying Contract.

6.8

Notice of Certain Events.  Each Party shall promptly notify the other Party of (a) any change or occurrence, or failure to occur, of any event that, individually or in the aggregate, has had or could reasonably be expected to have a Material Adverse Effect with respect to a Party or otherwise results in any representation or warranty of such Party hereunder being inaccurate in any material respect; (b) any failure of such Party to comply with or satisfy any covenant, condition or agreement to be complied with or satisfied by it hereunder in any material respect; (c) any written notice or other written communication from any Person alleging that the consent of such Person is or may be required in connection with the transactions contemplated hereby; (d) any written notice of default from a Counterparty with respect to any material Contract; (e) any written notice or oth er written communication from any Governmental Entity in connection with the transactions contemplated hereby (to the extent legally permitted); and (f) receipt of written notice of any action, suit, claim, investigation or proceeding directly involving any of the Acquired Assets that would reasonably be expected to materially and adversely affect or impair the consummation of the transactions contemplated hereby.  Each Party hereby acknowledges that the other Party does not and shall not waive any right it may have hereunder as a result of such notifications.

6.9

Cooperation.  The Parties shall cooperate in good faith and use Commercially Reasonable Efforts to obtain, and not to oppose directly or indirectly, the Buyer Regulatory Approvals or the Seller Regulatory Approvals.  The Parties will cooperate, support, assist in preparing or prepare and join in any filings, applications and other documents reasonably requested by the other Party in connection with this Agreement.  Seller and Buyer will each use Commercially Reasonable Efforts to prepare and file (or otherwise effect) as promptly as

practicable after the Agreement Date all applications, notices, petitions and filings with respect to the Seller Regulatory Approvals and Buyer Regulatory Approvals.

6.10

Further Assurances.  Each Party shall execute and deliver such additional instruments of sale, transfer, conveyance, assignment and confirmation and take such additional action as is necessary to (a) transfer, convey and assign to Buyer, and for Buyer to assume and accept, in each case in accordance with the terms hereof, the Administered Contracts (as they become transferable), the Acquired Assets and Assumed Liabilities and/or to cause Seller and its Affiliates to be released from the Assumed Liabilities and NU from the NU Guarantees, and (b) provide for the performance of the obligations of each Party under the Administration Agreement.  This Section 6.10 shall survive for a period of one (1) year after the Closing Date; provided that the foregoing undertakings with respect to the Administration Agreement shall survive until the full performance of all obligati ons thereunder.

6.11

Use of Seller’s Name and other Proprietary Information.

(a)

Effective on the Closing Date, Seller hereby grants to Buyer a non-exclusive, non-transferable, royalty-free right and limited license to use the name and logo set forth on Schedule 6.11 hereto that are used by Seller in connection with the Retail Business (collectively, the “Marks”) subject to the provisions hereof (the “Name Use License”) in connection with Buyer’s purchase of the Acquired Assets pursuant to this Agreement and Buyer’s performance of the Administered Contracts pursuant to the Administration Agreement or pursuant to any Backed Transaction, in each case subject to Seller’s right to cancel such Name Use License as provided in Section 6.11(c).

(b)

Subject to Section 6.11(c) below, the Name Use License shall remain in effect, and Buyer shall only use the Marks (i) for purposes of marketing of retail products and services in the electric energy and natural gas industries pursuant to the transactions contemplated under this Agreement, for a period of six (6) months following the Closing Date, and (ii) for purposes of performing services under the Administration Agreement or pursuant to any Backed Transaction, until such agreement or Backed Transaction is terminated or expired. Buyer acknowledges that Seller will continue to use the  Marks.  Accordingly, Seller retains the right to use the Marks in any manner and to grant non-exclusive licenses to any third parties to use the Marks other than for the sale of retail Power or Gas.  Seller further reserves the right and discretion to restrict, by written notice given to Buyer, the Name Use License in any instance in which Seller determines that the dual use of any of the Marks adversely affects Seller's business.  Without limiting the generality of the foregoing, the Name Use License does not extend to use of the Marks for purposes of conducting business other than on the retail level, and Buyer shall not use any of the Marks in connection with registrations, filings, agreements and/or any other transactions with any Person (including, without limitation, any System Operator) other than Buyer’s supply of electric energy and/or natural gas to such Person for end use consumption, except to the extent that Seller otherwise approves any such use in writing in advance.

(c)

In connection with the Name Use License provided in Section 6.11(a), Buyer shall use the Marks consistent with Seller’s past practice and any other guidelines or communications provided to Buyer, and that Seller may terminate the Name Use License at any time in its sole discretion if used otherwise.  In addition, except as otherwise provided in this Agreement or the Administration Agreement with respect to the Administered Contracts, Buyer and its Affiliates shall not hold themselves out as agents or representatives of Seller or its Affiliates, and Seller may terminate the Name Use License at any time in its sole discretion if Buyer or its Affiliates violate any of the foregoing prohibitions.  

(d)

Buyer acknowledges that Seller makes no representations or warranties, express or implied, with respect to the Marks, and, without limiting the generality of the foregoing, specifically disclaims any implied warranties of merchantability, title, noninfringement or fitness for a particular purpose.

(e)

This Section 6.11 shall survive the Closing for the period necessary to give full effect to its terms.

6.12

Cooperation Regarding the Transfer of Certain Responsibilities and Obligations.  The Parties shall cooperate in good faith to facilitate the transfer from Seller to Buyer as of the Closing Date of all responsibilities for meeting the requirements of and complying with the rules and procedures of applicable System Operators, Pipeline Administrators and LDCs related to the Contracts (including the enrollment of Customers), whether such Contracts are transferred on the Closing Date or will be performed as Administered Contracts pursuant to the Administration Agreement.  In addition, to the extent that Seller or SENY has LDC Obligations, Load Obligations or Pipeline Obligations in connection with any of the Contracts, the Parties shall cooperate and take all steps reasonably necessary to transfer such LDC Obligations, Load Obligations or Pipeline Obligations to Buyer in accordance with all applicable requirements, rules and procedures, as of the Closing Date.  If any of such obligations cannot be transferred effective on the Closing Date and/or the Parties mutually determine to defer any of such transfers to minimize disruptions, including for the avoidance of Customer enrollments other than at the end of the applicable billing cycle, Buyer and Seller shall fully indemnify and reimburse each other, within three (3) Business Days after request therefor, with respect to all Liabilities of Seller and its Affiliates or Buyer incurred as a result of, and/or in connection with, each such transfer not occurring as of the Closing Date. If this Agreement is terminated in accordance with Article VIII, Buyer shall promptly take any and all steps necessary to effect the immediate transfer of the LDC Obligations, Load Obligations or Pipeline Obligations back to Seller or SENY, as the case may be; provided that if the immediate transfer of the Load Obligation or Pipeline Obligati on back to Seller or SENY is delayed, Buyer shall execute such documents or forms and act at the instruction of Seller to place Seller in the same position Seller or SENY would have been in if the LDC Obligations, Load Obligations or Pipeline Obligations had been immediately transferred back to Seller or SENY.  This Section 6.12 shall survive the Closing for the period necessary to give full effect to its terms.

6.13

Workforce Covenants.

(a)

Within two (2) Business Days after the Agreement Date, Seller shall provide to Buyer a listing of Seller’s account executives engaged in the Retail Business, and within five (5) Business Days Seller shall provide to Buyer a listing of all other employees engaged in the operation or administration of the Retail Business.  Such list shall include base salary information, the years of Seller-credited service for each such current employee, and the maximum amount of severance such employee would be entitled to under Seller’s existing severance policy, all as of May 31, 2006.  Buyer will be permitted, following execution hereof, to interview any of the listed individuals and to offer employment, on comparable terms as such employee had with Seller, to any such employee on and after Closing, but is not required as a condition hereof to offer employment to any such individual.  Notwithstanding any h iring decision, Buyer will have no liability to either such employee or Seller in connection with any of Seller’s benefit plans (including pension obligations of Seller and its Affiliates), policies or procedures, term or condition of employment, and nothing herein is intended to create any right, privilege or claim in any such employee or Seller, and Buyer expressly disclaims that such employees are intended beneficiaries hereof.  Subject to the qualification above, and the provision that the one (1) year requirement for entry into Buyer’s pension plan cannot be waived and that such employees would not be given credit for prior service for purposes of determining benefit payments amounts under Buyer’s pension plan, Buyer covenants with Seller that any such employee accepting employment with Buyer will be provided with the benefits offered under Buyer’s benefits, policies and procedures to similarly situated Buyer’s employees, including credit for service for purposes of vesting benefits under Buyer’s pension plan, as if the scheduled years of Seller’s service were deemed to be service as an employee of Buyer.  Buyer shall notify Seller promptly of each individual decision regarding employment of Persons then working for Seller, and shall have made all such decisions regarding such employment and notified Seller thereof not later than fifteen (15) days prior to the Closing and shall provide Seller a final list of the names of such all such individuals at that time.  Buyer and Seller shall cooperate with respect to communications to employees and regarding Buyer’s hiring decisions. Subject to the confirmation in writing prior to the Closing Date by each such individual of his or her intention to be so employed (each such a “Hired Employee”), each Hired Employee shall be retained by Buyer on an at-will basis effective as of the Closing Date.  Buyer acknowledges that certain employees may remain employed by Seller and/or its Affiliates an d that employees may choose not to accept an offer of employment with Buyer, and the Parties agree that neither event shall constitute a breach hereunder by Seller or otherwise excuse the full performance by Buyer of its obligations in accordance with the terms hereof.

(b)

With respect to each Hired Employee:

(i)

Buyer shall employ such Hired Employee for a period of not less than ninety (90) days following the Closing (the “Initial Employment Period”) (provided that Buyer retains the right to terminate any such Hired Employee for cause); and

(ii)

Any Hired Employee terminated after the first (1^st) anniversary of the Closing Date shall be entitled to receive such severance benefits as may be applicable under severance plans maintained or adopted by Buyer.

(c)

In the event that Buyer terminates any Hired Employee during the Initial Employment Period for any reason other than for cause, Buyer shall pay any such terminated Hired Employee an amount equal to such terminated Hired Employee’s base salary for the remainder of the Initial Employment Period, plus Enhanced Severance; provided that such terminated Hired Employee executes and delivers to Buyer a general release and covenant not to sue in favor of Buyer, Seller and their respective Affiliates in a form reasonably acceptable to Seller.  In the event that Buyer terminates any Hired Employee after the Initial Employment Period but prior to the first (1^st) anniversary of the Closing Date for any reason other than cause, Buyer shall pay any such terminated Hired Employee Enhanced Severance, subject to receipt of the release reference in the immediately preceding sentence.

(d)

After the Closing, Buyer shall continue to pay all AE/CC Commissions that are Assumed Liabilities to any Hired Employees who earned such AE/CC Commissions while employed by Seller in accordance with the Commission Plan and Seller’s past practices.  With respect to AE/CC Commissions that are Assumed Liabilities, but are payable to persons who are not Hired Employees because they were not offered comparable employment by Buyer, Buyer shall reimburse Seller for an amount equal to fifty percent (50%) of the aggregate payment by Seller to such persons  with respect to such AE/CC Commissions; provided, that Buyer’s reimbursement obligation hereunder extends only to such commissions that Seller pays prior to or on December 31, 2007; provided further, that in the event Seller has not paid any such commissions due to proceedings before any Governmental Entity, mediator, arbitrator or similar dispute re solution forum, initiated with respect to such person prior to December 31, 2007, Buyer shall be obligated to reimburse Seller as described above for any AE/CC Commissions paid by Seller with respect to the conclusion or settlement of any such proceeding.  With respect to Persons who are offered comparable employment with Buyer, but do not accept the offer, Seller shall not pay any severance or AE/CC Commissions following the failure to accept such offer.  For purposes of clarity, the transactions contemplated by this Agreement shall not constitute a “realignment, reorganization or downsizing” under the Commission Plan.

(e)

This Section 6.13 shall survive the Closing for the period necessary to give full effect to its terms.

6.14

Supplements to Schedules.

(a)

From time to time prior to the Closing Date, in addition to the changes contemplated under Section 6.1, Seller shall supplement or amend and deliver updates to the Schedules to this Agreement (each a “Schedule Update”) which are necessary to complete or correct any information in the Schedules or in any continuing representation or warranty of Seller which has been rendered inaccurate since the Agreement Date.

(b)

If Buyer shall notify Seller in writing of any potential indemnification claim under Section 9.4 with respect to a Schedule Update Seller shall have the right, within ten (10) Business Days after receipt of such written notice from Buyer, to cure, if possible, any claimed deficiency or breach identified in Seller’s Schedule Update; provided that any such effort to cure shall not prejudice either Buyer’s right to pursue or Seller’s right to dispute any such claim for indemnification.

(c)

Schedule Updates related to Select Contracts or SENY Contracts will be delivered by Seller at the Closing to reflect any changes (as reflected in Seller’s and SENY’s records as of the Closing Date) to such Schedules originally attached to this Agreement on the Agreement Date.  Buyer acknowledges that due to the continued operation of the Retail Business throughout the period between the Agreement Date and the Closing Date that Schedule Updates related to such Schedules may not include all of the Contracts as of the Closing due to the difficulties of reporting such changes in real time.  Consequently, Seller shall, as soon as practicable following the Closing, update the appropriate Schedules for any such Contracts not listed in such Schedule Updates.  Representations and warranties of Seller regarding the Schedules shall be effective as of the date such Schedules are updated pursuant to t he terms herein.

6.15

Bulk Transfer Laws.  Buyer acknowledges that Seller will not comply with the provisions of any bulk transfer laws of any jurisdiction in connection with the transactions contemplated by this Agreement.  Buyer hereby waives compliance by Seller with the provisions of the bulk sales or transfer laws of all applicable jurisdictions.

6.16

Transition Services.  For the periods set forth on Schedule 6.16, Seller will use Commercially Reasonable Efforts to provide those transition services designated by Buyer on Schedule 6.16 at prices to be mutually agreed upon by Buyer and Seller prior to the Closing Date; provided that, in the event that Buyer and Seller are unable to reach such agreement on pricing for any transitional services in whole or in part prior to the Closing Date, acting reasonably and in good faith, Seller shall thereafter provide such services and Buyer shall reimburse Seller for Seller’s actual fully-loaded costs (including salary, benefits and retention costs) with no profit margin of providing such services, with any dispute regarding such reimbursement being resolved pursuant to Section 10.17.  Seller shall furnish any such services in a manner consistent with pa st practices; provided (a) to the extent any Hired Employees previously performed such services for Seller and/or its Affiliates, Seller, by written notice given to Buyer after the Closing, may decline to provide all or any portion of the affected services; and (b) Seller reserves the right to vary from such past practices as a result of resource limitations, including the departure of personnel who previously performed such services for Seller.  Notwithstanding anything to the contrary set forth herein and/or under Applicable Law, Seller and its Affiliates shall have no Liability to Buyer and/or its Affiliates for any services performed pursuant to this Section 6.16, and Buyer hereby releases and discharges Seller and its Affiliates from such Liability, it being understood that Buyer's sole recourse and remedy for dissatisfaction with the performance of services shall be termination of the services arrangement unless such liability arises from recklessness or willful misconduct.  This Section 6.16 shall survive after the

termination of the service period until Buyer has paid Seller in full for such services in accordance with Schedule 6.16.

6.17

Buyer Master Agreements.  The Parties contemplated that in connection with the  assignment of each Sourcing Contract, simultaneously with the Closing, the Counterparty to such Sourcing Contract will release Seller and its Affiliates, in a form acceptable to Seller, from all Liabilities under such Sourcing Contract, and such Sourcing Contract shall constitute a transaction under, and otherwise governed by, the Master Agreement(s) between Buyer and such Counterparty.  The Parties do not contemplate that Seller will transfer its Master Agreements with Counterparties to Buyer.  To effect the foregoing, prior to the Closing Date, (a) with respect to Master Agreement(s) between Buyer and the Counterparty to each Sourcing Contract in existence as of the Agreement Date, Buyer shall negotiate in good faith with each such Counterparty to allow for such assignment to occur without incident; and (b) to the extent that Buyer does not have any or an appropriate Master Agreement in effect with any Counterparty to a Sourcing Contract that allows Buyer to transact with that Counterparty for Power and/or Gas (as the case may be), Buyer shall use Commercially Reasonable Efforts to enter into with each such Counterparty all agreements or confirmations necessary to transact with that Counterparty for Power and/or Gas.

6.18

Customer Notification.  As soon as practicable following the Agreement Date and/or the Closing Date, and only to the extent required by Applicable Law, Seller and Buyer will cause to be sent to the active Customers under Retail Sales Contracts a notice of the transfer of such Customers from Seller to Buyer, which notice will comply with all applicable requirements of the public utility commissions having jurisdiction (“PUCs”), all other relevant Governmental Entities and LDCs related to the transfer of Power and/or Gas customers.  Such notices shall contain such information concerning Seller and Buyer as is required by Applicable Law and/or LDC Rules.  After the Closing Date, Buyer also shall cause SENY to send any and all notices to Customers under SENY Contracts, PUCs and all other relevant Governmental Entities and LDCs, in each case as re quired under Applicable Law and/or LDC Rules in connection with the consummation of the transactions contemplated by this Agreement.  Seller, in its discretion, may combine the notices required under this Section 6.18 with the notice contemplated under Section 6.6.  This Section 6.18 shall survive the Closing for the period necessary to give full effect to its terms.

6.19

Seller’s Retention of Certain SENY Assets; Other SENY Actions.

(a)

Buyer acknowledges and agrees that prior to the Closing, SENY intends to assign, in a manner reasonably determined by Seller, its account receivables, routine collection matters and bankruptcy claims (including those collection matters and bankruptcy claims owned by or applicable to SENY included on Schedule 2.1(b)(ii)) in existence immediately prior to the Closing Date to an Affiliate, and that any such accounts receivable, routine collection matters and bankruptcy claims will not be held by SENY when the SENY Shares are sold to Seller.  Buyer agrees that to the extent Seller is unable to effectuate such assignments prior to the Closing, Buyer will use Commercially Reasonable Efforts, at Seller’s expense, to effect such assignments after the Closing, to be effective, where permitted by Applicable Law, as of the Closing Date.  In the event

that any such matters or claims are not assigned to Seller prior to Closing, Seller will indemnify Buyer pursuant to Article IX for all Damages suffered by Buyer associated with any such matters between the Closing Date and the eventual assignment of such matters.

(b)

Buyer also acknowledges and agrees that prior to the Closing, Seller and SENY shall remove all cash from SENY bank accounts, and that Seller shall retain any such cash or cash equivalents where ever held, as well as any cash of SENY in money pools of Seller Affiliates; provided that, to the extent necessary Seller shall leave sufficient cash in SENY checking accounts to cover any outstanding checks of SENY written prior to Closing, and Buyer shall cause such checks to be honored following the Closing to the extent that Seller left funds in SENY’s account available therefor.

(c)

Prior to Closing, SENY shall terminate all existing agreements and money pool arrangements with Seller and its Affiliates which impose obligations on SENY after the Closing, except that this provision will not act to terminate SENY’s obligations to perform such actions as are necessary to effect transactions as are permitted to be performed after Closing pursuant to the terms of this Agreement.  Seller’s Affiliates shall not, and shall not be obligated to, provide insurance of any kind for SENY after the Closing Date.

(d)

Prior to Closing SENY shall transfer to Seller or another Affiliate all deposits or prepayments of Customers and other Counterparties held by SENY in a manner reasonably determined by Seller for disposition in the manner set forth in Section 6.4.

(e)

Prior to the Closing, SENY shall assign and/or transfer to Seller and/or its Affiliates in a manner reasonably determined by Seller, (i) its office leases in Albany and Syracuse, New York, and (ii) all furniture, equipment, systems or similar tangible assets of SENY that are in SENY’s Albany and Syracuse, New York offices or in off-site storage (collectively, the “Retained Syracuse Assets”).  Buyer agrees that to the extent Seller is unable to effectuate such assignments and/or transfers prior to the Closing, Buyer will cause SENY to effect such assignments and/or transfers (at Seller’s expense) after the Closing, to be effective, where permitted by Applicable Law, as of the Closing Date.  Seller will indemnify Buyer pursuant to Article IX for all Damages suffered by Buyer associated with the Retained Syracuse Assets between the Closing Date and the eventual assignment and/or tran sfer of such assets.

(f)

Buyer shall reimburse Seller dollar-for-dollar for the value of any prepayments for goods or services made by SENY prior to the Closing that inure to the benefit of Buyer on and after the Closing.  Within thirty (30) days after Closing, Seller shall provide Buyer a list of any such prepayments along with reasonable supporting documentation, and the aggregate value of such prepayments shall be settled as a dollar-for-dollar adjustment to the Purchase Price in favor of Seller as provided in Section 2.3(c).  

6.20

Renewable Portfolio Standards Reporting Obligations.  Following the Closing, Buyer shall assume responsibility, at its own expense, for taking all action (other than executing any filing or registration with, or application or request for consent or approval of, any Governmental Entity) and providing all information necessary for Seller to comply with all Attribute Laws applicable to it for the states and time periods set forth on Schedule 6.20 which time periods extend beyond the Closing (the “Attribute Law Requirements”).  Without limiting the generality of the foregoing, Buyer shall be responsible at its own expense for (a) purchasing Renewable Energy Credits on behalf of Seller, (b) depositing those Renewable Energy Credits in Seller’s accounts in the Tracking Systems used to demonstrate compliance with the Attribute Law Requirements, (c) preparing for execution by Seller the filings and registrations with Governmental Entities necessary for Seller to demonstrate compliance with the Attribute Law Requirements, and (d) upon execution of such filings and registrations by Seller, filing such filings and registrations with the appropriate Governmental Entities prior to the deadline therefor.  All filings and registrations prepared by Buyer pursuant to this Section 6.20 shall be provided to Seller at least thirty (30) days prior to the deadline date when such filing or registration must be filed with a Governmental Entity.  In order to effect the purposes of this Section 6.20, Seller appoints Buyer as its agent solely for the purpose of effecting transactions in the Tracking Systems at Buyer’s expense, and Seller will execute such forms and other documents as may be necessary to evidence or effect that appointment.  Seller will use Commercially Reasonable Efforts to cooperate with Buyer in performing its o bligations under this Section 6.20.  This Section 6.20 shall survive the Closing for the period necessary to give full effect to its terms.

6.21

Cure of Material Adverse Effect.  Each Party shall exercise Commercially Reasonable Efforts to cure any known Material Adverse Effect existing with respect to such Party prior to the Closing.

6.22

Buyer Maintenance of Permits and Agreements.

(a)

Buyer shall secure and maintain all Permits set forth on Schedule 4.6(a), at Buyer's sole cost and expense (including costs of preparation, any filing fees and/or charges, and any bonds or other performance assurance relating to such Permits), in a manner that assures procurement on or before the Closing Date.  Buyer shall furnish to Seller copies of each application for such Permit simultaneously with the submission thereof to the applicable Governmental Entity, and within three (3) Business Days after Buyer's issuance or receipt, as the case may be, Buyer shall provide copies to Seller of any written communication submitted to, and/or received from, such Governmental Entity and/or otherwise relating to each such Permit.  Without limiting the generality of the foregoing, Buyer shall immediately notify Seller of any adverse action and/or other development with respect to such permitting process. &nbs p;Buyer shall furnish to Seller copies of each such Permit within three (3) Business Days after Buyer’s receipt of same.

(b)

Buyer, at Buyer's sole cost and expense (including costs of any bonds or other performance assurance relating thereto), shall enter into all agreements, tariffs and/or other documents set forth on Schedule 4.6(b) with the applicable LDC, System Operator, and Pipeline Administrator, in a manner that assures completion on or before

the Closing Date.  Within three (3) Business Days after Buyer's issuance or receipt, as the case may be, Buyer shall provide copies to Seller of any written communication submitted to, and/or received from, an LDC, System Operator, and Pipeline with respect to such efforts.  Without limiting the generality of the foregoing, Buyer shall immediately notify Seller of any adverse action and/or other development with respect to such process.  Buyer shall notify Seller in writing of each successful completion of the process.

6.23

Sale of Storage Gas.

(a)

Simultaneously with the Closing, Buyer and Seller shall enter into transactions providing for the sale to Buyer of stored Gas owned by Seller at the applicable Storage Gas Location(s).  The transactions will be documented on applicable Gas Industry Standards Board forms, at the prevailing applicable market price in effect on the Closing Date.  The sale shall be priced in accordance with the applicable indices for such purpose as set forth on Schedule 6.23 for the actual quantity of gas in storage at 10:00 a.m. on the Closing Date.

(b)

Simultaneously and in connection with the Closing and in connection with the sale of the SENY Shares to Buyer, Buyer shall also acquire the stored Gas owned by SENY at the applicable Storage Gas Location(s).  Buyer shall pay Seller for the stored Gas owned by SENY at the prevailing applicable market price in effect on the Closing Date.  The sale shall be priced in accordance with the applicable indices for such purpose as set forth on Schedule 6.23 for the actual quantity of gas in storage at 10:00 a.m. on the Closing Date.  Buyer’s payment for such stored Gas will be treated as a dollar for dollar adjustment to the Purchase Price in Seller’s favor as provided in Section 2.2(c).

6.24

Agreement Not to Compete. For good and valuable consideration, Seller agrees that, except as otherwise provided in this Section 6.24, for a period commencing on the Closing Date and ending on the date which is sixty (60) months after the Closing Date (the “Non-Compete Term"), neither Seller nor its Affiliates (Seller and such Affiliates, herein, the "Restricted Persons") shall, without the prior written consent of Buyer, directly or indirectly (whether as principal, agent, independent contractor, partner or otherwise or by any other means) own, manage, operate, control, participate in, perform services for or otherwise carry on, in any material respect, any business or division or line of any business for the purpose of engaging in the deregulated retail commodity sale of natural gas or electricity to commercial, industrial or institutional customers in the Territory (a "Competitive Business"); provided, however, that:

(a)

any Restricted Person which is a regulated electric or gas utility may engage in any such activity if the following conditions have been satisfied (to the extent not waived by Buyer):

(i)

such activity is limited to the service territory of such Restricted Person;

(ii)

such Restricted Person shall not actively market or solicit the deregulated or competitive retail commodity sale of natural gas or electricity

to commercial, industrial or institutional customers in connection with such activities; and

(iii)

such activity has been authorized by a Governmental Entity (including through legislative action and/or PUC decisions and/or orders) under a regulatory structure that permits such Restricted Person the opportunity to recover the economic effect thereof.

The Parties intend that the foregoing exception will allow Seller's regulated electric or gas utility Affiliates to engage in their regulated utility businesses, including the installation and operation of, and the sale of output from, applications at customer premises (including distributed resources), demand side management, and limited economic development “special” contracts within their respective service territories, but shall not be construed to allow such Affiliates to broadly engage in the deregulated or competitive retail commodity sale of natural gas or electricity to commercial, industrial or institutional customers.  If Buyer asserts in writing that any of Seller's regulated electric or gas utility Affiliates have engaged in the foregoing activities, but have not satisfied the foregoing conditions, then within thirty (30) days after Seller's receipt of such assertion, Seller shall have the right, but not the obligation, to pay to Buyer the Buy Out Amount (as calculated below), in which case (A) Seller's obligations under this Section 6.24 with respect to Seller's regulated electric or gas utility Affiliates shall be limited only to a prohibition that such regulated electric or gas utility Affiliates may not create a competitive subsidiary, division or other entity to engage in a Competitive Business, or contracting for or engaging any sales channels for such sales; and (B) such Buy Out will be deemed a simultaneous Buy Out pursuant to (b)(i)(A) below, effective as of the date of any subsequent merger or acquisition.  If Seller does not elect to make such payment of the Buy Out Amount pursuant to the foregoing, then Buyer shall have the right to pursue, and Seller shall have the right to dispute, any claim by Buyer for indemnification resulting from such assertion);

(b)

such prohibition shall not prevent any Restricted Person from merging with or acquiring or being acquired by a company whose business includes such a Competitive Business; provided that:

(i)

within thirty (30) days after the consummation of such business combination, Seller either shall (A) unless previously paid pursuant to Section 6.24(a) above, pay to Buyer the Buy Out Amount (as calculated below), in which case any and all of Seller's obligations under this Section 6.24 shall be extinguished without Liability or recourse whatsoever; or (B) advise Buyer in writing that the surviving entity intends to divest or cease to conduct such Competitive Business restricted under, and in accordance with, this Section 6.24(b);

(ii)

if Seller has notified Buyer under clause (i)(B) above that the surviving entity intends to divest or cease to conduct such Competitive Business, then on or before the expiration of the Divestiture Period, the surviving entity either shall divest such Competitive Business, or cease to conduct such Competitive Business (other than as necessary to perform, compromise or

otherwise liquidate obligations outstanding and/or incurred before such cessation).  The "Divestiture Period" shall mean the period commencing on the date that Seller notifies Buyer under clause (i)(B) above and ends one hundred and eighty (180) days thereafter; provided that Seller shall have the right to request, and the Parties shall negotiate in good faith, an extension of such initial period based on the divestiture plan for such Competitive Business (including the marketing plan developed by any independent adviser retained by the surviving entity for such purpose); provided further that if one or more agreements for such divestiture have been executed during the Divestiture Period, but the parties thereto have not yet satisfied the conditions to closing thereunder, and/or if Buyer (and/or any of its Affiliates) is negotiating to acquire such Competitive Business, the Divestiture P eriod shall be extended to allow for the consummation of such transaction(s);

(iii)

during the Divestiture Period, the surviving entity shall not use the “Select” and/or "Northeast Utilities" name, mark or brand in soliciting the deregulated or competitive retail commodity sale of natural gas or electricity to commercial, industrial or institutional retail customers in connection with such Competitive Business; and

(iv)

such Competitive Business shall be conducted in the ordinary course during the Divestiture Period which shall not include the expansion of such Competitive Business into new states and/or the contribution of capital (financial or intellectual) to such Competitive Business (other than as reasonably necessary to preserve the value thereof in the divestiture process and/or to fulfill Liabilities in connection with the cessation process, as the case may be); and

(c)

the foregoing shall not prohibit Seller’s conduct of those portions of the Retail Business constituting the Excluded Assets (including those Administered Contracts for their stated term subject to the Administration Agreement) and Seller's satisfaction of the Excluded Liabilities, and shall not apply to that portion of Seller’s business as of the Agreement Date not related to the Retail Business.

The "Buy Out Amount" shall mean a lump sum payment equal to Three Hundred Thirty Three Thousand Three Hundred Thirty Three Dollars ($333,333.00) multiplied by the number of full or partial months remaining in the Non-Compete Term.  For example, if such election occurs with twenty (20) months remaining in the Non-Compete Term, the Buy Out Amount would be Six Million Six Hundred Sixty Six Thousand Six Hundred Sixty Dollars ($6,666,660.00) (20 x $333,333.00 = $6,666,660.00).  Notwithstanding anything to the contrary in this Section 6.24, Seller shall have no obligation to pay the Buy Out Amount on more than one occasion.

ARTICLE VII

CONDITIONS TO THE PARTIES’ OBLIGATIONS TO CLOSE

7.1

Seller’s Closing Conditions.  The obligation of Seller to consummate the transactions contemplated by this Agreement is subject to the satisfaction, or waiver by Seller, of the following conditions (collectively, the “Seller’s Closing Conditions”):

(a)

Representations and Warranties True.  Each of the representations and warranties of Buyer contained in this Agreement shall be true and correct in all material respects (except with respect to representations and warranties that contain materiality qualifiers, which representations and warranties shall be true and correct in all respects as so qualified) on and as of the Closing Date as if made on and as of such date, except to the extent that any such representation or warranty is made as of a specified date, in which case such representation or warranty shall have been true and correct as aforesaid as of such specified date;

(b)

Covenants and Agreements Performed.  Buyer shall have performed and complied with in all material respects all covenants and agreements required by this Agreement to be performed or complied with by it on or prior to the Closing Date and all deliveries contemplated by Section 5.3 shall have been made;

(c)

Legal Proceedings.  No preliminary or permanent injunction or other order, decree, or ruling shall have been issued by a Governmental Entity and no proceeding for the purpose of obtaining a preliminary injunction shall have been commenced since the Agreement Date, and no statute, rule, regulation, or executive order shall have been promulgated or enacted by a Governmental Entity since the Agreement Date, in each case, which remains in effect on the Closing Date which restrains, enjoins, prohibits, or otherwise makes illegal the consummation of the transactions contemplated by this Agreement, the Administration Agreement or in the Ancillary Documents;

(d)

No Material Adverse Effect.  Between the Agreement Date and the Closing Date there shall not have occurred or arisen any Material Adverse Effect in relation to Buyer that Buyer has not cured that results in a right to terminate this Agreement;

(e)

Bankruptcy.  Buyer shall not be Bankrupt;

(f)

Regulatory Approvals.  All Seller Regulatory Approvals shall have been obtained;

(g)

Permits.  Buyer shall have procured all of the Permits set forth in Section 4.6(a) of the Buyer’s Disclosure Schedule, all of such Permits are in full force and effect, and there is no action or proceeding pending or threatened against Buyer or any of its Affiliates before any Governmental Entity directly concerning any of such Permits; and

(h)

Other Buyer Agreements.  Buyer shall have entered into all agreements, tariffs and/or other documents and shall have obtained any accounts as required by each LDC, LDC Pool, System Operator, and Pipeline Administrator as set forth in Section 4.6(b) of the Buyer’s Disclosure Schedule and otherwise satisfied any and all conditions

of each of such Persons necessary for Buyer to perform its obligations under the Contracts and under the Administration Agreement, and there is no action or proceeding pending or threatened against Buyer or any of its Affiliates Buyer alleging any noncompliance with any Market Rules and Procedure, LDC Rules and natural gas pipeline tariffs applicable to the Contracts.

7.2

Buyer’s Closing Conditions.  The obligation of Buyer to consummate the transactions contemplated by this Agreement is subject to the satisfaction, or waiver by Buyer, of the following conditions (collectively, the “Buyer’s Closing Conditions”):

(a)

Representations and Warranties True.  Each of the representations and warranties of Seller contained in this Agreement shall be true and correct in all material respects (except with respect to representations and warranties that contain materiality qualifiers, which representations and warranties shall be true and correct in all respects as so qualified) on and as of the Closing Date as if made on and as of such date, except to the extent that any such representation or warranty is made as of a specified date, in which case such representation or warranty shall have been true and correct as aforesaid as of such specified date (in each case as may be modified pursuant to Section 6.14);

(b)

Covenants and Agreements Performed.  Seller shall have performed and complied with in all material respects all covenants and agreements required by this Agreement to be performed or complied with by it on or prior to the Closing Date and all deliveries contemplated by Section 5.2 shall have been made;

(c)

Legal Proceedings.  No preliminary or permanent injunction or other order, decree, or ruling shall have been issued by a Governmental Entity and no proceeding for the purpose of obtaining a preliminary injunction shall have been commenced since the Agreement Date, and no statute, rule, regulation, or executive order shall have been promulgated or enacted by a Governmental Entity since the Agreement Date, in each case, which remains in effect on the Closing Date which restrains, enjoins, prohibits, or otherwise makes illegal the consummation of the transactions contemplated by this Agreement, the Administration Agreement or in the Ancillary Documents;

(d)

No Material Adverse Effect.  Between the Agreement Date and the Closing Date there shall not have occurred or arisen any Material Adverse Effect in relation to Seller that Seller has not cured that results in a right to terminate this Agreement;

(e)

Bankruptcy.  Neither Seller nor the Seller’s Guarantor shall be Bankrupt; and

(f)

Regulatory Approvals.  All Buyer Regulatory Approvals shall have been obtained.

7.3

Waiver of Closing Conditions.  Seller may, in its sole discretion, waive any of the Seller’s Closing Conditions, and Buyer may, in its sole discretion, waive any of the Buyer’s

Closing Conditions); provided that: (a) Seller shall waive Seller’s Closing Conditions under Sections 7.1(a), 7.1(b), 7.1(g) and 7.1(h) if the failure to satisfy any of such conditions does not preclude Buyer from performing its obligations under the Administration Agreement (including through the use of transitional services under Section 6.16) and such failure is not a result of fraud, willful misconduct or failure to comply with Applicable Laws; provided, further, that such waiver shall not affect Seller’s rights under the Administration Agreement and/or indemnification pursuant to Article IX; and (b) Buyer shall waive Buyer’s Closing Conditions under Sections 7.2(a) and 7.2(b) unless failure to satisfy such conditions is due to fraud, willful misconduct or failure to comply with Applicable Laws; provided that such waiver shall not prejudice Buyer’s right to claim indemnification pursuant to Article IX.

ARTICLE VIII

TERMINATION

8.1

Termination.  This Agreement may be terminated at any time prior to the Closing Date, solely as follows:

(a)

by mutual written consent of Seller and Buyer;

(b)

by Seller or by Buyer, if any representation or warranty contained in this Agreement is determined not true in some material respect as of the Agreement Date or not true in some material respect on the Closing Date (after giving effect to any applicable Schedule Updates and the cure provisions under Section 6.14), and such other Party fails to cure such misrepresentation within thirty (30) days after receipt of written notice thereof; provided if such misrepresentation is capable of cure and such other Party shall be pursuing such cure with due diligence, but such cure cannot be effected within such thirty (30) days, then such cure period shall be extended until the Closing Date; provided further that if the then scheduled Closing Date would occur during the foregoing initial cure period, or the foregoing extended cure period would expire in less than fifteen (15) days due to the then scheduled Closing Date, the scheduled Closing Date shall be extended to provide for an aggregate cure period of forty-five (45) days;

(c)

by Seller or by Buyer, if the other Party has failed to comply in any material respect with any of its covenants or agreements contained in this Agreement, and such other Party fails to cure such noncompliance within thirty (30) days after receipt of written notice thereof; provided if such noncompliance is capable of cure and such other Party shall be pursuing such cure with due diligence, but such cure cannot be effected within such thirty (30) days, then such cure period shall be extended until the Closing Date; provided further that if the then scheduled Closing Date would occur during the foregoing initial cure period, or the foregoing extended cure period would expire in less than fifteen (15) days due to the then scheduled Closing Date, the Closing Date shall be extended to provide for an aggregate cure period of forty-five (45) days; provided that, notwithstanding anything to the contrary in the foregoing , elsewhere in this Agreement, or under Applicable Law, neither Seller nor Buyer shall be entitled to any cure period with respect to such Party's failure to provide assurances in strict accordance with Section

2.2(d), and the other Party may immediately exercise any and all of its right and remedies, including under Section 8.3, upon such failure;

(d)

by Seller or Buyer, if a Governmental Entity has issued a final non-appealable order, decree or ruling or taken any other action (which order, decree or ruling the Parties have used all their Commercially Reasonable Efforts to lift), which permanently restrains, enjoins or otherwise prohibits the transactions contemplated by this Agreement; or

(e)

by either Party on August 1, 2006, if Closing has not occurred, provided that (i) such date shall be extended to give full effect to any applicable cure period (but in no event past July 31, 2006), and (ii) if the  Closing has not occurred due to a breach of the representations, warranties or obligations of the Party seeking termination, which breach has not been timely cured, then such Party may not terminate this Agreement pursuant to this Section 8.1(e).  

Notwithstanding anything to the contrary in this Section 8.1, (A) the Buyer’s sole and exclusive remedy for any breach of Sections 3.2(c)(iv), 3.4, 3.5, 3.7, 3.9, 6.1, 6.3, 6.4, 6.7, 6.12 and 6.14 shall be indemnification pursuant to Article IX, and Buyer hereby waives any right to terminate this Agreement as a result of any such breach, other than a breach due to fraud, willful misconduct or failure to comply with Applicable Laws, and (B) if Buyer has breached Sections 4.6 and 6.22 and such breach does not preclude Buyer from performing its obligations under the Administration Agreement (including through the use of transitional services under Section 6.16), then the Seller will not exercise its right to terminate this Agreement as a result of any such breach, other than a breach due to fraud, willful misconduct or failure to comply with Applicable Laws; provided, however, the foregoing shall not affect Seller’s rights under the Administration Agreement.

8.2

Effect of Termination.

(a)

If this Agreement is terminated prior to the Closing pursuant to Section 8.1, then this Agreement will immediately become null and void, and there will be no Liability or obligation on the part of Seller or Buyer (or any of their respective officers, directors, employees, agents or other representatives or Affiliates), except that the provisions with respect to fees and expenses in Section 6.2, cooperation regarding the transfer of certain responsibilities and obligations in Section 6.12, termination damages in Section 8.3, notices in Section 10.2, consent to venue and governing law in Section 10.4, confidentiality in Section 10.13, dispute resolution in Section 10.17, and this Section 8.2 will continue to apply following any such termination.

(b)

If this Agreement is terminated pursuant to Section 8.1, all filings, applications and other submissions made pursuant to this Agreement shall be withdrawn from the Person to which they were made.  In addition to the rights of the Parties set forth in Section 8.3, the Parties shall retain the right to pursue any other remedies, whether legal or equitable, following any such termination.

8.3

Termination Damages.

(a)

In the event that (i) Buyer repudiates this Agreement, or (ii) Seller terminates this Agreement pursuant to Sections 8.1(b) and/or 8.1(c) and Buyer failed to use its best efforts to cure the breach giving rise to such termination, then in either case Buyer shall pay to Seller by wire transfer of immediately available United States funds in accordance with Seller's instructions Twenty Million Dollars ($20,000,000.00).  In all other instances in which Seller terminates this Agreement pursuant to Sections 8.1(b) and/or 8.1(c), then Buyer shall pay to Seller by wire transfer of immediately available United States funds in accordance with Seller's instructions Three Million Dollars ($3,000,000.00).  Any  payment hereunder shall be made within three (3) Business Days after such repudiation or the effective date of such termination.  Buyer specifically acknowledges that Seller's termination of this A greement due to a default by Buyer or Buyer’s repudiation of this Agreement will result in irreparable injury to Seller to the Retail Business, particularly its value and viability as a going concern, the full nature and extent of which cannot be reasonably ascertained at this time, but which are acknowledged by both Parties to be substantial; accordingly, Buyer shall pay the applicable foregoing sum under this Section 8.3(a) to Seller as liquidated damages as a mutually agreed and reasonable estimate of such injury to the Retail Business and not as a penalty.

(b)

In the event that Buyer terminates this Agreement pursuant to Sections 8.1(b) and/or 8.1(c), then Seller shall pay to Buyer by wire transfer of immediately available United States funds in accordance with Buyer's instructions Three Million Dollars ($3,000,000.00) which payment shall be made within three (3) Business Days after the effective date of such termination.  Seller specifically acknowledges that Buyer's termination of this Agreement due to a default by Seller will result in damages suffered by Buyer, the full nature and extent of which cannot be reasonably ascertained at this time, but which are acknowledged by both Parties to be substantial; accordingly, Seller shall pay the foregoing sum under this Section 8.3(b) to Buyer as liquidated damages as a mutually agreed and reasonable estimate of such damages of Buyer and not as a penalty.

ARTICLE IX

SURVIVAL AND INDEMNIFICATION

9.1

Survival of Representations, Warranties and Covenants.

(a)

The respective representations and warranties of the Parties contained in this Agreement or in any certificate delivered at Closing pursuant to this Agreement shall terminate one (1) year after the Closing Date, except that the representations and warranties set forth (i) in Sections 3.1, 3.2 (other than Section 3.2(c)(iv)), 3.3, 3.7(e), (f) and (g), 3.8, 4.1, 4.2 (other than Section 4.2(c)(iv)) and 4.3 shall terminate three (3) years after the Closing Date, and (ii) in Section 3.9 shall survive for the applicable statutory periods and any extensions thereof.

(b)

The covenants and agreements contained in this Agreement to be performed or complied with after the Closing shall survive in accordance with their respective terms.

(c)

Any claim for indemnification with respect to any of such matters which is not asserted by notice given as herein provided within such specified period of survival may not be pursued.

9.2

Indemnification by Seller.  On and after the Closing, Seller shall be responsible for, shall pay on a current basis, and shall indemnify, save, hold harmless, discharge and release Buyer, all of its Affiliates, its and their successors and permitted assignees, and all of its and their respective stockholders, trustees, directors, officers, employees, agents and representatives (collectively, “Buyer Indemnified Parties”) from and against any and all Damages incurred arising from, based upon, related to or associated with (a) the Excluded Assets or Excluded Liabilities; (b) the breach of, or failure to perform or satisfy, any of the representations, warranties and covenants of Seller set forth in this Agreement including the Ancillary Documents to which Seller is a party; and (c) any fraud or willful misconduct of Seller in connection with this Agreement , including the Ancillary Documents to which Seller is a party.  Notwithstanding anything to the contrary in the foregoing, the right of any Buyer Indemnified Party to assert or otherwise claim indemnification under this Section 9.2 shall irrevocably expire and terminate (i) with respect to indemnity obligations arising out of, and/or relating to, the performance of the Retail Sales Contracts  before the Closing Date, for each such Retail Sales Contract, on the first day of the sixth (6th) month after the expiration or termination of such Retail Sales Contract (without giving effect to any renewal and/or other extension thereof occurring after the Closing Date); (ii) with respect to indemnity obligations related to Section 2.2, until the entire Purchase Price is paid; and (iii) for all other indemnity obligations of whatever nature, the later of the survival period provided for in Section 9.1(a) above, or the first day of the sixth (6th) month after the Closing Date; provided that the foregoing ter mination of Seller's indemnity obligations shall not affect any claims asserted by any Buyer Indemnified Party before the applicable date of expiration or termination.

9.3

Indemnification by Buyer.  After the Closing, Buyer shall assume, be responsible for, shall pay on a current basis, and shall indemnify, save, hold harmless, discharge and release Seller, all of its Affiliates, its and their successors and permitted assigns, and all of their respective stockholders, trustees, directors, officers, employees, agents and representatives (collectively, “Seller Indemnified Parties”) from and against any and all Damages incurred arising from, based upon, related to or associated with (a) the Acquired Assets (for Damages accruing at or after the Closing Date) and the Assumed Liabilities; (b) the breach of, or failure to perform or satisfy any of the representations, warranties and covenants of Buyer set forth in this Agreement including the Ancillary Documents to which Buyer is a party, (c) Buyer’s use of the Marks; and (d) any fraud or willful misconduct of Buyer in connection with this Agreement, including the Ancillary Documents to which Buyer is a party.  Notwithstanding anything to the contrary in the foregoing, the right of any Seller Indemnified Party to assert or otherwise claim indemnification under this Section 9.3 shall irrevocably expire and terminate for each respective Contract on the first day of the sixth (6th) month after such Contract is fully performed or properly terminated in accordance with its terms; provided that the foregoing termination of

Buyer's indemnity obligations shall not affect any claims asserted by any Seller Indemnified Party before such date.

9.4

Limitations on Liability and Available Remedies.  Except with respect to the Administration Agreement entered into pursuant to this Agreement, which shall be subject to the indemnification, remedy and liability provisions set forth therein:

(a)

After the Closing, notice of any assertion by any Buyer Indemnified Party that Seller is liable to any Buyer Indemnified Party in connection with the transactions contemplated hereby pursuant to Section 9.2 must be made by Buyer in writing and must be given to Seller, on or prior to the time of expiration set forth in Section 9.2 above.  No claim for indemnification made after the applicable expiration time will be valid.

(b)

After the Closing, notice of any assertion by any Seller Indemnified Party that Buyer is liable to any Seller Indemnified Party pursuant to Section 9.3 in connection with the transactions contemplated hereby must be given to Buyer on or prior to the time of expiration set forth in Section 9.3 above.  No claim for indemnification made after the applicable expiration time will be valid.

(c)

Any notice provided under this Section 9.4 shall state the facts known to the asserting Party that give rise to such notice in sufficient detail to allow the other Party to evaluate the assertion.

(d)

None of the Seller Indemnified Parties or Buyer Indemnified Parties shall make any claim against an indemnifying party under this Article IX unless and until the aggregate amount of such claims against the indemnifying party exceeds Two Hundred and Fifty Thousand Dollars ($250,000) (the “Threshold”), whereupon a Seller Indemnified Party or Buyer Indemnified Party, as the case may be, may make claims under this Article IX for any and all claimed amounts.  Notwithstanding the foregoing, (i) Damages resulting from any of the following shall be excluded from the Threshold: (A) any claims related to the Excluded Liabilities under Section 2.1(d)(vii), and (B) any claims related to a breach of Section 3.7(g) other than with respect to SENY Contracts, and (ii) net Damages resulting from data errors (other than intentional errors) on any Schedules or Schedule Updates, including any inaccurate, incomp lete and/or corrected data that affects the calculation of any MTM Adjustment, whether discovered before or after the Closing, shall not be the subject of a claim for indemnification by any Seller Indemnified Parties or Buyer Indemnified Parties unless and until the amount of any such claim for such Damages exceeds Five Million Dollars ($5,000,000) whereupon a Seller Indemnified Party or Buyer Indemnified Party, as the case may be, may make claims under this Article IX for any and all claimed amounts arising from such Damages.

(e)

The amount of any Damages for which any of the Buyer Indemnified Parties or Seller Indemnified Parties is entitled to indemnification under this Agreement shall be reduced by any corresponding insurance proceeds received.  Indemnification payments payable pursuant to this Article IX shall not take into account, and shall not be

increased to reflect, the Tax consequences to the indemnified party of the receipt of (or the right to receive) the indemnification payments.

(f)

Except as specifically provided in Section 8.3 with respect to termination damages and Section 9.5 with respect to third party claims, none of the Buyer Indemnified Parties nor the Seller Indemnified Parties shall be entitled to recover from Seller or Buyer, respectively, for any Damages arising under this Agreement or in connection with or with respect to the transactions contemplated in this Agreement, any amount in excess of the actual compensatory damages, court costs and reasonable attorneys fees, suffered by such Party.  Except as specifically provided in Section 8.3 with respect to termination damages and Section 9.5 with respect to third party claims, Buyer on behalf of each of the Buyer Indemnified Parties and Seller on behalf of each of the Seller Indemnified Parties waives any right to recover incidental, indirect, special, exemplary, punitive or consequential damages, including lost revenues or p rofits, even if such damages are foreseeable or the damaged Party has advised the other Party of the possibility of such damages and regardless of whether any such damages are deemed to result from the failure or inadequacy of any exclusive or other remedy.

(g)

If the Closing occurs, except for remedies that are otherwise expressly provided for in this Agreement, the sole and exclusive remedy of each of the Buyer Indemnified Parties and the Seller Indemnified Parties as against Seller and Buyer, respectively, with respect to the purchase and sale of the Acquired Assets and the assumption of the Assumed Liabilities, shall be pursuant to the indemnification provisions of this Article IX.  Any and all (i) claims relating to the representations, warranties, covenants and agreements contained in this Agreement, (ii) other claims pursuant to or in connection with this Agreement, or (iii) other claims relating to the Acquired Assets and the purchase and sale thereof and the assumption of the Assumed Liabilities, in each case, of any Buyer Indemnified Parties against Seller and any Seller Indemnified Parties against Buyer, respectively, shall be subject to the provisions s et forth in this Article IX.  Except for claims made pursuant to the indemnification provisions of this Article IX, Buyer, on behalf of each of the Buyer Indemnified Parties, and Seller, on behalf of each of the Seller Indemnified Parties, shall be deemed to have waived, to the fullest extent permitted under Applicable Law, any right of contribution and any and all rights, claims and causes of action it may have against Seller or any of its Affiliates or Buyer or any of its Affiliates, respectively, arising under or based on any Applicable Law or otherwise, in each case relating to the transactions contemplated by this Agreement.  The Parties acknowledge and agree that this Article IX is intended to limit the Liabilities and remedies of the Parties (and the Buyer Indemnified Parties and the Seller Indemnified Parties) with respect to the transactions contemplated by this Agreement to and against each other, and that nothing in this Article IX is intended to waive or limit rights or obligatio ns of any Party (or the Buyer Indemnified Parties and the Seller Indemnified Parties) as against third parties or rights of assertion with respect thereto.

(h)

No Person entitled to indemnification hereunder or otherwise to damages in connection with or with respect to the transactions contemplated in this Agreement shall settle, compromise or take any other action with respect to any claim, demand, assertion of

Liability or legal proceeding that could materially prejudice or otherwise materially adversely affect the ability of the Party providing such indemnification or potentially liable for such damages to defend or otherwise settle or compromise with respect to such claim, demand, assertion of Liability or legal proceeding without the prior written consent of the Party providing such indemnification, which consent shall not be unreasonably withheld.

(i)

Except as specifically otherwise provided for in Sections 8.3 and 10.13, each Party acknowledges that the payment of money, as limited by the terms of this Agreement, shall be adequate compensation for breach of any representation, warranty, covenant or agreement contained in this Agreement or for any other claim by any Seller Indemnified Parties against Buyer or by any Buyer Indemnified Parties against Seller arising in connection with or with respect to the transactions contemplated in this Agreement.  As the payment of money shall be adequate compensation as set forth above, except as otherwise specified herein, Buyer and Seller waive any right to rescind this Agreement or any of the transactions contemplated hereby.

(j)

Each Person entitled to indemnification hereunder or otherwise to Damages in connection with the transactions contemplated in this Agreement shall use Commercially Reasonable Efforts to mitigate all Damages after becoming aware of any event or circumstance that could reasonably be expected to give rise to any Damages that are indemnifiable or recoverable hereunder or in connection herewith.

(k)

The indemnification, release and assumption provisions provided for in this Agreement shall be applicable whether or not the Damages in question arose solely or in part from the active, passive or concurrent negligence, strict liability or other fault (other than fraud or willful misconduct) of any indemnified party.

(l)

Neither Party shall have recourse whatsoever against any of the trustees, directors, officers,  employees or representatives of the other Party (including for such purposes, the trustees, directors, officers,  employees or representatives of any Affiliate of a Party).  Without limiting the generality of the foregoing, Buyer, on behalf of itself, its Affiliates and the Buyer Indemnified Parties, and Seller, on behalf of itself, its Affiliates and the Seller Indemnified Parties, each hereby fully and irrevocably waives any right, claim or entitlement whatsoever against such trustees, directors, officers,  employees or representatives relating to any and all Damages suffered or incurred by any of them arising from, based upon, related to, or associated with this Agreement.

9.5

Third Party Claims Procedures.  Promptly after receipt by either Party of any third party claim or notice of the commencement of any third party action or administrative or legal proceeding or investigation against such Party or any of its Affiliates, its and their successors and permitted assigns, or any of their respective stockholders, trustees, directors, officers, employees, agents and representatives (collectively, the “Indemnified Person”) to which the indemnity provided for in this Article IX may apply, such Party shall notify the other Party (the “Indemnifying Party”) of such fact.  The Indemnifying Party shall have the right to assume the defense thereof with counsel designated by such Indemnifying Party and reasonably satisfactory

to the Indemnified Person; provided, however, that if the defendants in any such action include both the Indemnified Person and the Indemnifying Party and the Indemnified Person shall have reasonably concluded that there may be legal defenses available to it and/or other Indemnified Persons which are different from or additional to those available to the Indemnifying Party, the Indemnified Person or Persons shall have the right to select separate counsel to assert such legal defenses and to otherwise participate in the defense of such action on behalf of such Indemnified Person or Persons and in such event the Indemnifying Party shall pay the reasonable cost of such separate counsel; provided, further if the claim is one that cannot by its nature be defended solely by the Indemnifying Party, the Indemnified Person shall make available all information and assistance reasonably available and necessary for the defense of the third party action as the Indemnifying Party may reasonably request at the expense of the Indemnifying Party.  The Indemnified Person shall be entitled, at its expense, to participate in any action, suit or proceeding, the defense of which has been assumed by the Indemnifying Party.  Notwithstanding the foregoing, the Indemnifying Party shall not be entitled to assume and control the defense of any such action, suit or proceedings if and to the extent that, in the opinion of the Indemnified Person and its counsel, such action, suit or proceeding involves the potential imposition of criminal liability on the Indemnified Person or a conflict of interest between the Indemnified Person and the Indemnifying Party, and in such event the Indemnifying Party shall pay the reasonable expenses of the Indemnified Person in such defense.  The Indemnifying Party will not have the right to settle any such action, suit or proceeding without the consent of the Indemnified Person; provided, however, that any such se ttlement involving non-monetary obligations of the Indemnified Person, or otherwise having a direct effect upon its continuing operations shall be subject to the written consent of the Indemnified Person, which consent shall not be unreasonably withheld, conditioned or delayed.  

9.6

Waiver of Representations.

(a)

THE EXPRESS REPRESENTATIONS OF SELLER CONTAINED IN THIS AGREEMENT, THE ADMINISTRATION AGREEMENT AND THE ANCILLARY DOCUMENTS TO WHICH SELLER IS A PARTY ARE EXCLUSIVE AND ARE IN LIEU OF, ANY OTHER REPRESENTATION OR WARRANTY WITH RESPECT TO THE ACQUIRED ASSETS OR THE ASSUMED LIABILITIES OR THE STATUS OF EITHER OF THEM.  WITHOUT LIMITING THE GENERALITY OF THE FOREGOING, SELLER MAKES NO REPRESENTATION, WARRANTY OR UNDERTAKING WHATSOEVER WITH RESPECT TO (i) THE INFORMATION MEMORANDUM ISSUED BY SELLER'S FINANCIAL ADVISOR IN CONNECTION WITH THE TRANSACTIONS CONTEMPLATED UNDER THIS AGREEMENT; AND (ii) INFORMATION DISCLOSED TO BUYER IN CONNECTION WITH THE EFFORTS OF SELLER AND ITS ADVISORS TO SELL THE RETAIL BUSINESS, INCLUDING THE CONTENTS OF THE ELECTRONIC DATA ROOM MAINTAINED AS PART OF THE SALE PROCESS, OR AS DISTRIBUTED TO BUYER AS PART OF BUYER’S DUE DILIGENCE.

(b)

EXCEPT TO THE EXTENT OF THE EXPRESS REPRESENTATIONS AND WARRANTIES OF SELLER CONTAINED IN THIS AGREEMENT, THE ADMINISTRATION AGREEMENT AND THE ANCILLARY DOCUMENTS TO

WHICH SELLER IS A PARTY, SELLER EXPRESSLY DISCLAIMS AND NEGATES, AND BUYER HEREBY WAIVES, ANY LIABILITY OR RESPONSIBILITY OF SELLER AND ITS AFFILIATES FOR, (i) ALL OTHER REPRESENTATIONS AND WARRANTIES, EXPRESS, IMPLIED OR STATUTORY (INCLUDING ANY WARRANTIES UNDER THE UNIFORM COMMERCIAL CODE), AND (ii) ANY STATEMENT OR INFORMATION ORALLY OR IN WRITING MADE OR COMMUNICATED TO BUYER, INCLUDING ANY OPINION, INFORMATION, ADVICE, FINANCIAL PROJECTIONS OR FORECASTS RELATING TO THE RETAIL BUSINESS OR THE CONTRACTS, INCLUDING PROJECTIONS REGARDING THE RETAIL LOAD SERVED BY  SELLER OR SENY UNDER THE RETAIL SERVICE CONTRACTS AND SENY CONTRACTS, IN EACH CASE THAT MAY HAVE BEEN PROVIDED TO BUYER BY ANY OFFICER, DIRECTOR, EMPLOYEE, AGENT, CONSULTANT OR REPRESENTATIVE OF SELLER, SENY, OR ANY OTHER AGENT, CONSULTANT OR REPRESENTATIVE, AND (iii) ANY OTHER INFORMATION WHETHER PUBLICLY AVAILABLE OR DEVELOPED PRIVATELY AN D OBTAINED BY BUYER, IN EACH CASE, IN CONNECTION WITH THE TRANSACTIONS CONTEMPLATED IN THIS AGREEMENT, THE ADMINISTRATION AGREEMENT OR THE ANCILLARY DOCUMENTS.  EXCEPT TO THE EXTENT OF THE EXPRESS REPRESENTATIONS AND WARRANTIES OF BUYER CONTAINED IN THIS AGREEMENT, THE ADMINISTRATION AGREEMENT AND THE ANCILLARY DOCUMENTS TO WHICH BUYER IS A PARTY, BUYER EXPRESSLY DISCLAIMS AND NEGATES, AND SELLER HEREBY WAIVES, ANY LIABILITY OR RESPONSIBILITY OF BUYER AND ITS AFFILIATES FOR, (A) ALL OTHER REPRESENTATIONS AND WARRANTIES, EXPRESS, IMPLIED OR STATUTORY, AND (B) ANY STATEMENT OR INFORMATION ORALLY OR IN WRITING MADE OR COMMUNICATED TO SELLER, INCLUDING ANY OPINION, INFORMATION OR ADVICE THAT MAY HAVE BEEN PROVIDED TO SELLER BY ANY OFFICER, DIRECTOR, EMPLOYEE, AGENT, CONSULTANT OR REPRESENTATIVE OF BUYER, OR ANY OTHER AGENT, CONSULTANT OR REPRESENTATIVE, IN EACH CASE, IN CONNECTION WITH THE TRANSACTIONS CONTEMPLATED IN THIS AGREEMENT OR THE ADMINISTRATION AGREEMENT.

(c)

WITH RESPECT TO ANY FINANCIAL PROJECTION OR FORECAST DELIVERED BY OR ON BEHALF OF SELLER OR SENY TO BUYER, OR OTHER PUBLIC OR PRIVATE INFORMATION OBTAINED BY BUYER, BUYER ACKNOWLEDGES AND AGREES BY ITS EXECUTION OF THIS AGREEMENT THAT (A) THERE ARE UNCERTAINTIES INHERENT IN ATTEMPTING TO MAKE SUCH PROJECTIONS AND FORECASTS, AND BUYER IS FAMILIAR WITH SUCH UNCERTAINTIES; (B) BUYER IS TAKING FULL RESPONSIBILITY FOR MAKING ITS OWN EVALUATION OF ALL SUCH PROJECTIONS AND FORECASTS SO FURNISHED TO IT OR OTHER PUBLIC OR PRIVATE INFORMATION OBTAINED BY BUYER; AND (C) BUYER SHALL HAVE NO CLAIM AGAINST ANY OF SELLER, SENY AND/OR ANY OF THEIR RESPECTIVE OFFICERS, DIRECTORS, EMPLOYEES, TRUSTEES, STOCKHOLDERS, AFFILIATES OR REPRESENTATIVES WITH RESPECT TO

SUCH PROJECTIONS OR FORECASTS OR SUCH OTHER PUBLIC OR PRIVATE INFORMATION.

(d)

EXCEPT TO THE EXTENT OF THE EXPRESS REPRESENTATIONS AND WARRANTIES OF SELLER CONTAINED IN THIS AGREEMENT, THE ADMINISTRATION AGREEMENT AND THE ANCILLARY DOCUMENTS TO WHICH SELLER IS A PARTY, SELLER EXPRESSLY DISCLAIMS AND NEGATES, AND BUYER HEREBY WAIVES, ANY LIABILITY OR RESPONSIBILITY FOR, ANY WARRANTY OR REPRESENTATION, EXPRESS OR IMPLIED, AS TO THE QUALITY, MERCHANTABILITY, FITNESS FOR A PARTICULAR PURPOSE, CONFORMITY TO SAMPLES, OR CONDITION OF ANY ACQUIRED ASSET OR ANY PART THEREOF.

(e)

 EXCEPT AS OTHERWISE PROVIDED IN THIS AGREEMENT, BUYER ACKNOWLEDGES THAT THE CONTRACTS DO NOT INCLUDE SUFFICIENT SOURCING AGREEMENTS TO PROVIDE FOR THE PROVISION OF GAS OR POWER UNDER ALL OF THE RETAIL SERVICE CONTRACTS AND SENY CONTRACTS FOR THE PROVISION OF RETAIL GAS AND POWER, AND THAT SUCH SHORTAGE IS REFLECTED IN THE PURCHASE PRICE.  BUYER FURTHER ACKNOWLEDGES THAT IT HAS ASSUMED ANY RISKS ASSOCIATED WITH CHANGES IN THE MARKET FOR GAS AND POWER THAT MAY OCCUR BETWEEN THE AGREEMENT DATE AND THE CLOSING DATE.

ARTICLE X

MISCELLANEOUS

10.1

Setoff Rights and Limitations.  Except as provided in the next sentence, neither Party shall have the right to setoff, net, off-set, or otherwise combine accounts or obligations

Owed to the other Party under any other agreement(s), instrument(s) or undertaking(s), against any amounts Owed by such Party to the other Party under this Agreement or the Administration Agreement.  Each Party shall have the right to setoff, net, off-set or otherwise combine amounts Owed after the Closing Date to the other Party under this Agreement or the Administration Agreement against any amounts Owed by such other Party under this Agreement and in the Administration Agreement.  For purposes of this Section 10.1, “Owed” shall mean any amounts owed or otherwise accrued and payable (regardless of whether such amounts have been or could be invoiced), except for amounts disputed in good faith, as of the applicable date of determination and regardless of whether arising prior to or after the Agreement Date.  Each Party represents and acknowledges that the prohibition set forth in this Section 10. 1 is an integral part of this Agreement and the Administration Agreement and that without such prohibition the Parties would not be willing to enter into this Agreement or the Administration Agreement.

10.2

Notice.  All notices, requests, statements or payments shall be made as specified below.  All notices are required to be in writing and shall be delivered by letter, facsimile or other documentary form.  Notice by facsimile or hand delivery shall be deemed to have been received by the close of the Business Day on which it was transmitted or hand delivered (unless transmitted or hand delivered after close of the Business Day in which case it shall be deemed received at the close of the next Business Day).  Notice by overnight mail or courier shall be deemed to have been received two (2) Business Days after it was sent.  Notice by registered or certified mail, postage prepaid, return receipt requested shall be deemed to have been received five (5) Business Days after it was sent.  A Party may change its addresses by providing notice of same in ac cordance herewith.  Notices shall be sent as follows:

If to Seller, to:

Select Energy, Inc.

107 Selden Street

Berlin, CT 06037-1616

Phone:

(860) 665-2702

Fax:

(860) 665-2017

Attn:

President

With a copy to:

Northeast Utilities Service Company

107 Selden Street

Berlin, CT 06037-1616

Phone:  (860) 665-3181

Fax:  

 (860) 665-5504

Attn:  General Counsel

If to Buyer, addressed to:

Amerada Hess Corporation

One Hess Plaza

Woodbridge, NJ  07095

Phone:   (732) 750-6650

Fax:

  (732) 750-6670

Attn:   

  Senior Vice President, Energy Marketing

With a copy to:

Amerada Hess Corporation

One Hess Plaza

Woodbridge, NJ  07095

Phone:   (732) 750-7123

Fax:

  (732) 750-6944

Attn:      Associate General Counsel, Marketing and Refining

10.3

No Third Party Beneficiaries.  Nothing in this Agreement or any Schedules will provide any benefit to any third party or entitle any third party to any claim, cause of action, remedy or right of any kind, it being the intent of the Parties that this Agreement will not be construed as a third-party beneficiary contract.  As used in this Section 10.3, the term “third party” does not include Affiliates of the Parties.

10.4

Governing Law.  This Agreement and the rights and duties of the Parties hereunder will be governed by and construed, enforced and performed in accordance with the law of the State of New York, without giving effect to principles of conflicts of laws.

10.5

Entire Agreement.  This Agreement, the Administration Agreement and the Ancillary Documents and documents incorporated by reference herein, including the Exhibits and Schedules and the Confidentiality Agreement, contain the entire agreement between the Parties with respect to the subject matter hereof and there are no agreements, understandings, representations, or warranties between the Parties other than those set forth or referred to herein or therein; provided that Buyer's undertakings under the Confidentiality Agreement relating to the Acquired Assets shall terminate on the Closing Date.

10.6

Waiver.  No waiver by any Party of any covenant, condition or of default by the other Party in the performance of any of the provisions of this Agreement will be construed as a waiver of any other covenant, condition or default hereunder whether of a like kind or different nature.

10.7

Amendments and Extensions.  No amendment, modification or change to this Agreement will be enforceable unless reduced to writing and executed by duly authorized representatives of both Parties or, in the case of a waiver or consent, by the Party waiving compliance or giving consent.  The Parties expressly agree that any dates, deadlines and time periods recited herein are subject to extension by mutual written agreement of the Parties.

10.8

Severability.  If any provision hereof is declared or rendered unlawful by any Governmental Entity with jurisdiction over the Parties, or deemed unlawful due to a statutory change, the Parties will negotiate an equitable adjustment to the provisions of this Agreement with a view to effecting, to the extent possible, the original purpose and intent of this Agreement, and the validity and enforceability of the remaining provisions of this Agreement shall not be affected thereby.

10.9

Counterparts; Facsimile Signatures.  This Agreement may be executed in several counterparts, including through facsimile signatures, each of which is an original and all of which constitute one and the same agreement.

10.10

Joint Negotiation and Drafting.  This Agreement shall be considered for all purposes as prepared through the joint efforts of the Parties and shall not be construed against one Party or the other as a result of the preparation, submission or other event of negotiation, drafting or execution hereof.  The captions for the Articles and Sections contained in this Agreement have been inserted for convenience only and form no part of this Agreement and shall not be deemed to affect the meaning or construction of any of the covenants, agreements, conditions or terms of this Agreement.

10.11

Assignment and Binding Effect.  Neither Party may assign this Agreement or its rights hereunder without the prior written consent of the other Party, which consent shall not be unreasonably withheld, conditioned or delayed; provided that Seller may assign this Agreement to an Affiliate so long as the Seller Guaranty continues for the benefit of Buyer and is not extinguished.  Assignments or transfers not in compliance with this Section 10.11 shall be void ab initio.  This Agreement shall inure to the benefit of and be binding upon the Parties and their respective successors and permitted assigns.

10.12

Interpretation.  In this Agreement, words importing the singular include the plural and vice versa.  Except where otherwise expressly provided or unless the context otherwise necessarily requires: (a) reference to Applicable Law shall mean such Applicable Law in effect as amended or modified as of the date on which the reference is made, or performance and/or compliance is required; (b) reference to a given agreement or instrument is a reference to that agreement or instrument as originally executed, and as modified, amended, supplemented and restated through the date as of which reference is made to that agreement or instrument or performance is required under that agreement or instrument; (c) "includes", "including" or any other variant thereof means "including, without limitation,"; (d) the phrase "and/or" shall be deemed to mean the words both preceding and following such phrase, or either of them; (e) reference to a Person includes its heirs, executors, administrators, successors and permitted assigns; (f) unless otherwise indicated, whenever this Agreement refers to a number of days, such number shall refer to calendar days; and (g) any pronoun includes the corresponding

masculine, feminine or neuter forms.  The words "will" and "shall" are used interchangeably throughout this Agreement; the use of either connotes a mandatory requirement; and the use of one or the other will not mean a different degree of right or obligation for either Party.

10.13

Confidentiality.

(a)

Unless otherwise agreed by the Parties, the specific terms of this Agreement (including the Purchase Price), the Administration Agreement (including the Administration Fee) and the Ancillary Documents shall not be disclosed to any Person not employed or retained by such Party, except that such information may be disclosed to:

(i)

any of the receiving Party’s or such Party’s Affiliates’, directors, trustees, officers, employees and agents and advisors (collectively, its “Representatives”) who require access to such information in connection with this Agreement or the transactions contemplated hereby or for the conduct of the receiving Party’s ordinary course of business.  Each of the Parties agree that any of its Representatives to whom such information is disclosed will be informed of the confidential or proprietary nature thereof and of the receiving Party’s obligations under this Agreement and that each Party shall be responsible for any use or disclosure of such information by any of its Representatives; and

(ii)

as may be required or appropriate in response to any summons, subpoena, request from a Governmental Entity, or otherwise in connection with any litigation or arbitration, or to comply with any Applicable Law, including a regulatory request or requirement, or accounting disclosure rule or standard (hereafter, a “Required Disclosure”).  A Party seeking to disclose information as a Required Disclosure shall, to the extent practical or permissible, notify the other Party prior to making such disclosure in order to permit the other Party an opportunity to seek an appropriate protective order or grant a waiver of compliance with the provisions of this Agreement; provided that Buyer acknowledges that Seller and its Affiliates shall disclose the transactions contemplated under this Agreement in compliance with Applicable Laws pertaining to securities issued by the Seller Guarantor, and Buyer hereby irre vocably consents to such disclosure only to the extent that such disclosure is required by Applicable Law.  Notwithstanding the foregoing, either Party will be permitted to disclose such information or any portion thereof without notice to the other Party upon the request of any Governmental Entity having or claiming to have authority to regulate or oversee any aspect of such Party’s business or that of its Affiliates, provided that the Party disclosing such information uses reasonable efforts to advise such Governmental Entity of the confidential nature of such information and request confidential treatment (if available) for such information.

(b)

Nothing in this Section 10.13 shall restrict (i) either Party from pursuing and obtaining all regulatory approvals required to consummate the transactions contemplated under this Agreement; provided that that the Party disclosing information uses reasonable efforts to advise the applicable Governmental Entity of the confidential

nature of such information and request confidential treatment (if available) for such information Buyer; (ii) the issuance of notices to Customers as contemplated by Section 6.19; and (iii) the ability of either Party to perform its respective obligations under the Administration Agreement; provided that if such performance requires the disclosure of all or a portion of any documents, including the Administration Agreement, the Party seeking to disclose such documentation shall redact the same to the fullest extent possible.

(c)

The Parties acknowledge that the disclosing Party would not have an adequate remedy under Applicable Law and would be irreparably harmed if the recipient breached this Section 10.13; accordingly, without prejudice to the rights and remedies otherwise available, the disclosing Party shall be entitled to equitable relief by way of injunction to prevent breaches of this Section 10.13 by the receiving Party or any other recipients of such confidential information.

(d)

Notwithstanding the foregoing, each Party (and each Representative of such Party for so long as they remain a Representative) may disclose to any and all Persons, without limitation of any kind, the Tax treatment and Tax structure of the transaction contemplated by this Agreement and all materials of any kind (including opinions or other analyses) that are provided to such Party relating to such Tax treatment or Tax structure.  Nothing in this Agreement or any other agreement between the Parties, express or implied, shall be construed as limiting in any way the ability of either Party to consult with any Tax advisor (including a Tax advisor independent from all other entities involved in the transaction contemplated by this Agreement) regarding the Tax treatment or Tax structure of the transaction contemplated by this Agreement.

10.14

Waiver of Jury Trial.  Each Party hereby irrevocably waives, to the fullest extent permitted by law, any and all right to a trial by jury in any action, suit or other legal proceeding based on, arising out of or relating to this Agreement or the transactions contemplated herein.  

10.15

Incorporation of Exhibits and Schedules.  The Exhibits and Schedules identified in this Agreement are incorporated herein by reference and made a part hereof.

10.16

Good Faith Covenant.  The Parties agree that their actions and dealings with each other shall be subject to an express covenant of good faith and fair dealing.

10.17

Dispute Resolution.

(a)

Negotiation between Executives.  The Parties shall attempt in good faith to resolve any dispute arising out of or relating to this Agreement, promptly by negotiation between executives who have authority to settle the controversy and who are at a higher level of management than the person(s) with direct responsibility for administration of this Agreement.  Any Party may give the other Party written notice of any dispute not resolved in the normal course of business.  Such notice shall include: (i) a statement of that Party’s position and a summary of arguments supporting that position; and (ii) the name and title of the executive who will be representing that Party and of any other person who will accompany the executive.  Within fifteen (15) days after delivery of the notice, the

receiving Party shall respond with: (A) a statement of that Party’s position and a summary of arguments supporting that position; and (B) the name and title of the executive who will represent that Party and of any other person who will accompany the executive.  Within thirty (30) days after delivery of the initial notice, the executives of both Parties shall meet at a mutually acceptable time and place, and thereafter as often as they reasonably deem necessary, to attempt to resolve the dispute.  All reasonable requests for information made by one Party to the other will be honored.  All negotiations pursuant to this clause are confidential and shall be treated as compromise and settlement negotiations for purposes of applicable rules of evidence.

(b)

Mediation.  If the dispute has not been resolved by negotiation within forty-five (45) days of the disputing Party’s notice, or if the Parties failed to meet within thirty (30) days following delivery of such notice, the Parties shall endeavor to settle the dispute by mediation under the then current CPR Mediation Procedure; provided, however, that if one Party fails to participate as provided herein, the other Party can initiate mediation prior to the expiration of the forty-five (45) days.  Unless otherwise agreed, the Parties will select a mediator from the CPR Panels of Distinguished Neutrals.  The place of mediation shall be in a neutral location agreed to by the Parties.

(c)

Arbitration.  If the dispute has not been resolved by mediation within ninety (90) days of the initiation of such procedure, such dispute shall be finally resolved by arbitration in accordance with the then current CPR Rules for Non-Administered Arbitration by a sole arbitrator, for disputes involving amounts in the aggregate under Three Million Dollars ($3,000,000), or three (3) arbitrators, for disputes involving amounts in the aggregate equal to or greater than Three Million Dollars ($3,000,000), of whom each Party shall designate one in accordance with the “screened” appointment procedure provided in Rule 5.4, with the third arbitrator selected pursuant to CPR Rules 5 and 6; provided, however, that if either Party will not participate in a non-binding procedure, the other may initiate arbitration before expiration of the above period.  The arbitration shall be governed by the Federa l Arbitration Act, 9 U.S.C. §§ 1-16, and judgment upon the award rendered by the arbitrator(s) may be entered by any court having jurisdiction thereof.  The place of arbitration shall be Hartford, Connecticut.

(d)

Powers of Arbitrators.  The arbitrator(s) are not empowered to award damages in excess of compensatory damages (including liquidated damages specified in Section 8.3) and each Party expressly waives and foregoes any right to punitive, exemplary or similar damages unless a statute requires that compensatory damages be increased in a specified manner.  All costs of the arbitration shall be paid equally by the Parties, unless the award shall specify a different division of the costs.  Each Party shall be responsible for its own expenses, including attorneys’ fees.

(e)

Compelled Arbitration.  The Parties shall proceed in good faith to conclude the arbitration proceeding as quickly as reasonably possible.  If a Party refuses to participate in an arbitration proceeding as required by this Agreement, the other Party may petition any Governmental Entity having proper jurisdiction for an order directing the refusing

Party to participate in the arbitration proceeding.  All costs and expenses incurred by the petitioning Party in enforcing such participation will be paid by the refusing Party.

 [Signature Page Follows]

IN WITNESS WHEREOF, the Parties have signed this Agreement as of the Agreement Date.

SELLER:

SELECT ENERGY, INC.

By:  /s/ William J. Quinlan

Name: William J. Quinlan

Title: Chief Operating Officer

BUYER:

AMERADA HESS CORPORATION

By:  /s/ John A. Gartman

Name: John A. Gartman

Title: Senior Vice-President - Energy Marketing

EX-15

Exhibit 15

May 5, 2006

Northeast Utilities

107 Selden Street

Berlin, CT 06037

We have made a review, in accordance with the standards of the Public Company Accounting Oversight Board (United States), of the unaudited interim financial information of Northeast Utilities and subsidiaries (the "Company") for the periods ended March 31, 2006 and 2005, as indicated in our report dated May 5, 2006 (which report includes an explanatory paragraph related to significant charges recorded in connection with the Company’s decision to exit certain business lines, and the presentation of certain components as discontinued operations); because we did not perform an audit, we expressed no opinion on that information.

We are aware that our report referred to above, which is included in your Quarterly Report on Form 10-Q for the quarter ended March 31, 2006, is incorporated 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 333-106008 on Forms S-8 of Northeast Utilities.

We also are aware that the aforementioned report, pursuant to Rule 436(c) under the Securities Act of 1933, is not considered a part of the Registration Statement prepared or certified by an accountant or a report prepared or certified by an accountant within the meaning of Sections 7 and 11 of that Act.

/s/

Deloitte & Touche LLP

Deloitte & Touche LLP

Hartford, Connecticut

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 quarterly report on Form 10-Q 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:  May 5, 2006

/s/	Charles W. Shivery
	Charles W. Shivery
	Chairman, President and 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 quarterly report on Form 10-Q 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:  May 5, 2006

/s/	David R. McHale
	David R. McHale
	Senior Vice President and Chief Financial Officer
	(Principal Financial 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 quarterly report of Northeast Utilities (the registrant) on Form 10-Q for the period ending March 31, 2006 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
	Charles W. Shivery
	Chairman, President and Chief Executive Officer

/s/	David R. McHale
	David R. McHale
	Senior Vice President and Chief Financial Officer

Date:  May 5, 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-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 quarterly report on Form 10-Q 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:  May 5, 2006

/s/	Cheryl W. Grisé
	Cheryl W. Grisé
	Chief Executive Officer
	(Principal Executive Officer)

EX-31

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 quarterly report on Form 10-Q 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:  May 5, 2006

/s/	David R. McHale
	David R. McHale
	Senior Vice President and Chief Financial Officer
	(Principal Financial 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 quarterly report of The Connecticut Light and Power Company (the registrant) on Form 10-Q for the period ending March 31, 2006 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
	Cheryl W. Grisé
	Chief Executive Officer

/s/	David R. McHale
	David R. McHale
	Senior Vice President and Chief Financial Officer

Date:  May 5, 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-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 quarterly report on Form 10-Q 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:  May 5, 2006

/s/	Cheryl W. Grisé
	Cheryl W. Grisé
	Chief Executive Officer
	(Principal Executive Officer)

EX-31

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 quarterly report on Form 10-Q 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:  May 5, 2006

/s/	David R. McHale
	David R. McHale
	Senior Vice President and Chief Financial Officer
	(Principal Financial 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 quarterly report of Public Service Company of New Hampshire (the registrant) on Form 10-Q for the period ending March 31, 2006 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
	Cheryl W. Grisé
	Chief Financial Officer

/s/	David R. McHale
	David R. McHale
	Senior Vice President and Chief Financial Officer

Date:  May 5, 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-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 quarterly report on Form 10-Q 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:  May 5, 2006

/s/	Cheryl W. Grisé
	Cheryl W. Grisé
	Chief Executive Officer
	(Principal Executive Officer)

EX-31

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 quarterly report on Form 10-Q 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:  May 5, 2006

/s/	David R. McHale
	David R. McHale
	Senior Vice President and Chief Financial Officer
	(Principal Financial 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 quarterly report of Western Massachusetts Electric Company (the registrant) on Form 10-Q for the period ending March 31, 2006 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
	Cheryl W. Grisé
	Chief Executive Officer

/s/	David R. McHale
	David R. McHale
	Senior Vice President and Chief Financial Officer

Date:  May 5, 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.