NU's March 2006 Form 10-Q

10-Q 1 march2006form10qdraft5edgar.htm NU's March 2006 Form 10-Q

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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


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

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

iii


	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

NORTHEAST UTILITIES AND SUBSIDIARIES


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.


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.


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.


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.

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)

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (All Companies)

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.

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 servicing of certain CL&P accounts receivable.

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.

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.

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


	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

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.

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.

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.

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.

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."

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.

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.

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

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.

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.

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


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.

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 accounting 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.

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.

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:


	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

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

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.

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.

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,

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

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.

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.

COMMITMENTS AND CONTINGENCIES

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

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. 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.

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.

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.

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.

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.

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, Bechtel 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 will become effective upon approval from the FERC, but should not materially affect the level of 2006 charges.

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 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.

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.

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

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)

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.

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.

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:


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.

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,

"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


	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


	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

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.

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

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES


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.


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.


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.


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.

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PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES


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.


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.


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.


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.

This Page Intentionally Left Blank

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY


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.


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.


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.


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.

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 decline 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

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 permanent 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:


	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.

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.

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 businesses 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 divestiture 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.

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.

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 companies (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 approximately $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.

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.

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.

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 cost 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.

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 expected 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.

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 request for proposals. If such utility bid was accepted, then the unit after five years would have to be a) sold, b) have its capacity sold, or c) both, provided that the DPUC could waive these requirements. The 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 the 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 1and June 1of each year. NU's RNS rate is reset on June 1 of each year. On January 1, 2006, NU's LNS rates increased NU wholesale revenues by approximately $18 million on an annualized basis. The LNS and RNS rates to be effective on June 1, 2006 have not yet been determined. Additionally, NU's LNS tariff provides for a true-up to actual costs, which ensures that

NU's transmission business recovers its total transmission revenue requirements, including the allowed ROE. At 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 generators from December 1, 2006 through May 31, 2010 without regard to location in New England, and annual forward capacity auctions, beginning in 2008, for the 1-year period ending on May 31, 2011, and annually thereafter. The settlement agreement must be approved by the FERC, and the parties have asked for a decision by June 30, 2006. 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 established 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.

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.

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.

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.

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:

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.

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.

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, Bechtel has withdrawn from the FERC 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.

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.

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

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.

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


	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 settlement 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.

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, either 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

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 expected 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 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 asserted. 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 company 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.

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 developments or circumstances occurring after the statement is made.

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

RESULTS OF OPERATIONS - 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

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.

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.

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.

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.

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.

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), partially 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.

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.

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.

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.

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.

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 fixed-rate debt.

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

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

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

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

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 officer 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.

PART II. OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

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 certiorari 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 exposure 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.

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

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

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

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

Until Select Energy disposes of its retail electric and gas marketing business, it will be subject to a number of ongoing risks which are similar, though of a lesser magnitude, to those of the wholesale marketing business. Fluctuations in prices, fuel costs, competitive conditions, regulations, weather, transmission costs, lack of market liquidity, plant outages and other factors can all impact the retail business adversely from time to time. Extreme price volatility in the third quarter 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

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 Environmental 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.

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.

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

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

Deloitte & Touche LLP Letter Regarding Unaudited Financial Information

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

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)

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

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)

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

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)

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

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

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)

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)