Western Massachusetts Electric 10-Q 2007 Q1 Quarterly report

____________________________________________________________________________________

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 EndedMarch 31, 2007
	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, 2007
Northeast Utilities Common stock, $5.00 par value	154,553,804 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

Northeast Utilities holds all of the 6,035,205 shares, 301 shares, and 434,653 shares of the outstanding common stock of The Connecticut Light and Power Company, Public Service Company of New Hampshire and Western Massachusetts Electric Company, respectively.

Public Service Company of New Hampshire and Western Massachusetts Electric Company meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and therefore filed their 2006 Form 10-K with the reduced disclosure format specified in General Instruction I(2) to such Form 10-K.

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	Mt. Tom generating plant
NGC	Northeast Generation Company
NGS	Northeast Generation Services Company
NU or the company	Northeast Utilities
NU Enterprises	At March 31, 2007, NU Enterprises, Inc., is comprised of Select Energy, NGS, the remaining contracts of the former Woods Electrical Co., Inc. (Woods Electrical - Other), the E.S. Boulos Company (Boulos), the Connecticut division of SECI (SECI-CT) and NU Enterprises parent.  For further information, see Note 10, "Segment Information," to the condensed consolidated financial statements.
PSNH	Public Service Company of New Hampshire
Regulated companies	NU's regulated companies, comprised of the electric distribution and transmission segments of CL&P, PSNH, WMECO, the generation segment of PSNH and Yankee Gas, which is a natural gas local distribution company.  For further information, see Note 10 "Segment Information," to the condensed consolidated financial statements.
SECI	Select Energy Contracting, Inc.
Select Energy	Select Energy, Inc.
SESI	Select Energy Services, Inc.
WMECO	Western Massachusetts Electric Company
Yankee	Yankee Energy System, Inc.
Yankee Gas	Yankee Gas Services Company
REGULATORS:
DPU	Massachusetts Department of Public Utilities (formerly the Massachusetts Department of Telecommunications and Energy (DTE)
DPUC	Connecticut Department of Public Utility Control
FERC	Federal Energy Regulatory Commission
NHPUC	New Hampshire Public Utilities Commission
SEC	Securities and Exchange Commission

i

OTHER:
AFUDC	Allowance For Funds Used During Construction
CTA	Competitive Transition Assessment
EPS	Earnings Per Share
ES	Default Energy Service
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
LOCs	Letters of Credit
MW	Megawatt/Megawatts
NU 2006 Form 10-K	The Northeast Utilities and Subsidiaries combined 2006 Form 10-K as filed with the SEC
NYMEX	New York Mercantile Exchange
OCC	Connecticut Office of Consumer Counsel
Regulatory ROE	The average cost of capital method for calculating the return on equity related to the distribution and generation segments excluding the wholesale transmission segment.
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
TSO	Transitional Standard Offer

ii

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

TABLE OF CONTENTS

	Page
PART I - FINANCIAL INFORMATION
ITEM 1 -Condensed Consolidated Financial Statements for the Following Companies:
Northeast Utilities and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited) - March 31, 2007 and December 31, 2006	2
Condensed Consolidated Statements of Income/(Loss) (Unaudited) - Three Months Ended March 31, 2007 and 2006	4
Condensed Consolidated Statements of Cash Flows (Unaudited) - Three Months Ended March 31, 2007 and 2006	5
Notes to Condensed Consolidated Financial Statements (Unaudited - all companies)	6
Report of Independent Registered Public Accounting Firm	27
The Connecticut Light and Power Company and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited) - March 31, 2007 and December 31, 2006	30
Condensed Consolidated Statements of Income (Unaudited) - Three Months Ended March 31, 2007 and 2006	32
Condensed Consolidated Statements of Cash Flows (Unaudited) - Three Months Ended March 31, 2007 and 2006	33
Public Service Company of New Hampshire and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited) - March 31, 2007 and December 31, 2006	36
Condensed Consolidated Statements of Income (Unaudited) - Three Months Ended March 31, 2007 and 2006	38
Condensed Consolidated Statements of Cash Flows (Unaudited) - Three Months Ended March 31, 2007 and 2006	39
Western Massachusetts Electric Company and Subsidiary
Condensed Consolidated Balance Sheets (Unaudited) - March 31, 2007 and December 31, 2006	42
Condensed Consolidated Statements of Income (Unaudited) - Three Months Ended March 31, 2007 and 2006	44
Condensed Consolidated Statements of Cash Flows (Unaudited) - Three Months Ended March 31, 2007 and 2006	45

iii

	Page
ITEM 2 - Management's Discussion and Analysis of Financial Condition and Results of Operations for the following  companies:
Northeast Utilities and Subsidiaries		46
The Connecticut Light and Power Company and Subsidiaries		63
Public Service Company of New Hampshire and Subsidiaries		66
Western Massachusetts Electric Company and Subsidiary		68
ITEM 3 -Quantitative and Qualitative Disclosures About Market Risk		70
ITEM 4 -Controls and Procedures		71
PART II - OTHER INFORMATION
ITEM 1 - Legal Proceedings		72
ITEM 1A - Risk Factors		72
ITEM 2 - Unregistered Sales of Equity Securities and Use of Proceeds		72
ITEM 6 - Exhibits		72
SIGNATURES		74

iv

NORTHEAST UTILITIES AND SUBSIDIARIES

1

NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,	December 31,
	2007	2006
	(Thousands of Dollars)
ASSETS
Current Assets:
Cash and cash equivalents	$                214,730	$                481,911
Special deposits	29,850	48,524
Investments in securitizable assets	397,168	375,655
Receivables, less provision for uncollectible
accounts of $20,689 in 2007 and $22,369 in 2006	362,721	361,201
Unbilled revenues	80,728	88,170
Taxes receivable	5,494	-
Fuel, materials and supplies	139,317	173,882
Marketable securities - current	64,464	67,546
Derivative assets - current	117,716	88,857
Prepayments and other	45,955	45,305
	1,458,143	1,731,051
Property, Plant and Equipment:
Electric utility	7,162,936	7,129,526
Gas utility	859,649	858,961
Other	310,555	299,389
	8,333,140	8,287,876
Less: Accumulated depreciation: $2,469,757 for electric
and gas utility and $172,761 for other in 2007;
$2,440,544 for electric and gas utility and
$174,562 for other in 2006	2,642,518	2,615,106
	5,690,622	5,672,770
Construction work in progress	705,984	569,416
	6,396,606	6,242,186
Deferred Debits and Other Assets:
Regulatory assets	2,344,353	2,449,132
Goodwill	287,591	287,591
Prepaid pension	23,584	21,647
Marketable securities - long-term	55,544	50,843
Derivative assets - long-term	288,140	271,755
Other	182,127	249,031
	3,181,339	3,329,999
Total Assets	$           11,036,088	$          11,303,236
The accompanying notes are an integral part of these condensed consolidated financial statements.

2

NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,	December 31,
	2007	2006
	(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION
Current Liabilities:
Long-term debt - current portion	$                    4,435	$                   4,877
Accounts payable	503,887	569,940
Accrued taxes	1,136	364,659
Accrued interest	49,338	53,782
Derivative liabilities - current	101,792	125,843
Counterparty deposits	1,400	148
Other	147,102	244,586
	809,090	1,363,835
Rate Reduction Bonds	1,083,768	1,177,158
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	1,109,483	1,099,433
Accumulated deferred investment tax credits	31,336	32,427
Deferred contractual obligations	259,420	271,528
Regulatory liabilities	827,428	809,324
Derivative liabilities - long-term	120,683	148,557
Accrued postretirement benefits	198,544	203,320
Other	398,961	322,840
	2,945,855	2,887,429
Capitalization:
Long-Term Debt	3,263,933	2,960,435
Preferred Stock of Subsidiary - Non-Redeemable	116,200	116,200
Common Shareholders' Equity:
Common shares, $5 par value - authorized
225,000,000 shares; 175,653,482 shares issued
and 154,529,376 shares outstanding in 2007 and
175,420,239 shares issued and 154,233,141 shares
outstanding in 2006	878,267	877,101
Capital surplus, paid in	1,453,591	1,449,586
Deferred contribution plan - employee stock
ownership plan	(32,820)	(34,766)
Retained earnings	876,214	862,660
Accumulated other comprehensive income	3,516	4,498
Treasury stock, 19,705,353 shares in 2007
and 19,684,249 shares in 2006	(361,526)	(360,900)
Common Shareholders' Equity	2,817,242	2,798,179
Total Capitalization	6,197,375	5,874,814
Commitments and Contingencies (Note 6)
Total Liabilities and Capitalization	$           11,036,088	$          11,303,236
The accompanying notes are an integral part of these condensed consolidated financial statements.

3

NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME/(LOSS)
(Unaudited)
	Three Months Ended
	March 31,
	2007	2006
	(Thousands of Dollars,
	except share information)
Operating Revenues	$             1,704,293	$            2,147,388
Operating Expenses:
Operation -
Fuel, purchased and net interchange power	1,070,486	1,544,030
Other	238,135	309,732
Restructuring charges	193	5,143
Maintenance	45,997	38,421
Depreciation	63,469	58,830
Amortization	6,223	58,471
Amortization of rate reduction bonds	51,799	48,678
Taxes other than income taxes	72,590	76,425
Total operating expenses	1,548,892	2,139,730
Operating Income	155,401	7,658
Interest Expense:
Interest on long-term debt	36,213	33,571
Interest on rate reduction bonds	16,350	19,881
Other interest	6,703	6,000
Interest expense, net	59,266	59,452
Other Income	14,069	14,204
Income/(Loss) from Continuing Operations Before
Income Tax Expense/(Benefit)	110,204	(37,590)
Income Tax Expense/(Benefit)	32,578	(18,305)
Income/(Loss) from Continuing Operations Before
Preferred Dividends of Subsidiary	77,626	(19,285)
Preferred Dividends of Subsidiary	1,390	1,390
Income/(Loss) from Continuing Operations	76,236	(20,675)
Discontinued Operations:
Income from Discontinued Operations	-	17,583
Loss from Sale of Discontinued Operations	(1,908)	-
Income Tax Benefit/(Expense)	766	(7,014)
(Loss)/Income from Discontinued Operations	(1,142)	10,569
Net Income/(Loss)	$                  75,094	$               (10,106)
Basic and Fully Diluted Earnings/(Loss) Per Common Share:
Income/(Loss) from Continuing Operations	$                      0.50	$                   (0.13)
(Loss)/Income from Discontinued Operations	(0.01)	0.06
Basic and Fully Diluted Earnings/(Loss) Per Common Share	$                      0.49	$                   (0.07)
Basic Common Shares Outstanding (weighted average)	154,349,473	153,442,640
Fully Diluted Common Shares Outstanding (weighted average)	154,992,044	153,442,640
The accompanying notes are an integral part of these condensed consolidated financial statements.

4

NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Three Months Ended
	March 31,
	2007	2006
	(Thousands of Dollars)
Operating Activities:
Net income/(loss)	$              75,094	$               (10,106)
Adjustments to reconcile to net cash flows
(used in)/provided by operating activities:
Bad debt expense	5,609	8,766
Depreciation	63,469	61,720
Deferred income taxes	4,353	171,578
Amortization	6,223	59,717
Amortization of rate reduction bonds	51,799	48,678
Amortization/(deferral) of recoverable energy costs	8,752	(52,085)
Pension expense, net of capitalized portion	5,993	10,256
Regulatory refunds	(8,337)	(124,048)
Derivative assets and liabilities	(29,414)	(29,059)
Deferred contractual obligations	(12,108)	(25,030)
Other non-cash adjustments	10,288	(13,060)
Other sources of cash	2,981	2,863
Other uses of cash	(13,591)	(17,650)
Changes in current assets and liabilities:
Receivables and unbilled revenues, net	(950)	358,108
Fuel, materials and supplies	34,565	50,728
Investments in securitizable assets	(30,821)	11,149
Other current assets	(2,056)	7,343
Accounts payable	(41,824)	(255,189)
Counterparty deposits and margin special deposits	19,926	32,919
Taxes receivable and accrued taxes	(368,454)	(239,525)
Other current liabilities	(48,108)	(15,347)
Net cash flows (used in)/provided by operating activities	(266,611)	42,726
Investing Activities:
Investments in property and plant	(227,703)	(203,825)
Cash payment related to the sale of competitive businesses	(1,908)	-
Proceeds from sales of investment securities	35,998	18,335
Purchases of investment securities	(37,338)	(19,153)
Rate reduction bond escrow	50,108	(4,381)
Other investing activities	1,787	(1,120)
Net cash flows used in investing activities	(179,056)	(210,144)
Financing Activities:
Issuance of common shares	4,117	3,202
Issuance of long-term debt	300,000	-
Retirement of rate reduction bonds	(93,390)	(53,809)
Increase in short-term debt	-	238,000
Reacquisitions and retirements of long-term debt	(442)	(2,649)
Cash dividends on common shares	(29,218)	(27,241)
Other financing activities	(2,581)	401
Net cash flows provided by financing activities	178,486	157,904
Net decrease in cash and cash equivalents	(267,181)	(9,514)
Cash and cash equivalents - beginning of period	481,911	45,782
Cash and cash equivalents - end of period	$            214,730	$                 36,268
The accompanying notes are an integral part of these condensed consolidated financial statements.

5

NORTHEAST UTILITIES AND SUBSIDIARIES

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

1.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (All Companies)

A.

Presentation

Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission (SEC).  The accompanying unaudited condensed consolidated financial statements should be read in conjunction with the entirety of this 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 2006 Form 10-K (NU 2006 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 an d the above companies' financial position at March 31, 2007, and the results of operations and cash flows for the three months ended March 31, 2007 and 2006.  The results of operations and statements of cash flows for the three months ended March 31, 2007 and 2006 are not necessarily indicative of the results expected for a full year.  

The condensed consolidated financial statements of NU and 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.

Certain reclassifications of prior period data included in the accompanying condensed consolidated financial statements have been made to conform with the current period presentation.  For the three months ended March 31, 2006, wholesale contract market changes, net were separately stated on the condensed consolidated statement of income/(loss) to increase the transparency of the mark-to-market related to Select Energy Inc.'s (Select Energy) wholesale marketing portfolio.  As the disclosure of this amount is currently not as meaningful as it was in the first quarter of 2006, $6.8 million has been reclassified to fuel, purchased and net interchange power on the accompanying condensed consolidated statement of income/(loss) for the three months ended March 31, 2006.  For further information regarding Select Energy's derivatives, see Note 4, "Derivative Instruments," to the condensed consolidated financial statements.

In NU's condensed consolidated statements of income/(loss) and CL&P's and PSNH's condensed consolidated statements of income for the three months ended March 31, 2006, the classification of certain cost and income items previously included in other income, net and interest expense was changed.  These amounts, which are now classified as operating expenses for NU, CL&P and PSNH for the three months ended March 31, 2006 are as follows:

(Millions of Dollars)	NU		CL&P		PSNH
(Decrease)/increase in other income	$	(2.0)	$	(2.7)	$	0.4
Decrease in interest expense	$	1.8	$	1.8	$	-
Decrease/(increase) in operating expenses	$	0.2	$	0.9	$	(0.4)

These reclassifications had no impact on the companies' results of operations, financial condition or cash flows.  

6

NU's condensed consolidated statements of income/(loss) for the three months ended March 31, 2007 and 2006 classifies the operations for the following as discontinued operations:  

·

Northeast Generation Company (NGC), including certain components of Northeast Generation Services Company (NGS)

·

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

·

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

·

A portion of the former Woods Electrical Co., Inc. (Woods Electrical).

For further information regarding these companies, see Note 3, "Assets Held for Sale and Discontinued Operations," to the condensed consolidated financial statements.

B.

Accounting Standards Issued But Not Yet Adopted

Fair Value Measurements:  On September 15, 2006, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 157, "Fair Value Measurements," which establishes a framework for identifying and measuring fair value and is required to be implemented in the first quarter of 2008.  SFAS No. 157 provides a fair value hierarchy, giving the highest priority to quoted prices in active markets, and is expected to be applied to fair value measurements of derivative contracts that are subject to mark-to-market accounting and other assets and liabilities reported at fair value.  In most cases, SFAS No. 157 is required to be implemented prospectively with adjustments to fair value reflected as a cumulative effect adjustment to the opening balance of retained earnings as of January 1, 2008.  The company is evaluating the potential impact of SFAS No. 157 on its condensed consolidated financial statements.

The Fair Value Option:  On February 15, 2007, the FASB issued SFAS No. 159, "The Fair Value Option for Financial Assets and Financial Liabilities - including an amendment of FAS 115."  SFAS No. 159 allows entities to choose, at specified election dates, to measure at fair value eligible financial assets and liabilities that are not otherwise required to be measured at fair value.  If a company elects the fair value option for an eligible item, changes in that item's fair value in subsequent reporting periods must be recognized in earnings.  The company is evaluating the measurement options available under SFAS No. 159, which is effective in the first quarter of 2008.

C.

Regulatory Accounting

The accounting policies of the regulated companies 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 segments of CL&P, PSNH and WMECO, along with PSNH's generation segment and Yankee Gas Services Company's (Yankee Gas) gas distribution segment, continue to be cost-of-service rate regulated.  Management believes that the application of SFAS No. 71 to those segments continues to be appropriate.  Management also believes it is probable that the regulated companies will recover their investments in long-lived assets, including regulatory assets.  All material net regulatory assets are earning an equity return, except for securitized regulatory assets, which are not supported by equity.  Amortization and deferrals of regulatory assets are included on a net basis in amortization expense on the accompanying condensed consolidated statements of income/(loss).  

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

	At March 31, 2007
(Millions of Dollars)	NU Consolidated		CL&P		PSNH		WMECO		Yankee Gas and Other
Securitized assets	$	1,073.3	$	665.5	$	312.7	$	95.1	$	-
Deferred benefit costs		393.5		149.8		87.7		24.6		131.4
Income taxes, net		307.2		266.8		0.9		39.7		(0.2)
Unrecovered contractual obligations		209.0		160.5		-		48.5		-
CTA and SBC undercollections		106.5		106.5		-		-		-
Regulatory assets offsetting regulated   company derivative liabilities		43.5		32.3		11.2		- -		- -
Other regulatory assets		211.4		48.8		70.6		32.5		59.5
Totals	$	2,344.4	$	1,430.2	$	483.1	$	240.4	$	190.7

7

	At December 31, 2006
(Millions of Dollars)	NU Consolidated		CL&P		PSNH		WMECO		Yankee Gas and Other
Securitized assets	$	1,131.1	$	707.2	$	325.6	$	98.3	$	-
Deferred benefit costs		407.4		155.8		90.4		25.8		135.4
Income taxes, net		308.0		266.6		5.5		41.3		(5.4)
Unrecovered contractual obligations		214.4		163.7		-		50.7		-
CTA and SBC undercollections		100.5		100.5		-		-		-
Regulatory assets offsetting regulated   company derivative liabilities		75.4		36.0		39.2		- -		0.2
Other regulatory assets		212.3		47.6		63.8		36.2		64.7
Totals	$	2,449.1	$	1,477.4	$	524.5	$	252.3	$	194.9

Included in NU's other regulatory assets are the regulatory assets associated with the implementation of FASB Interpretation (FIN) 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143," totaling $48.1 million at March 31, 2007 and $46.4 million at December 31, 2006.  Of these amounts, $13.8 million and $13.7 million, respectively, have been approved for future recovery.  At this time, management believes that the remaining regulatory assets are probable of recovery.  

The companies above had $11.2 million of costs at both March 31, 2007 and December 31, 2006 that are included in deferred debits and other assets - other on the accompanying condensed consolidated balance sheets.  These amounts represent 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.

Regulatory Liabilities:  The components of regulatory liabilities are as follows:  

	At March 31, 2007
(Millions of Dollars)	NU Consolidated		CL&P		PSNH		WMECO		Yankee Gas and Other
Cost of removal	$	272.1	$	119.9	$	77.2	$	22.1	$	52.9
Regulatory liabilities offsetting   regulated company derivative assets		328.7		326.0		2.5		- -		0.2
Generation service charge overcollections		89.5		89.5		-		-		-
Other regulatory liabilities		137.1		56.2		44.6		2.3		34.0
Totals	$	827.4	$	591.6	$	124.3	$	24.4	$	87.1

	At December 31, 2006
(Millions of Dollars)	NU Consolidated		CL&P		PSNH		WMECO		Yankee Gas and Other
Cost of removal	$	290.8	$	134.4	$	79.2	$	23.6	$	53.6
Regulatory liabilities offsetting   regulated company derivative assets		294.5		294.5		- -		- -		- -
Generation service charge overcollections		108.2		108.2		-		-		-
Other regulatory liabilities		115.8		45.7		36.5		3.2		30.4
Totals	$	809.3	$	582.8	$	115.7	$	26.8	$	84.0

For information regarding derivative assets, see Note 4, "Derivative Instruments."

D.

Allowance for Funds Used During Construction

The allowance for funds used during construction (AFUDC) is included in the cost of the regulated companies utility plant and represents the cost of borrowed and equity funds used to finance construction.  The portion of AFUDC attributable to borrowed funds is recorded as a reduction of other interest expense, and the cost of equity funds is recorded as other income on the accompanying condensed consolidated statements of income/(loss), as follows:

	For the Three Months Ended
(Millions of Dollars, except percentages)	March 31, 2007		March 31, 2006
Borrowed funds	$	4.4	$	3.2
Equity funds		2.4		3.7
Totals	$	6.8	$	6.9
Average AFUDC rates		6.8%		7.4%

8

The average regulated companies' AFUDC rate is based on a Federal Energy Regulatory Commission (FERC) prescribed formula that develops an average rate using the cost of a company's short-term financings as well as a company's capitalization (preferred stock, long-term debt and common equity).  The average rate is applied to eligible construction work in progress (CWIP) amounts to calculate AFUDC.  Although AFUDC is recorded on 100 percent of CL&P's CWIP for its major transmission projects in southwest Connecticut, 50 percent of this AFUDC is being reserved as a regulatory liability to reflect current rate base recovery for 50 percent of the CWIP due to FERC transmission incentives.

E.

Income Taxes

Effective on January 1, 2007, NU implemented FASB Interpretation No. (FIN) 48, "Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109."  FIN 48 applies to all tax positions previously filed in a tax return and tax positions expected to be taken in a future tax return that have been reflected on the balance sheets.  FIN 48 addresses the methodology to be used prospectively in recognizing, measuring and classifying the amounts associated with tax positions that are deemed to be uncertain, including related interest and penalties.  Previously, NU recorded estimates for uncertain tax positions in accordance with SFAS No. 5, "Accounting for Contingencies."    

As a result of implementing FIN 48, NU recognized a cumulative effect of a change in accounting principle of $32.5 million as a reduction to the January 1, 2007 balance of retained earnings.  The CL&P, PSNH and WMECO reductions/(benefits) to the January 1, 2007 balances of retained earnings were $15.6 million, $(1.6) million and $(0.4) million, respectively.  

Interest and Penalties:  Effective on January 1, 2007, NU’s accounting policy for the classification of interest and penalties related to FIN 48 is as follows:

·

Interest on uncertain tax positions is recorded and classified as a component of other interest expense.  NU recorded accrued interest expense of $17.4 million, which is included in the cumulative effect of a change in accounting principle as of January 1, 2007.  NU recorded accrued interest expense of $2 million for the three months ended March 31, 2007.  

·

No penalties have been recorded under FIN 48.  If penalties are recorded in the future, then the estimated penalties would be classified as a component of other income/expense.  

Unrecognized Tax Benefits:  Upon adoption of FIN 48 on January 1, 2007, NU recorded a liability for unrecognized tax benefits totaling $73.5 million, of which $56.9 million would impact the effective tax rate, if recognized.  

Tax Positions:  NU is currently undergoing tax audits, and it is reasonably possible as these audits progress that the liability for unrecognized tax benefits could change significantly in the next 12 months; however, management cannot estimate the amount of change at this time.

Tax Years:  The following table summarizes NU's tax years that remain subject to examination by major tax jurisdictions at January 1, 2007:  

Description	Tax Years
Federal	2002 - 2006
Connecticut	1997 - 2006
New Hampshire	2003 - 2006
Massachusetts	2003 - 2006

F.

Sale of Customer Receivables

CL&P Receivables Corporation (CRC), a consolidated, wholly-owned subsidiary of CL&P, can sell up to $100 million of an undivided interest in its accounts receivable and unbilled revenues to a financial institution. At March 31, 2007 and December 31, 2006, there were no such sales.

At March 31, 2007 and December 31, 2006, amounts sold to CRC by CL&P but not sold to the financial institution totaling $397.2 million and $375.7 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 5, 2006, CRC renewed the bank commitment for the Receivables Purchase and Sale Agreement with CL&P and the financial institution through July 3, 2007 to coincide with the date this agreement is scheduled to terminate.  CL&P presently expects to extend this agreement for another five years.  CL&P's continuing involvement with the receivables that are sold to CRC and the financial institution is limited to servicing those receivables.  

9

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."

G.

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.

H.

Special Deposits and Counterparty Deposits

To the extent Select Energy requires collateral from counterparties, or the counterparties require collateral from Select Energy, cash is paid to or by Select Energy as a part of the total collateral required based on Select Energy’s position in the transaction.  Select Energy's right to use cash collateral is determined by the terms of the related 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.  

Special deposits paid to unaffiliated counterparties and brokerage firms totaled $29.9 million and $48.5 million at March 31, 2007 and December 31, 2006, respectively.  These amounts are recorded as current assets and are included as special deposits on the accompanying condensed consolidated balance sheets.  Balances collected from counterparties resulting from Select Energy’s credit management activities totaled $1.4 million and $0.1 million at March 31, 2007 and December 31, 2006, respectively.  These amounts are recorded as current liabilities and are included as counterparty deposits on the accompanying condensed consolidated balance sheets.  

The company also had amounts on deposit related to four special purpose entities used to facilitate the issuance of rate reduction bonds and certificates.  These amounts, which totaled $52.4 million and $102.5 million at March 31, 2007 and December 31, 2006, respectively, are included in deferred debits and other assets - other on the accompanying condensed consolidated balance sheets.

I.

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, 2007		March 31, 2006
Other Income:
Investment income	$	8.5	$	6.9
CL&P procurement fee		-		2.9
AFUDC - equity funds		2.4		3.7
Energy Independence Act incentives		2.7		-
Other		0.5		0.8
Total Other Income	$	14.1	$	14.3
Other Loss:
Rental investment expense		-		(0.1)
Total Other Loss	$	-	$	(0.1)
Total Other Income, Net	$	14.1	$	14.2

CL&P	For the Three Months Ended
(Millions of Dollars)	March 31, 2007		March 31, 2006
Other Income:
Investment income	$	1.4	$	3.6
CL&P procurement fee		-		2.9
AFUDC - equity funds		1.5		2.5
Energy Independence Act incentives		2.7		-
Other		0.3		0.3
Total Other Income	$	5.9	$	9.3

10

PSNH	For the Three Months Ended
(Millions of Dollars)	March 31, 2007		March 31, 2006
Other Income:
Investment income	$	0.2	$	0.2
AFUDC - equity funds		0.4		1.1
Other		0.1		-
Total Other Income	$	0.7	$	1.3

WMECO	For the Three Months Ended
(Millions of Dollars)	March 31, 2007		March 31, 2006
Other Income:
Investment income	$	0.3	$	0.3
Conservation and load management incentive		0.2		0.4
AFUDC - equity funds		-		0.1
Total Other Income	$	0.5	$	0.8

Investment income for NU includes equity in earnings of regional nuclear generating and transmission companies of $0.7 million and $0.9 million for the three months ended March 31, 2007 and 2006, respectively.  Equity in earnings relates to the company's investment in the Connecticut Yankee Atomic Power Company, Maine Yankee Atomic Power Company, Yankee Atomic Electric Company and the Hydro-Quebec transmission system.

J.

Other Taxes

Certain excise taxes levied by state or local governments are collected by NU from its customers.  These excise taxes are accounted for on a gross basis with collections in revenues and payments in expenses.  For the three months ended March 31, 2007 and 2006, gross receipts taxes, franchise taxes and other excise taxes of $31.7 million and $31.2 million, respectively, are included in operating revenues and taxes other than income taxes on the accompanying condensed consolidated statements of income/(loss).  Certain sales taxes are also collected by the regulated companies from their customers as agent for state and local governments and are recorded on a net basis with no impact on the accompanying condensed consolidated statements of income/(loss).  

2.

RESTRUCTURING CHARGES (NU, NU Enterprises)

NU Enterprises recorded $0.2 million and $6.1 million of pre-tax restructuring charges for the three months ended March 31, 2007 and 2006, respectively, related to the decision to exit the competitive businesses.  The amounts related to continuing operations are included as restructuring charges on the condensed consolidated statements of income/(loss) with the remainder included in discontinued operations.  These charges are included as part of the NU Enterprises reportable segment in Note 10, "Segment Information."  A summary of these pre-tax restructuring charges is as follows:  

	For the Three Months Ended
(Millions of Dollars)	March 31, 2007		March 31, 2006
Retail Marketing	$	-	$	4.8
Competitive Generation		-		1.7
Energy Services and Other		0.2		(0.4)
Total restructuring charges		0.2		6.1
Restructuring charges included in discontinued operations		-		1.0
Total restructuring charges included in continuing operations	$	0.2	$	5.1

Restructuring charges totaling $0.2 million and $6.8 million for the three months ended March 31, 2007 and 2006, respectively, were recorded related to consulting fees, legal fees, employee-related and other costs incurred.  In the first quarter of 2006, a benefit of $0.7 million was included in restructuring charges related to the gain on sale of the Massachusetts service location of Select Energy Contracting, Inc. - Connecticut (SECI-CT), which was offset by costs related to the sale of SESI.  

11

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, 2007 and December 31, 2006:  

(Millions of Dollars)	Employee- Related Costs		Professional and Other Fees		Total
Restructuring liability as of January 1, 2005	$	-	$	-	$	-
Costs incurred		2.3		7.4		9.7
Cash payments and other deductions/reversals		(0.5)		(3.2)		(3.7)
Restructuring liability as of December 31, 2005		1.8		4.2		6.0
Costs incurred		3.3		24.0		27.3
Cash payments and other deductions/reversals		(3.7)		(25.9)		(29.6)
Restructuring liability as of December 31, 2006		1.4		2.3		3.7
Costs incurred		-		0.2		0.2
Cash payments and other deductions/reversals		(1.0)		(1.2)		(2.2)
Restructuring liability as of March 31, 2007	$	0.4	$	1.3	$	1.7

3.

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

A summary of the NU Enterprises businesses held for sale status at March 31, 2007 and December 31, 2006, which are included as part of the NU Enterprises reportable segment in Note 10, "Segment Information," as well as the discontinued operations status for all periods presented including date sold, is as follows:

	Held for Sale Status as of
	March 31, 2007	December 31, 2006	Discontinued Operations	Sale Date
Wholesale Marketing	No	No	No	Not Sold
Retail Marketing	Sold	Sold	No	June 2006
NGC (including certain   components of NGS)	Sold	Sold	Yes	November 2006
Mt. Tom	Sold	Sold	Yes	November 2006
NGS	No	No	No	Not Sold
SESI	Sold	Sold	Yes	May 2006
Woods Electrical -    Services	Sold	Sold	Yes	April 2006
Woods Electrical -   Other	No	No	No	Not Sold
Boulos	No	No	No	Not Sold
SECI-CT	No	No	No	Not Sold

Assets Held for Sale:  In the first quarter of 2006, management determined that the retail marketing and competitive generation businesses met held for sale criteria under applicable accounting guidance, and should be recorded at the lower of their carrying amount or fair value less cost to sell.  The retail marketing business was reduced to its fair value less cost to sell through a $59.9 million pre-tax charge, which was recorded in other operating expenses.  

At March 31, 2007, management continues to believe that Select Energy's wholesale marketing business, NGS, Woods Electrical - Other, Boulos, and SECI-CT do not meet the held for sale criteria under applicable accounting guidance and therefore continue to be held and used and included in continuing operations.

Discontinued Operations:  NU's condensed consolidated statements of income/(loss) present NGC, Mt. Tom, SESI, and Woods Electrical - Services as discontinued operations for all periods presented.  These businesses were sold in 2006.  Under discontinued operations presentation, revenues and expenses of the businesses classified as discontinued operations are classified net of tax in income from discontinued operations on the condensed consolidated statements of income/(loss) and all prior periods are reclassified.  Summarized financial information for the discontinued operations is as follows:  

	For the Three Months Ended
(Millions of Dollars)	March 31, 2007		March 31, 2006
Operating revenue	$	-	$	58.7
Income before income tax expense		-		17.6
Loss on sale of discontinued operations		(1.9)		-
Income tax benefit/(expense)		0.8		(7.0)
Net (loss)/income		(1.1)		10.6

12

No intercompany revenues were included in discontinued operations for the three months ended March 31, 2007.  Included in discontinued operations are $50.1 million for the three months ended March 31, 2006 of intercompany revenues that are not eliminated in consolidation due to the separate presentation of discontinued operations.  Of the 2006 amount, $49.9 million represents revenues on intercompany contracts between the generation operations of NGC and Mt. Tom and Select Energy.  NGC's and Mt. Tom's revenues and earnings related to these contracts are included in discontinued operations while Select Energy's related and offsetting expenses and losses are included in continuing operations.  

Select Energy's obligation to NGC and Mt. Tom ended at the time of the sale of the competitive generation business. See Note 6F, "Commitments and Contingencies - Guarantees and Indemnifications," for information related to an HWP coal purchase contract with a supplier and related back-to-back agreement with the purchaser of the competitive generation business.  At March 31, 2007, NU does not have or expect to have significant ongoing involvement or continuing cash flows with the entities presented in discontinued operations.

The retail marketing business is not presented as discontinued operations because separate financial information is not available for this business for all prior periods presented.  

4.

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

Contracts that are derivatives and do not meet the requirements to be treated as a cash flow hedge or 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, including those related to initial and ongoing documentation, 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 rec ognized 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 meet the requirements of a normal purchase or sale, and are so designated, 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, 2007 and December 31, 2006.  The fair value of these contracts may not represent amounts that will be realized.  On the accompanying condensed consolidated balance sheets at March 31, 2007 and December 31, 2006, these amounts are recorded as current or long-term derivative assets or liabilities and are summarized as follows:

	At March 31, 2007
	Assets				Liabilities
	Current		Long-Term		Current		Long-Term		Net Totals
(Millions of Dollars)
NU Enterprises - Wholesale	$	60.8	$	16.3	$	(86.1)	$	(87.9)	$	(96.9)
Regulated Companies - Gas:
Non-trading		0.2		-		-		-		0.2
Regulated Companies - Electric:
Non-trading		56.7		271.8		(15.7)		(27.8)		285.0
NU Parent:
Hedging		-		-		-		(5.0)		(5.0)
Totals	$	117.7	$	288.1	$	(101.8)	$	(120.7)	$	183.3

13

	At December 31, 2006
	Assets				Liabilities
	Current		Long-Term		Current		Long-Term		Net Totals
(Millions of Dollars)
NU Enterprises:
Wholesale	$	43.6	$	22.3	$	(82.3)	$	(110.1)	$	(126.5)
Retail		0.2		-		(0.1)		-		0.1
Regulated Companies - Gas:
Non-trading		0.1		-		(0.2)		-		(0.1)
Regulated Companies - Electric:
Non-trading		45.0		249.5		(43.2)		(32.0)		219.3
NU Parent:
Hedging		-		-		-		(6.5)		(6.5)
Totals	$	88.9	$	271.8	$	(125.8)	$	(148.6)	$	86.3

For the regulated companies, offsetting regulatory assets or liabilities are recorded for the changes in fair value of their contracts, as these contracts are part of the stranded costs, and management believes that these costs will continue to be recovered or refunded in cost-of-service, regulated rates.  

The business activities of NU Enterprises that result in the recognition of derivative assets result in exposures to credit risk to energy marketing and trading counterparties.  At March 31, 2007, Select Energy had $77.1 million of derivative assets from wholesale activities that are exposed to counterparty credit risk.  

NU Enterprises - Wholesale:  Certain electric 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, a contract to sell electricity to an agency that is comprised of municipalities with a term of seven remaining years, and two contracts to purchase the output of generating plants.  The fair value of electricity contracts was determined by prices from external sources for years through 2011 and generally by models based on natural gas prices and a heat-rate conversion factor to electricity for subsequent periods.  At March 31, 2007 and December 31, 2006, the net fair value of these wholesale contracts was a liability of $96.9 million and $126.5 million, respectively.  

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.  This in turn resulted in a change in 2005 from accrual accounting to mark-to-market accounting for the wholesale marketing contracts.  For the three months ended March 31, 2007 and 2006, NU recorded a pre-tax benefit of $2.5 million and a pre-tax charge of $6.9 million, respectively, in fuel, purchased and net interchange power related to the wholesale contracts.  These charges are associated with the mark-to-market on and changes in the fair value of certain long-dated wholesale electricity contracts in New England, New York and PJM and contracts to purchase generation products in New York.  

Regulated Companies - Gas - Non-Trading:  Yankee Gas' non-trading derivatives consist of peaking supply arrangements to serve winter load obligations and firm retail sales contracts with options to curtail delivery.  These contracts are subject to fair value accounting as these contracts are derivatives that cannot be designated as normal purchases and sales because of the optionality in the contract terms.  These non-trading derivatives at March 31, 2007 included current assets of $0.2 million.  At December 31, 2006, these non-trading derivatives included current assets of $50 thousand and current liabilities of $0.2 million.  An offsetting regulatory liability and an offsetting regulatory asset were recorded for these amounts as management believes that these costs will be refunded/recovered in rates.

Regulated Companies - Electric - Non-Trading:  CL&P has contracts with two independent power producers (IPP) 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, 2007 include a derivative asset with a fair value of $326 million and a derivative liability with a fair value of $30.5 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 cost of service, regulated rates.  At December 31, 2006, the fair values of these IPP non-trading derivatives included a derivative asset with a fair value of $289.6 million and a derivative liability with a fair value of $35.6 million.

14

CL&P has entered into Financial Transmission Rights (FTR) contracts to limit the congestion costs associated with its standard offer contracts.  An offsetting regulatory asset or liability has been recorded as management believes that these costs will be recovered or refunded in rates.  At March 31, 2007, the fair value of these contracts is recorded as a current derivative liability of $1.8 million on the accompanying condensed consolidated balance sheets.  At December 31, 2006, the fair value of the FTRs is recorded as a derivative asset of $4.9 million and a derivative liability of $0.4 million on the accompanying condensed consolidated balance sheets.  

PSNH has a contract to purchase oil that no longer qualified for the normal purchases and sales exception in the fourth quarter of 2006 due to offsetting sales of oil.  This contract is a non-trading derivative at March 31, 2007, the fair value of which is calculated based on market prices and is recorded as a current derivative liability of $1.9 million.  At December 31, 2006, the fair value is recorded as a derivative liability of $10.8 million.  An offsetting regulatory asset was recorded as management believes that this cost will be recovered in rates through a deferral mechanism that tracks generation revenues and costs.

PSNH has electricity procurement contracts that management determined no longer qualified for the normal purchases and sales exception in the fourth quarter of 2006 due to quantities being sold into the energy market.  These contracts are non-trading derivatives at March 31, 2007, the fair value of which is calculated based on market prices and is recorded as a current derivative liability of $9.3 million.  At December 31, 2006, the fair value is recorded as a derivative liability of $28.4 million.  An offsetting regulatory asset was recorded as management believes that these costs will be recovered in rates as the energy is delivered.

In 2007, PSNH entered into a contract to assign transmission rights of the Hydro-Quebec direct current line in exchange for two energy call options.  These energy call options are derivatives that do not qualify for the normal purchases and sales exception and are accounted for at fair value calculated based on market prices.  At March 31, 2007, the options are recorded as a current derivative asset of $2.5 million.  An offsetting regulatory liability is recorded, as the benefit of this arrangement will be refunded to customers in rates.

NU Parent - Hedging:  In March of 2003, to manage the interest rate characteristics of the company's long-term debt, 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.  Under fair value hedge accounting, the changes in fair value of the swap and the hedged long-term debt instrument are recorded in interest expense.  The cumulative changes in the fair value of the swap and the long-term debt are recorded as derivative liabilities and decreases to long-term debt of $5 million at March 31, 2007 and $6.5 million at December 31, 2006.

5.

GOODWILL (Yankee Gas)

SFAS No. 142, "Goodwill and Other Intangible Assets," requires that goodwill and intangible assets deemed to have indefinite useful lives be reviewed for impairment at least annually by applying a fair value-based test.  NU uses October 1^stas the annual goodwill impairment testing date.  Goodwill impairment is deemed to exist if the net book value of a reporting unit exceeds its estimated fair value and if the implied fair value of goodwill based on the estimated fair value of the reporting unit is less than the carrying amount.  

The only NU reporting unit that currently maintains goodwill is the Yankee Gas reporting unit, which is classified under the regulated companies - 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, 2007 and December 31, 2006.  

For information regarding NU's reportable segments, see Note 10, "Segment Information," to the condensed consolidated financial statements.

6.

COMMITMENTS AND CONTINGENCIES

A.

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

Connecticut:

CTA and SBC Reconciliation:  The Competitive Transition Assessment (CTA) allows CL&P to recover stranded costs, such as securitization costs associated with its rate reduction bonds, amortization of regulatory assets, and independent power producer 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 30, 2007, CL&P filed its 2006 CTA and SBC reconciliation, which compared CTA and SBC revenues to revenue requirements, with the Connecticut Department of Public Utility Control (DPUC).  For the year ended December 31, 2006, total CTA cost of service exceeded CTA revenues by $5.6 million.  This amount was recorded as a regulatory asset on the accompanying condensed consolidated balance sheets.  In addition, CTA refunds for the period January 2006 through August 2006 totaled $99.8

15

million and resulted in an additional increase to CL&P’s CTA regulatory asset.  For the year ended December 31, 2006, the SBC cost of service exceeded SBC revenues by $24.3 million.  Management expects a decision in this docket from the DPUC by the end of 2007 and does not expect the outcome to have a material adverse impact on CL&P's net income, financial position or cash flows.

Underground Network Reliability:  In 2006, the DPUC opened an investigation into various underground electrical network failures on the CL&P system in 2001 and 2006 in Waterbury, Meriden and Stamford, Connecticut.  On April 25, 2007, the DPUC issued a final decision finding that it was necessary for CL&P to replace the older type cables in those municipalities, as was previously proposed by CL&P.  CL&P estimates that the cost of this project will be between $20 million and $30 million.  Included in that estimate is $2 million to $3 million of project costs that may be incurred if it is deemed necessary to remove the existing older type cable as part of the project.  Management is currently evaluating whether these additional project costs will be required and whether an asset retirement obligation has arisen as a result of this decision.

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' previously recovered PGA costs and deferred any conclusion on the $9 million of previously recovered revenues until the completion of the audit.  In a subsequent draft decision regarding Yankee Gas PGA charges for the period September 1, 2004 through August 31, 2005, an additional $2 million related to previously recovered revenues was also identified, bringing the total maximum amount at issue with regard to PGA clause charges under audit to $11 million.  

The DPUC hired a consulting firm which has concluded an audit of Yankee Gas' previously recovered PGA costs and has submitted a draft report to CL&P for review and comment.  Management believes the unbilled sales and revenue adjustments and resulting charges to customers through the PGA clause for both periods were appropriate.  Based on the facts of the case and the supplemental information provided to the DPUC, management believes the appropriateness of the PGA charges to customers for the time period under review will be approved, and has not reserved for any loss.

New Hampshire:

SCRC/ES Reconciliation:  On an annual basis, PSNH files with the New Hampshire Public Utilities Commission (NHPUC) a stranded cost recovery charge/energy service (SCRC/ES) reconciliation filing for the preceding calendar year.  The NHPUC reviews the filing, including a prudence review of the operations within PSNH's generation segment.  On May 1, 2007, PSNH filed its 2006 SCRC/ES reconciliation with the NHPUC.  At March 31, 2007, SCRC costs exceeded SCRC revenues and PSNH has deferred the $11.8 million difference for future recovery.  At March 31, 2007, ES revenues exceeded ES costs and PSNH has deferred the $24 million difference for future refund.  Management does not expect the outcome of the NHPUC's review of this filing to have a material adverse impact on PSNH's net income, financial position or cash flows.

Massachusetts:

Transition Cost Reconciliations: WMECO filed its 2005 transition cost reconciliation with the Massachusetts Department of Telecommunications and Energy (DTE) (effective on April 11, 2007, known as the Massachusetts Department of Public Utilities (DPU)) on March 31, 2006 and filed its 2006 transition cost reconciliation with the DPU on March 31, 2007.  The DPU has not yet reviewed these filings or issued schedules for review, and the timing of decisions on these filings is uncertain.  Management does not expect the outcome of the DPU's review of these filings to have a material adverse impact on WMECO's net income, financial position or cash flows.

B.

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

Certain subsidiaries of NU, including CL&P and Yankee Gas, entered into transactions with NRG Energy, Inc. (NRG) and certain of its subsidiaries.  On May 14, 2003, NRG and certain subsidiaries of NRG 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 refunding of approximately $28 million of congestion charges previously withheld from NRG prior to the implementation of standard market design on March 1, 2003, which is still pending before the court, 2) the recovery of approximately $26.9 million of CL&P's station service billings from NRG, which is currently the subject of an arbitration, and 3) the recovery of, among other claimed damages, approximately $17.5 million of capital costs and expenses incurred by Yankee Gas 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 earnings or financial position.  

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C.

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

CL&P:  These amounts represent commitments for various services and materials associated with the Middletown to Norwalk,  Glenbrook Cables and the Norwalk to Northport-Long Island, New York transmission projects and other projects as of March 31, 2007:

(Millions of Dollars)	2007	2008	2009	2010	2011	Thereafter	Total
Transmission segment   project commitments	$457.4	$336.3	$33.9	$    -	$    -	$    -	$827.6

Select 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.  Most purchase commitments are recorded at their mark-to-market value with the exception of one non-derivative contract which is accounted for on the accrual basis.  These purchase commitments at March 31, 2007 are as follows:

(Millions of Dollars)	2007	2008	2009	2010	2011	Thereafter	Total
Select Energy   purchase commitments	$387.6	$193.3	$29.7	$32.1	$31.2	$27.2	$701.1

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 also classified in fuel, purchased and net interchange power, and certain purchases are included in revenues.  Select Energy also maintains certain 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 is included in assets held for sale and liabilities of assets held for sale.  These contracts are included in the table above.  

The amounts and timing of the costs associated with Select Energy's purchase agreements will be impacted by the exit from the NU Enterprises' businesses.

D.

Environmental Matters (HWP)

The company is in the process of evaluating additional potential remediation requirements at a river site in Massachusetts containing coal tar deposits.  HWP is partially responsible for this site, and substantial remediation activities at this site have already been conducted.  The company’s reserve with respect to this site is based on its current site assessment and estimate of remediation costs.  The cost to remediate any additional coal tar may be more significant than currently estimated.  The ultimate remediation requirements are the subject of ongoing discussions with the Massachusetts Department of Environmental Protection and may change from time-to-time.  The cost of remediation to HWP will depend, among other things, on the level and extent of the remaining coal tar required to be removed, and the extent of HWP’s responsibility.  HWP's share of the costs related to this site is not recoverable from ratepayers.  At this time, manag ement cannot predict the outcome of this matter or its ultimate effect on NU.  Any increase to the environmental remediation reserve for this site would be recorded in earnings in future periods, may be material, and will be in addition to the approximately $13 million expensed to date of which $11.8 million has been spent and $1.2 million remains in the reserve for this site.  

E.

Consolidated Edison, Inc. Merger Litigation

Certain gain and loss contingencies exist with regard to the merger agreement between NU and Consolidated Edison, Inc. (Con Edison) and the related litigation.  

In 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).  In March of 2001, NU filed suit against Con Edison seeking damages in excess of $1 billion.  

In a 2005 opinion, 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 in 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.  In April of 2006, NU filed its motion for partial summary judgment on Con Edison's damage claim.  NU's motion asserts that NU is entitled to a judgment in its favor with respect to this claim based on the undisputed material facts and applicable law.  The matter is fully briefed and awaiting a decision.  At this time, NU cannot predict the outcome of this matter or its ultimate effect on NU.

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F.

Guarantees and Indemnifications

NU provides credit assurances on behalf of subsidiaries in the form of guarantees and letters of credit (LOCs) in the normal course of business.  In addition, NU has provided guarantees and various indemnifications on behalf of external parties as a result of the sales of SESI, the retail marketing business and the competitive generation business.  The following table summarizes NU's maximum exposure at March 31, 2007, in accordance with FIN 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others," expiration dates, and fair value of amounts recorded.  

Company	Description	Maximum Exposure (in millions)		Expiration Date(s)	Fair Value of Amounts Recorded (in millions)
On behalf of external parties:
SESI	General indemnifications in connection with the sale of SESI including completeness and accuracy of information provided, compliance with laws, and various claims	Not Specified	(1)	None	$  -
	Specific indemnifications in connection with the sale of SESI for estimated costs to complete or modify specific projects	Not Specified	(1)	Through project completion	0.2
	Indemnifications to lenders for payment of shortfalls in the event of early termination of government contracts	$2.7		2017-2018	0.1
	Surety bonds covering certain projects	$79.8		Through project completion	-
Hess (Retail Marketing Business)	General indemnifications in connection with the sale including compliance with laws, validity of contract information, completeness and accuracy of information provided, absence of default on contracts, and various claims	Not Specified	(1)	None	-
ECP (Competitive Generation Business)	General indemnifications in connection with the sale of the generating assets of NGC and Mt. Tom including compliance with laws, validity of contract information, completeness and accuracy of information provided, absence of default on contracts, and various claims	Not Specified	(1)	None	-
On behalf of subsidiaries:
Regulated Companies	Surety bonds, primarily for self-insurance	$11.7		None	N/A
	Letters of credit	40.0		2007-2008	N/A
Rocky River Realty Company	Lease payments for real estate	11.7		2024	N/A
NUSCO	Lease payments for fleet of vehicles	9.9		None	N/A
SECI-CT and Boulos	Surety bonds covering ongoing projects	77.1		Through project completion	N/A
NGS	Insurance bonds and lease payment guarantees	2.1		None	N/A
Select Energy	Performance guarantees and surety bonds for retail marketing contracts	12.3	(2)	None (3)	N/A
	Performance guarantees for wholesale marketing contracts	165.0	(2)	None	N/A
	Letters of credit	7.0		2007	N/A
HWP	Performance and payment guarantee related to coal purchase contract	Not Specified	(4)	2009	N/A

(1)

There is no specified maximum exposure included in the related sale agreements.  For retail marketing business guarantees, Hess may not assert an indemnification claim based on unintentional data errors unless and until damages exceed a $5 million aggregate threshold, at which point Hess may assert a claim for all damages; all other claims are subject to a $0.3 million threshold.  

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(2)

Maximum exposure is as of March 31, 2007; however, exposures vary with underlying commodity prices and for certain contracts are essentially unlimited.  

(3)

NU is working with counterparties to terminate the remaining guarantees and does not currently anticipate that these remaining guarantees on behalf of Select Energy will result in significant guarantees of the performance of Hess.

(4)

There is no specified maximum exposure included in this guarantee agreement.  NU has guaranteed the performance of HWP under a back-to-back agreement with ECP relating to an HWP coal supply contract.  The maximum exposure to loss under very unlikely circumstances is estimated at approximately $60 million.  NU would have recourse to ECP for approximately $50 million, of which $2 million is secured by an LOC.    

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.  

In July 2006, under its former SESI guarantee, NU was required to purchase contract payments relating to the only guaranteed SESI project that was behind schedule.  The carrying value of these assets is $9.3 million at March 31, 2007 and is included in other deferred debits on the accompanying condensed consolidated balance sheets.  NU may record additional losses associated with this transaction, the amount of which will depend on changes in interest rates used to determine SESI's refinancing proceeds, the amount of project cash available to offset NU's costs, and other factors.  

This carrying amount represents the amount expected to be received from refinancing through SESI's completion of the project.  

7.

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, 2007 and 2006 is as follows:

	Three Months Ended March 31, 2007
(Millions of Dollars)	NU*		CL&P		PSNH		WMECO		NU Enterprises		Yankee Gas		Other
Net income	$	75.1	$	33.6	$	10.0	$	6.9	$	4.8	$	13.6	$	6.2
Comprehensive (loss)/income items:
Qualified cash flow hedging instruments		(1.6)		(1.6)		-		-		-		-		-
Unrealized gains on securities		0.2		-		-		-		-		-		0.2
Pension, SERP, and other     postretirement benefits		0.4		- -		- -		- -		0.3		- -		0.1
Net change in comprehensive   (loss)/income items		(1.0)		(1.6)		- -		- -		0.3		- -		0.3
Total comprehensive income	$	74.1	$	32.0	$	10.0	$	6.9	$	5.1	$	13.6	$	6.5

	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:
Qualified cash flow hedging instruments		(20.1)		1.9		-		-		(22.0)		-		-
Unrealized gains on securities		3.1		-		-		-		2.5		-		0.6
Minimum SERP liability		(2.3)		-		-		-		-		-		(2.3)
Net change in comprehensive   (loss)/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)

*After preferred dividends of subsidiary.

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

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Accumulated other comprehensive income fair value adjustments in NU's cash flow hedging instruments for the three months ended March 31, 2007 and the twelve months ended December 31, 2006 are as follows:

(Millions of Dollars, Net of Tax)	Three Months Ended March 31, 2007		Twelve Months Ended December 31, 2006
Balance at beginning of period	$	5.9	$	18.2
Hedged transactions recognized into earnings		-		2.3
Amount reclassified into earnings due to   discontinuation of cash flow hedges		- -		(14.1)
Change in fair value of hedged  transactions delivered		- -		(4.5)
Cash flow transactions entered into for the period		(1.6)		4.0
Net change associated with the current period   hedging transactions		(1.6)		(12.3)
Total fair value adjustments included in accumulated   other comprehensive income	$	4.3	$	5.9

In the first quarter of 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 hedged beyond June 1, 2006 were no longer probable of physical delivery due to the retail business being sold.  

In March of 2006, CL&P entered into a forward lock agreement to hedge the interest rate associated with $125 million of its planned $250 million, 30-year fixed rate long-term debt issuance.  Under the agreement, CL&P locked in a LIBOR swap rate of 5.322 percent based on the notional amount of $125 million in long-term debt that was issued in June of 2006.  On June 1, 2006, the hedged transaction was settled and as a result $4.6 million, net of tax ($7.8 million pre-tax), was recorded in accumulated other comprehensive income to be amortized into earnings over the term of the long-term debt.  

In February of 2007, CL&P entered into two forward swap agreements to hedge the interest rates associated with $75 million of its planned $150 million, 10-year fixed rate long-term debt issuance and with $75 million of its planned $150 million, 30-year fixed rate long-term debt issuance.  Under the agreements, CL&P locked in a LIBOR swap rate of 5.229 percent for the 10-year hedge and 5.369 percent for the 30-year hedge, both based on the notional amounts of $75 million in long-term debt that was issued in March of 2007.  On March 27, 2007, the hedge was settled, and as a result, a charge of $1.6 million, net of tax ($2.6 million pre-tax) was recorded in accumulated other comprehensive income to be amortized into earnings over the term of the long-term debt.

At March 31, 2007, it is estimated that a pre-tax $1.6 million included in the accumulated other comprehensive income balance will be reclassified as a decrease to earnings in the next year related to pension, supplemental executive retirement plan (SERP) and other postretirement benefits adjustments.  

Accumulated other comprehensive income items unrelated to NU's cash flow hedging instruments totaled $0.8 million and $1.4 million of charges at March 31, 2007 and December 31, 2006, respectively.  These amounts relate to unrealized gains on investments in marketable debt and equity securities and the pension, SERP and other postretirement benefits adjustments, net of related income taxes.

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8.

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.  The following table excludes 1,739,430 options for the three months ended March 31, 2006, as these options were antidilutive.  There were no antidilutive options for the three months ended March 31, 2007.  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)	2007		2006
Income/(loss) from continuing operations	$	76.2	$	(20.7)
(Loss)/income from discontinued operations		(1.1)		10.6
Net income/(loss)		75.1		(10.1)
Basic EPS common shares outstanding (average)		154,349,473		153,442,640
Dilutive effect		642,571		-
Fully diluted EPS common shares   outstanding (average)		154,992,044		153,442,640
Basic and Fully Diluted EPS:
Income/(loss) from continuing operations		0.50		(0.13)
(Loss)/income from discontinued operations		(0.01)		0.06
Net income/(loss)	$	0.49	$	(0.07)

Restricted share units (RSUs) are included in basic common shares outstanding when shares are issued.  The dilutive effect of RSUs granted but not issued is calculated using the treasury stock method.  Assumed proceeds of RSUs under the treasury stock method consist of the remaining compensation cost to be recognized and a theoretical tax benefit.  The theoretical tax benefit is calculated as the tax impact of the difference between the market value of RSUs outstanding but not issued using the average market price during the period and the grant date market value.  

The dilutive effect of stock options is also calculated using the treasury stock method.  Assumed proceeds for stock options consist of remaining compensation cost to be recognized, cash proceeds that would be received upon exercise, and a theoretical tax benefit.  The theoretical tax benefit is calculated as the tax impact of the difference between the intrinsic value of dilutive stock options outstanding and the total adoption compensation.  

Allocated ESOP shares are included in basic common shares outstanding in the previous table.  

9.

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).  In addition, NU maintains a SERP which provides benefits to eligible participants, who are officers of NU, that would have been provided to them under NU’s retirement plan if certain Internal Revenue Code and other limitations were not imposed.  The components of net periodic benefit expense for the Pension Plan, SERP, and PBOP Plan for the three months ended March 31, 2007 and 2006 are as follows:

NU	For the Three Months Ended March 31,
	Pension Benefits				SERP				Postretirement Benefits
(Millions of Dollars)		2007		2006		2007		2006		2007		2006
Service cost	$	11.7	$	12.3	$	0.2	$	0.3	$	2.1	$	1.9
Interest cost		33.6		32.3		0.5		0.5		6.6		6.8
Expected return on plan assets		(47.2)		(43.5)		-		-		(4.5)		(3.5)
Amortization of unrecognized net   transition obligation		0.1		- -		- -		- -		2.9		2.8
Amortization of prior service cost		1.6		1.5		-		-		(0.1)		(0.1)
Amortization of actuarial loss		6.8		10.3		0.2		0.2		2.9		4.5
Net periodic expense	$	6.6	$	12.9	$	0.9	$	1.0	$	9.9	$	12.4

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A portion of these pension amounts is capitalized related to current employees that are working on capital projects.  Amounts capitalized were approximately $0.6 million and $2.6 million for the three months ended March 31, 2007 and 2006, respectively.

CL&P	For the Three Months Ended March 31,
	Pension Benefits				SERP				Postretirement Benefits
(Millions of Dollars)		2007		2006		2007		2006		2007		2006
Service cost	$	3.8	$	4.4	$	-	$	-	$	0.7	$	0.7
Interest cost		12.3		12.0		0.1		0.1		2.6		2.7
Expected return on plan assets		(22.1)		(20.3)		-		-		(1.8)		(1.4)
Amortization of unrecognized net   transition obligation		- -		- -		- -		- -		1.5		1.5
Amortization of prior service cost		0.7		0.7		-		-		-		-
Amortization of actuarial loss		2.5		4.0		-		-		1.2		1.8
Net periodic (income)/expense	$	(2.8)	$	0.8	$	0.1	$	0.1	$	4.2	$	5.3

Not included in the pension (income)/expense amounts above are intercompany expense allocations totaling $3.1 million and $3.3 million for the three months ended March 31, 2007 and 2006, respectively.  Intercompany allocations of postretirement benefits totaled $1.8 million and $2 million for the three months ended March 31, 2007 and 2006, respectively.  

For CL&P, a portion of the pension amounts, including intercompany allocations, is capitalized related to current employees that are working on capital projects.  Amounts capitalized were $0.6 million and $1 million for the three months ended March 31, 2007 and 2006, respectively.  The amount for 2007 offset capital costs, as pension income was recorded for that period.

PSNH	For the Three Months Ended March 31,
	Pension Benefits				SERP				Postretirement Benefits
(Millions of Dollars)		2007		2006		2007		2006		2007		2006
Service cost	$	2.5	$	2.4	$	-	$	-	$	0.4	$	0.4
Interest cost		5.3		5.0		-		-		1.2		1.2
Expected return on plan assets		(4.3)		(4.1)		-		-		(0.8)		(0.6)
Amortization of unrecognized net   transition obligation		0.1		0.1		- -		- -		0.6		0.6
Amortization of prior service cost		0.3		0.3		-		-		-		-
Amortization of actuarial loss		1.2		1.5		0.1		0.1		0.6		0.8
Net periodic expense	$	5.1	$	5.2	$	0.1	$	0.1	$	2.0	$	2.4

Not included in the pension expense amounts above are intercompany allocations totaling $0.5 million for both the three months ended March 31, 2007 and 2006, respectively.  Intercompany allocations of postretirement benefits totaled $0.3 million and $0.4 million for the three months ended March 31, 2007 and 2006, respectively.  

For PSNH, a portion of these pension amounts, including intercompany allocations, is capitalized related to current employees that are working on capital projects.  Amounts capitalized were $1.3 million and $1.4 million for the three months ended March 31, 2007 and 2006, respectively.   

WMECO	For the Three Months Ended March 31,
	Pension Benefits				Postretirement Benefits
(Millions of Dollars)		2007		2006		2007		2006
Service cost	$	0.7	$	0.9	$	0.2	$	0.2
Interest cost		2.5		2.4		0.6		0.6
Expected return on plan assets		(4.9)		(4.4)		(0.5)		(0.4)
Amortization of unrecognized net   transition obligation		- -		- -		0.3		0.3
Amortization of prior service cost		0.2		0.1		-		-
Amortization of actuarial loss		0.5		0.8		0.2		0.4
Net periodic (income)/expense	$	(1.0)	$	(0.2)	$	0.8	$	1.1

A de minimis amount of SERP expense was recorded for WMECO for the first three months ended March 31, 2007 and 2006.  

Not included in the pension income amounts above are intercompany expense allocations totaling $0.5 million for both the three months ended March 31, 2007 and 2006.  Intercompany allocations of postretirement benefits totaled $0.3 million for both the three months ended March 31, 2007 and 2006.  

For WMECO, a portion of these pension amounts, including intercompany allocations, is capitalized related to current employees that are working on capital projects.  Amounts capitalized were $0.3 million for the three months ended March 31, 2007.  A de minimis

22

amount was capitalized during the three months ended March 31, 2006.  The capitalized amounts for 2007 and 2006 offset capital project costs, as pension income was recorded for those periods.  

NU contributed $6.5 million in the first quarter of 2007 to fund its PBOP Plan.  In addition, NU funded an additional $2.5 million to its PBOP Plan with funds received from the federal Medicare subsidy for a portion of its 2006 subsidy.  

10.

SEGMENT INFORMATION (All Companies)

Presentation:  NU is organized between the regulated companies 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 each operates.  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 reclassified to conform to the current period presentation, except as indicated.  

The regulated companies segment, including the electric distribution, generation and transmission segments, as well as the gas distribution segment (Yankee Gas), represents approximately 96 percent for the three months ended March 31, 2007 and 76 percent for the three months ended March 31, 2006, of NU's total revenues.  CL&P's, PSNH's and WMECO's 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 segments.  Regulated companies 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.

At March 31, 2007, the NU Enterprises business segment includes:  1) Select Energy (wholesale contracts), 2) NGS, 3) Woods Electrical - Other, 4) Boulos, 5) SECI-CT, and 6) NU Enterprises parent.  

Other in the segment tables primarily consists of 1) the results of NU parent, which includes other income related to the equity in earnings of NU parent's subsidiaries and interest income from the NU Money Pool, which are both eliminated in consolidation, and interest income and expense related to the cash and debt of NU parent, respectively, 2) the revenues and expenses of NU's service companies, most of which are eliminated in consolidation, and 3) the results of other subsidiaries, which are comprised of Mode 1 Communications, Inc. and the results of the non-energy-related subsidiaries of Yankee Energy System, Inc. (Yankee Energy Services Company, Yankee Energy Financial Services Company, and NorConn Properties, Inc.).

As a result of the sales of NU Enterprises' retail marketing and competitive generation businesses, the financial information used by management was reduced to Select Energy's remaining wholesale marketing contracts, the operations of the remaining energy services businesses and NU Enterprises' parent company.  As a result of exiting these businesses in 2006, the operations of NU Enterprises have been aggregated and presented as one reportable segment for the three months ended March 31, 2007 and 2006.

Effective on January 1, 2007, financial information for the remaining operations of HWP that were not exited as part of the sale of the competitive generation business was included as part of the Other reportable segment as these operations were no longer considered part of NU Enterprises subsequent to the sale.  Accordingly, HWP’s remaining operations have been presented as part of the Other reportable segment for the three months ended March 31, 2007.

Customer Concentrations:  Select Energy provides basic generation service in the New Jersey and Maryland markets.  Select Energy revenues related to these contracts represented $60 million and $132.5 million for the three months ended March 31, 2007 and 2006, respectively.  No other individual customer represented in excess of 10 percent of NU Enterprises' revenues for the three months ended March 31, 2007 and 2006.  

Select Energy reported the settlement of all derivative contracts of the wholesale business, including full requirements sales contracts and intercompany revenues, in fuel, purchased and net interchange power.  This presentation is a result of applying mark-to-market accounting to those contracts due to the decision to exit the wholesale marketing business.

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NU's segment information for the three months ended March 31, 2007 and 2006 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, 2007
	Regulated Companies
	Distribution (1)
(Millions of Dollars)	Electric		Gas		Transmission		NU Enterprises		Other		Eliminations		Total
Operating revenues	$	1,381.4	$	184.8	$	69.0	$	80.5	$	94.0	$	(105.4)	$	1,704.3
Depreciation and amortization		(105.3)		(5.8)		(9.0)		(0.1)		(2.4)		1.1		(121.5)
Restructuring charges		-		-		-		(0.2)		-		-		(0.2)
Other operating expenses		(1,189.2)		(154.5)		(28.3)		(70.7)		(87.7)		103.2		(1,427.2)
Operating income/(loss)		86.9		24.5		31.7		9.5		3.9		(1.1)		155.4
Interest expense, net of AFUDC		(42.5)		(4.2)		(8.8)		(2.9)		(8.3)		7.4		(59.3)
Interest income		1.2		-		0.2		0.6		12.6		(7.4)		7.2
Other income/(loss), net		4.3		0.4		1.3		-		56.5		(55.6)		6.9
Income tax expense		(14.2)		(7.1)		(8.2)		(1.3)		(1.3)		(0.5)		(32.6)
Preferred dividends		(1.1)		-		(0.3)		-		-		-		(1.4)
Income/(loss) from   continuing operations	$	34.6	$	13.6	$	15.9	$	5.9	$	63.4	$	(57.2)	$	76.2
Loss from   discontinued operations		- -		- -		- -		(1.1)		- -		- -		(1.1)
Net income/(loss)	$	34.6	$	13.6	$	15.9	$	4.8	$	63.4	$	(57.2)	$	75.1
Total assets	$	9,255.6	$	1,213.3	$	-	$	224.9	$	4,420.4	$	(4,078.1)	$	11,036.1
Cash flows for total   investments in plant	$	92.8	$	14.4	$	116.4	$	0.1	$	4.0	$	- -	$	227.7

	For the Three Months Ended March 31, 2006
	Regulated Companies
	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)		(7.0)		(0.3)		(4.6)		3.5		(166.0)
Restructuring charges		-		-		-		(5.1)		-		-		(5.1)
Other operating expenses		(1,174.6)		(156.3)		(22.5)		(628.5)		(82.8)		96.1		(1,968.6)
Operating income/(loss)		74.2		22.1		18.9		(106.9)		0.3		(0.9)		7.7
Interest expense, net of AFUDC		(39.9)		(4.4)		(4.5)		(8.7)		(8.9)		6.9		(59.5)
Interest income		3.5		-		-		2.1		7.2		(7.4)		5.4
Other income/(loss), net		6.0		-		1.9		(0.1)		60.6		(59.6)		8.8
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 from   discontinued operations		- -		- -		- -		10.6		- -		- -		10.6
Net income/(loss)	$	30.1	$	11.8	$	12.7	$	(62.6)	$	58.9	$	(61.0)	$	(10.1)
Cash flows for total  investments in plant	$	79.5	$	17.8	$	90.2	$	5.0	$	11.3	$	-	$	203.8

(1)

Includes PSNH's generation activities.  

(2)

Information for segmenting total assets between electric distribution and transmission is not available at March 31, 2007.  On a NU consolidated basis, these distribution and transmission assets are disclosed in the electric distribution column above.  

24

The regulated companies information related to the distribution and transmission segments for CL&P, PSNH and WMECO for the three months ended March 31, 2007 and 2006 is as follows:

	CL&P - For the Three Months Ended March 31, 2007
(Millions of Dollars)	Distribution		Transmission		Total
Operating revenues	$	991.3	$	52.4	$	1,043.7
Depreciation and amortization		(66.6)		(6.9)		(73.5)
Other operating expenses		(871.1)		(20.1)		(891.2)
Operating income		53.6		25.4		79.0
Interest expense, net of AFUDC		(27.9)		(7.2)		(35.1)
Interest income		0.8		0.2		1.0
Other income, net		3.7		1.2		4.9
Income tax expense		(8.5)		(6.3)		(14.8)
Preferred dividends		(1.1)		(0.3)		(1.4)
Net income	$	20.6	$	13.0	$	33.6
Cash flows for total investments in plant	$	53.5	$	105.1	$	158.6

	CL&P - For the Three Months Ended March 31, 2006
(Millions of Dollars)	Distribution		Transmission		Total
Operating revenues	$	972.0	$	32.8	$	1,004.8
Depreciation and amortization		(62.1)		(5.2)		(67.3)
Other operating expenses		(861.4)		(15.3)		(876.7)
Operating income		48.5		12.3		60.8
Interest expense, net of AFUDC		(24.8)		(3.3)		(28.1)
Interest income		3.2		0.1		3.3
Other income, net		4.3		1.7		6.0
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

	PSNH - For the Three Months Ended March 31, 2007
(Millions of Dollars)	Distribution (1)		Transmission		Total
Operating revenues	$	266.2	$	10.9	$	277.1
Depreciation and amortization		(28.6)		(1.4)		(30.0)
Other operating expenses		(217.5)		(5.5)		(223.0)
Operating income		20.1		4.0		24.1
Interest expense, net of AFUDC		(10.4)		(1.1)		(11.5)
Interest income		0.2		-		0.2
Other income, net		0.3		0.2		0.5
Income tax expense		(2.1)		(1.2)		(3.3)
Net income	$	8.1	$	1.9	$	10.0
Cash flows for total investments in plant	$	31.3	$	8.5	$	39.8

25

	PSNH - For the Three Months Ended March 31, 2006
(Millions of Dollars)	Distribution (1)		Transmission		Total
Operating revenues	$	304.6	$	10.7	$	315.3
Depreciation and amortization		(85.2)		(1.3)		(86.5)
Other operating expenses		(204.1)		(4.7)		(208.8)
Operating income		15.3		4.7		20.0
Interest expense, net of AFUDC		(10.7)		(0.8)		(11.5)
Interest income		0.2		-		0.2
Other income, net		0.9		0.2		1.1
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

(1)

Includes PSNH's generation activities.  

	WMECO - For the Three Months Ended March 31, 2007
(Millions of Dollars)	Distribution		Transmission		Total
Operating revenues	$	123.9	$	5.7	$	129.6
Depreciation and amortization		(10.1)		(0.7)		(10.8)
Other operating expenses		(100.6)		(2.8)		(103.4)
Operating income		13.2		2.2		15.4
Interest expense, net of AFUDC		(4.2)		(0.5)		(4.7)
Interest income		0.2		-		0.2
Other income, net		0.3		-		0.3
Income tax expense		(3.6)		(0.7)		(4.3)
Net income	$	5.9	$	1.0	$	6.9
Cash flows for total investments in plant	$	8.0	$	2.8	$	10.8

	WMECO - For the Three Months Ended March 31, 2006
(Millions of Dollars)	Distribution		Transmission		Total
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

26

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, 2007, and the related condensed consolidated statements of income/(loss) and cash flows for the three-month periods ended March 31, 2007 and 2006.  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 Note 3, the Company recorded a $59.9 million, pre-tax charge in the three-month period ended March 31, 2006 to reduce the retail business to its fair value less cost to sell.  Also, as discussed in Note 1.E., the Company adopted Financial Accounting Standards Board Interpretation No. 48,Accounting for Uncertainty in Income Taxes – an Interpretation of FASB Statement No. 109, as of January 1, 2007.

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, 2006, and the related consolidated statements of income, comprehensive income, shareholders’ equity, and cash flows for the year then ended (not presented herein); and in our report dated February 26, 2007 (which report included an explanatory paragraph related to recording charges, gains and losses in connection with the Company’s ongoing divestiture activities, realizing a reduction to income tax expense related to a ruling that certain income taxes could not be used to reduce customer’s rates, and the adoption of Statement of Financial Accounting Standard No. 158,Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans), we expressed an unqualified opinion on those consolidat ed financial statements.  In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2006 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 8, 2007

27

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28

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

29

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,	December 31,
	2007	2006
	(Thousands of Dollars)
ASSETS
Current Assets:
Cash	$                    1,351	$                   3,310
Investments in securitizable assets	397,168	375,656
Receivables, less provision for uncollectible
accounts of $1,845 in 2007 and $1,679 in 2006	80,734	73,052
Accounts receivable from affiliated companies	1,091	1,965
Unbilled revenues	6,874	8,044
Materials and supplies	44,220	39,447
Derivative assets - current	54,159	45,031
Prepayments and other	23,952	15,945
	609,549	562,450
Property, Plant and Equipment:
Electric utility	4,595,222	4,557,231
Less: Accumulated depreciation	1,287,210	1,260,526
	3,308,012	3,296,705
Construction work in progress	444,308	337,665
	3,752,320	3,634,370
Deferred Debits and Other Assets:
Regulatory assets	1,430,232	1,477,375
Prepaid pension	249,134	243,139
Derivative assets - long-term	271,810	249,423
Other	94,182	154,537
	2,045,358	2,124,474
Total Assets	$             6,407,227	$            6,321,294
The accompanying notes are an integral part of these condensed consolidated financial statements.

30

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,	December 31,
	2007	2006
	(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION
Current Liabilities:
Notes payable to affiliated companies	$                   96,425	$                 258,925
Accounts payable	304,280	326,163
Accounts payable to affiliated companies	40,104	47,906
Accrued taxes	36,610	186,647
Accrued interest	21,251	29,587
Derivative liabilities - current	4,523	4,101
Other	59,958	80,543
	563,151	933,872
Rate Reduction Bonds	666,103	743,899
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	707,007	719,470
Accumulated deferred investment tax credits	23,172	24,019
Deferred contractual obligations	177,056	185,195
Regulatory liabilities	591,623	582,841
Derivative liabilities - long-term	27,806	31,923
Accrued postretirement benefits	83,560	85,768
Other	168,278	127,638
	1,778,502	1,756,854
Capitalization:
Long-Term Debt	1,820,518	1,519,440
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 2007 and 2006	60,352	60,352
Capital surplus, paid in	887,855	672,693
Retained earnings	511,516	513,344
Accumulated other comprehensive income	3,030	4,640
Common Stockholder's Equity	1,462,753	1,251,029
Total Capitalization	3,399,471	2,886,669
Commitments and Contingencies (Note 6)
Total Liabilities and Capitalization	$              6,407,227	$              6,321,294
The accompanying notes are an integral part of these condensed consolidated financial statements.

31

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
	Three Months Ended
	March 31,
	2007	2006
	(Thousands of Dollars)
Operating Revenues	$              1,043,686	$              1,004,760
Operating Expenses:
Operation -
Fuel, purchased and net interchange power	688,773	664,927
Other	133,574	144,264
Maintenance	21,434	20,452
Depreciation	38,189	35,743
Amortization of regulatory liabilities, net	(330)	(1,894)
Amortization of rate reduction bonds	35,661	33,453
Taxes other than income taxes	47,421	47,046
Total operating expenses	964,722	943,991
Operating Income	78,964	60,769
Interest Expense:
Interest on long-term debt	17,616	14,073
Interest on rate reduction bonds	10,120	12,584
Other interest	7,322	1,445
Interest expense, net	35,058	28,102
Other Income, Net	5,851	9,289
Income Before Income Tax Expense	49,757	41,956
Income Tax Expense	14,763	8,126
Net Income	$                   34,994	$                   33,830
The accompanying notes are an integral part of these condensed consolidated financial statements.

32

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Three Months Ended
	March 31,
	2007	2006
	(Thousands of Dollars)
Operating Activities:
Net income	$                   34,994	$                   33,830
Adjustments to reconcile to net cash flows
used in operating activities:
Bad debt expense	3,838	2,909
Depreciation	38,189	35,743
Deferred income taxes	7,337	72,674
Amortization of regulatory liabilities	(330)	(1,894)
Amortization of rate reduction bonds	35,661	33,453
Amortization/(deferral) of recoverable energy costs	1,032	(72,642)
Pension (income)/expense, net of capitalized portion	(1,609)	420
Regulatory refunds	(16,708)	(100,683)
Deferred contractual obligations	(8,139)	(16,838)
Other non-cash adjustments	4,297	(7,324)
Other sources of cash	3,974	2,338
Other uses of cash	(5,960)	(12,526)
Changes in current assets and liabilities:
Receivables and unbilled revenues, net	(7,091)	33,104
Materials and supplies	(4,773)	(796)
Investments in securitizable assets	(30,810)	11,149
Other current assets	(8,460)	(6,983)
Accounts payable	(12,614)	56,996
Taxes receivable and accrued taxes	(163,382)	(86,598)
Other current liabilities	(13,788)	(10,815)
Net cash flows used in operating activities	(144,342)	(34,483)
Investing Activities:
Investments in plant	(158,634)	(124,212)
Proceeds from sales of investment securities	263	245
Purchases of investment securities	(283)	(254)
Rate reduction bond escrow	50,711	(775)
Other investing activities	1,211	(1,778)
Net cash flows used in investing activities	(106,732)	(126,774)
Financing Activities:
Issuance of long-term debt	300,000	-
Retirement of rate reduction bonds	(77,796)	(39,175)
Increase in short-term debt	-	125,000
(Decrease)/increase in NU Money Pool borrowing	(162,500)	94,600
Capital contributions from Northeast Utilities Parent	215,000	-
Cash dividends on preferred stock	(1,390)	(1,390)
Cash dividends on common stock	(19,795)	(15,933)
Other financing activities	(4,404)	(162)
Net cash flows provided by financing activities	249,115	162,940
Net (decrease)/increase in cash	(1,959)	1,683
Cash - beginning of period	3,310	2,301
Cash - end of period	$                     1,351	$                     3,984
The accompanying notes are an integral part of these condensed consolidated financial statements.

33

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34

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE

35

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,	December 31,
	2007	2006
	(Thousands of Dollars)
ASSETS
Current Assets:
Cash	$                        541	$                            31
Receivables, less provision for uncollectible
accounts of $3,155 in 2007 and $2,626 in 2006	85,296	86,784
Accounts receivable from affiliated companies	54	590
Unbilled revenues	40,641	44,433
Taxes receivable	7,833	6,671
Fuel, materials and supplies	68,704	84,856
Derivative assets - current	2,570	-
Prepayments and other	29,322	12,652
	234,961	236,017
Property, Plant and Equipment:
Electric utility	1,895,032	1,893,124
Other	6,272	5,816
	1,901,304	1,898,940
Less: Accumulated depreciation	723,118	723,764
	1,178,186	1,175,176
Construction work in progress	86,096	67,202
	1,264,282	1,242,378
Deferred Debits and Other Assets:
Regulatory assets	483,146	524,536
Other	72,826	68,345
	555,972	592,881
Total Assets	$              2,055,215	$                2,071,276
The accompanying notes are an integral part of these condensed consolidated financial statements.

36

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,	December 31,
	2007	2006
	(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION
Current Liabilities:
Notes payable to affiliated companies	$                      27,000	$                      36,500
Accounts payable	61,129	69,948
Accounts payable to affiliated companies	21,165	22,327
Accrued taxes	331	-
Accrued interest	12,782	8,641
Derivative liabilities - current	11,136	39,180
Other	11,297	2,362
	144,840	178,958
Rate Reduction Bonds	321,497	333,831
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	208,186	200,136
Accumulated deferred investment tax credits	803	877
Deferred contractual obligations	33,856	35,623
Regulatory liabilities	124,256	115,731
Accrued pension	154,136	150,634
Accrued postretirement benefits	35,635	36,521
Other	43,893	44,304
	600,765	583,826
Capitalization:
Long-Term Debt	507,103	507,099
Common Stockholder's Equity:
Common stock, $1 par value - authorized
100,000,000 shares; 301 shares outstanding
in 2007 and 2006	-	-
Capital surplus, paid in	240,724	231,171
Retained earnings	240,101	236,215
Accumulated other comprehensive income	185	176
Common Stockholder's Equity	81,010	467,562
Total Capitalization	988,113	974,661
Commitments and Contingencies (Note 6)
Total Liabilities and Capitalization	$                 2,055,215	$                 2,071,276
The accompanying notes are an integral part of these condensed consolidated financial statements.

37

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
	Three Months Ended
	March 31,
	2007	2006
	(Thousands of Dollars)
Operating Revenues	$                    277,096	$                    315,316
Operating Expenses:
Operation -
Fuel, purchased and net interchange power	142,425	142,238
Other	53,051	42,975
Maintenance	17,404	13,491
Depreciation	13,289	12,249
Amortization of regulatory assets, net	3,794	62,076
Amortization of rate reduction bonds	12,906	12,191
Taxes other than income taxes	10,150	10,095
Total operating expenses	253,019	295,315
Operating Income	24,077	20,001
Interest Expense:
Interest on long-term debt	6,151	5,724
Interest on rate reduction bonds	4,708	5,535
Other interest	593	230
Interest expense, net	11,452	11,489
Other Income, Net	673	1,319
Income Before Income Tax Expense	13,298	9,831
Income Tax Expense	3,331	4,699
Net Income	$                        9,967	$                        5,132
The accompanying notes are an integral part of these condensed consolidated financial statements.

38

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Three Months Ended
	March 31,
	2007	2006
	(Thousands of Dollars)
Operating activities:
Net income	$                  9,967	$                  5,132
Adjustments to reconcile to net cash flows
provided by operating activities:
Bad debt expense	715	849
Depreciation	13,289	12,249
Deferred income taxes	(6,731)	(25,760)
Amortization of regulatory assets, net	3,794	62,076
Amortization of rate reduction bonds	12,906	12,191
Pension expense, net of capitalized portion	3,911	3,887
Regulatory overrecoveries/(underrecoveries)	1,470	(333)
Deferred contractual obligations	(1,767)	(3,556)
Other non-cash adjustments	(365)	(1,794)
Other uses of cash	(5,919)	(3,717)
Changes in current assets and liabilities:
Receivables and unbilled revenues, net	5,101	(4,109)
Fuel, materials and supplies	16,152	(1,544)
Other current assets	9,604	3,609
Accounts payable	(3,737)	12,872
Taxes receivable and accrued taxes	3,334	25,650
Other current liabilities	(1,411)	(440)
Net cash flows provided by operating activities	60,313	97,262
Investing Activities:
Investments in plant	(39,768)	(35,099)
Proceeds from sales of investment securities	450	420
Purchases of investment securities	(485)	(436)
Increase in NU Money Pool Lending	-	(4,100)
Other investing activities	44	(3,075)
Net cash flows used in investing activities	(39,759)	(42,290)
Financing Activities:
Retirement of rate reduction bonds	(12,334)	(11,571)
Decrease in NU Money Pool borrowing	(9,500)	(15,900)
Capital contributions from Northeast Utilities Parent	9,500	-
Cash dividends on common stock	(7,680)	(23,000)
Other financing activities	(30)	(60)
Net cash flows used in financing activities	(20,044)	(50,531)
Net increase in cash	510	4,441
Cash - beginning of period	31	27
Cash - end of period	$                     541	$                  4,468
The accompanying notes are an integral part of these condensed consolidated financial statements.

39

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40

WESTERN MASSACHUSETTS ELECTRIC COMPANY

41

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,		December 31,
	2007		2006
	(Thousands of Dollars)
ASSETS
Current Assets:
Cash		$                   1,503		$                   1,336
Receivables, less provision for uncollectible
accounts of $5,339 in 2007 and $5,073 in 2006		54,313		43,182
Accounts receivable from affiliated companies		5,403		5,628
Unbilled revenues		17,131		15,940
Taxes receivable		16,558		-
Materials and supplies		1,848		1,875
Marketable securities - current		26,705		28,054
Prepayments and other		1,850		1,080
		125,311		97,095
Property, Plant and Equipment:
Electric utility		708,870		703,723
Less: Accumulated depreciation		204,019		201,099
		504,851		502,624
Construction work in progress		27,220		23,470
		532,071		526,094
Deferred Debits and Other Assets:
Regulatory assets		240,447		252,346
Prepaid pension		71,600		69,933
Marketable securities - long-term		28,024		25,964
Other		14,762		17,261
		354,833		365,504
Total Assets		$            1,012,215		$               988,693
The accompanying notes are an integral part of these condensed consolidated financial statements.

42

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,		December 31,
	2007		2006
	(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION
Current Liabilities:
Notes payable to affiliated companies		$             73,900		$                30,800
Accounts payable		26,162		28,008
Accounts payable to affiliated companies		15,110		4,184
Accrued taxes		807		27,615
Accrued interest		1,616		4,546
Other		8,343		9,273
		125,938		104,426
Rate Reduction Bonds		96,168		99,428
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		198,296		197,881
Accumulated deferred investment tax credits		2,243		2,319
Deferred contractual obligations		48,508		50,711
Regulatory liabilities		24,382		26,756
Accrued postretirement benefits		13,937		14,293
Other		12,368		12,136
		299,734		304,096
Capitalization:
Long-Term Debt		262,487		261,777
Common Stockholder's Equity:
Common stock, $25 par value - authorized
1,072,471 shares; 434,653 shares outstanding
in 2007 and 2006		10,866		10,866
Capital surplus, paid in		119,365		114,544
Retained earnings		96,822		92,663
Accumulated other comprehensive income		835		893
Common Stockholder's Equity		227,888		218,966
Total Capitalization		490,375		480,743
Commitments and Contingencies (Note 6)
Total Liabilities and Capitalization		$         1,012,215		$              988,693
The accompanying notes are an integral part of these condensed consolidated financial statements.

43

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
	Three Months Ended
	March 31,
	2007	2006
	(Thousands of Dollars)
Operating Revenues	$             129,558	$               129,040
Operating Expenses:
Operation -
Fuel, purchased and net interchange power	71,171	88,875
Other	24,427	15,538
Maintenance	4,332	3,832
Depreciation	5,248	4,293
Amortization of regulatory assets/(liabilities), net	2,289	(2,186)
Amortization of rate reduction bonds	3,231	3,034
Taxes other than income taxes	3,425	3,478
Total operating expenses	114,123	116,864
Operating Income	15,435	12,176
Interest Expense:
Interest on long-term debt	2,649	2,744
Interest on rate reduction bonds	1,521	1,762
Other interest	565	248
Interest expense, net	4,735	4,754
Other Income, Net	488	780
Income Before Income Tax Expense	11,188	8,202
Income Tax Expense	4,271	3,025
Net Income	$                 6,917	$                   5,177
The accompanying notes are an integral part of these condensed consolidated financial statements.

44

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Three Months Ended
	March 31,
	2007	2006
	(Thousands of Dollars)
Operating Activities:
Net income	$                 6,917	$                   5,177
Adjustments to reconcile to net cash flows
used in operating activities:
Bad debt expense	1,279	1,077
Depreciation	5,248	4,293
Deferred income taxes	(1,935)	4,953
Amortization of regulatory assets/(liabilities), net	2,289	(2,186)
Amortization of rate reduction bonds	3,231	3,034
Pension income, net of capitalized portion	(656)	(143)
Regulatory overrecoveries/(underrecoveries)	3,188	(12,098)
Deferred contractual obligations	(2,203)	(4,636)
Other non-cash adjustments	767	(1,945)
Other sources of cash	1,307	1,670
Other uses of cash	(184)	(568)
Changes in current assets and liabilities:
Receivables and unbilled revenues, net	(13,930)	(4,100)
Materials and supplies	27	(3)
Other current assets	(770)	167
Accounts payable	10,087	1,577
Taxes receivable and accrued taxes	(41,186)	(2,476)
Other current liabilities	(2,945)	(3,695)
Net cash flows used in operating activities	(29,469)	(9,902)
Investing Activities:
Investments in plant	(10,821)	(10,385)
Proceeds from sales of investment securities	28,441	11,279
Purchases of investment securities	(29,196)	(11,839)
Other investing activities	(233)	(477)
Net cash flows used in investing activities	(11,809)	(11,422)
Financing Activities:
Retirement of rate reduction bonds	(3,260)	(3,064)
Increase in short-term debt	-	10,000
Increase in NU Money Pool borrowing	43,100	3,000
Capital contributions from Northeast Utilities Parent	4,800	14,500
Cash dividends on common stock	(3,195)	(1,986)
Net cash flows provided by financing activities	41,445	22,450
Net increase in cash	167	1,126
Cash - beginning of period	1,336	1
Cash - end of period	$                 1,503	$                   1,127
The accompanying notes are an integral part of these condensed consolidated financial statements.

45

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 Northeast Utilities and subsidiaries combined 2006 Form 10-K as filed with the Securities and Exchange Commission (SEC) (NU 2006 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) earned $75.1 million, or $0.49 per share, in the first quarter of 2007, compared with a loss of $10.1 million, or $0.07 per share, in the first quarter of 2006.  The results in 2007 included regulated companies net income of $64.1 million, or $0.42 per share, after payment of preferred dividends, NU Enterprises, Inc. (NU Enterprises) net income of $4.8 million, or $0.03 per share, and parent and affiliates net income of $6.2 million, or $0.04 per share.  

·

Earnings at the distribution segments of The Connecticut Light and Power Company (CL&P), Public Service Company of New Hampshire (PSNH) (including regulated generation), Western Massachusetts Electric Company (WMECO) and Yankee Gas Services Company (Yankee Gas) totaled $48.2 million in the first quarter of 2007, compared with $41.9 million in the first quarter of 2006.

·

The transmission segments of CL&P, PSNH and WMECO earned $15.9 million in the first quarter of 2007, compared with $12.7 million in the first quarter of 2006.

·

NU Enterprises earned $4.8 million in the first quarter of 2007, compared with a loss of $62.6 million in the first quarter of 2006.  

·

NU continues to project consolidated 2007 earnings of between $1.30 per share and $1.55 per share.  The company's earnings guidance does not include the impact of marking-to-market NU Enterprises' remaining wholesale energy contracts.

Regulatory and Other Items:

·

CL&P expects to file a distribution rate case in mid-2007 for new rates effective in early 2008.

·

On December 29, 2006, Yankee Gas filed a request with the Connecticut Department of Public Utility Control (DPUC) for a rate increase of approximately $67.8 million effective on July 1, 2007, partially offset by projected commodity and pipeline-related savings, for a net revenue increase of $37.2 million or 8.4 percent above current rates.  Hearings in the rate case have concluded.  Yankee Gas was granted a suspension by the DPUC in the procedural schedule to engage in settlement discussions.  If no settlement agreement is reached, then the procedural schedule would resume.  

·

On February 26, 2007, PSNH filed a settlement agreement it reached with the New Hampshire Public Utilities Commission (NHPUC) staff and the Office of Consumer Advocate (OCA) related to its rate case filing.  The settlement agreement includes, among other things, a transmission cost tracking mechanism, effective on July 1, 2006, to be reset annually, and an allowed return on equity (ROE) of 9.67 percent.  The allowed generation ROE of 9.62 percent was unaffected.  The settlement agreement provides for a $37.7 million estimated annualized increase beginning on July 1, 2007, in addition to the $24.5 million temporary increase that was effective on July 1, 2006.  Hearings on the settlement agreement have concluded and PSNH is awaiting a NHPUC order.  A final decision is expected in the second quarter of 2007.

·

On March 30, 2007, CL&P filed a metering compliance plan with the DPUC that would meet the DPUC's objective of offering time-of-use rates to all CL&P customers.  The DPUC has scheduled hearings on the plan for the second quarter of 2007.

·

On April 17, 2007, CL&P filed for new rates effective on July 1, 2007 that will decrease the average standard service rate from $0.11241 per kilowatt-hour (KWH) to $0.10791 per KWH, which in turn will decrease the overall rate for standard service

46

customers by approximately 4.5 percent.  At the same time, for the average supplier of last resort rate, CL&P requested an increase from $0.11359 per KWH to $0.11571 per KWH, which in turn will increase the overall rate for supplier of last resort service customers by approximately 1.4 percent.

·

On May 3, 2007, the DPUC issued a decision that selected four projects that would be eligible to sign contracts with CL&P and United Illuminating (UI).  These projects include three new generating plants that combined would add approximately 782 megawatts (MW) of generating capacity and 5 MW of demand-side measures in Connecticut.  The decision substantially approved the provisions that CL&P sought regarding cost recovery of these arrangements.  Executed contracts are expected to be approved by the DPUC no later than August 15, 2007.

Liquidity:

·

The company's consolidated cash on hand declined in the first quarter of 2007, primarily as a result of the payment of federal and state income taxes related to the sale of the competitive generation business.  However, NU's liquidity position continued to be strong in the first quarter of 2007, primarily as a result of the proceeds the company received from the sale of NU Enterprises' competitive generation assets in November of 2006 and the issuance of $300 million of CL&P long-term debt at March 31, 2007.  NU parent had $443.2 million invested in the NU money pool (pool) and will continue to infuse equity into the regulated companies as these companies build out their infrastructure.

·

NU's cash capital expenditures totaled $227.7 million in the first quarter of 2007, compared with $203.8 million in the first quarter of 2006.  The increase in NU's cash capital expenditures was primarily the result of higher transmission and distribution capital expenditures, particularly at CL&P.

·

Cash flows from operations were a negative $266.6 million in the first quarter of 2007, primarily due to federal and state income tax payments totaling $398.5 million made in the first quarter of 2007 related to the sale of the competitive generation business.  Aside from the tax payments, NU's cash flows from operations in the first quarter of 2007 totaled $131.9 million.  The improved 2007 cash flows excluding the tax payments were due primarily to a reduction in regulatory refunds, a reduction in payments made to the Connecticut Yankee Atomic Power Company (CYAPC), the Yankee Atomic Electric Company (YAEC) and the Maine Yankee Atomic Power Company (MYAPC) (collectively, the Yankee Companies) for decommissioning and closure costs, lower cash payments related to Select Energy Inc.'s (Select Energy) derivative contracts settled and changes in working capital items related to the divestiture of the NU Enterprises businesses in 200 6.  Cash flows from operations were a positive $42.7 million in the first quarter of 2006.

Overview

Consolidated:  NU earned $75.1 million, or $0.49 per share, in the first quarter of 2007, compared with a loss of $10.1 million, or $0.07 per share, in the first quarter of 2006.  A summary of NU's earnings/(losses) by segment, which may or may not reflect aggregations of specific subsidiaries, for the first quarter of 2007 and 2006 is as follows:

	For the Three Months Ended March 31,
	2007				2006
(Millions of Dollars, except per share amounts)	Amount		Per Share		Amount		Per Share
Regulated companies	$	64.1	$	0.42	$	54.6	$	0.35
NU Enterprises		4.8		0.03		(62.6)		(0.41)
Parent and affiliates		6.2		0.04		(2.1)		(0.01)
Net Income/(Loss)	$	75.1	$	0.49	$	(10.1)	$	(0.07)

The only common equity securities that are publicly traded are common shares of NU.  The earnings per share (EPS) 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 interest in NU's assets and liabilities as a whole.  EPS by segment is a non-GAAP measure.  Management uses this measure to provide segmented earnings guidance and believes that this measurement is useful to investors to evaluate the actual financial performance and contribution of its business segments.  These non-GAAP measures should not be considered as an alternative to EPS determined in accordance with GAAP as an indicator of operating performance.

Regulated Companies:  NU's regulated companies, which are comprised of CL&P, PSNH, WMECO and Yankee Gas, segment their earnings between their electric transmission segment and their electric and gas distribution segments, with PSNH generation included with the distribution segment.  A summary of regulated company earnings by segment for the first quarter of 2007 and 2006 is as follows:

47

	For the Three Months Ended March 31,
(Millions of Dollars)	2007		2006
CL&P Transmission*	$	13.0	$	9.1
PSNH Transmission		1.9		2.6
WMECO Transmission		1.0		1.0
Total Transmission		15.9		12.7
CL&P Distribution*		20.6		23.4
PSNH Distribution and Generation		8.1		2.5
WMECO Distribution		5.9		4.2
Yankee Gas		13.6		11.8
Total Distribution and Generation		48.2		41.9
Total Net Income	$	64.1	$	54.6

*After preferred dividends in all periods.

The higher first quarter 2007 transmission segment earnings reflect a higher level of investment in this segment as the company builds out its infrastructure to meet the region’s reliability needs.  CL&P’s transmission earnings increased primarily due to CL&P’s significant ongoing investment in projects in southwest Connecticut.  

CL&P’s first quarter 2007 distribution segment earnings were lower than the same period of 2006 due to higher interest, depreciation and property tax expenses and the absence of a state tax settlement that benefited CL&P by $4.9 million in the first quarter of 2006, partially offset by a 1.6 percent increase in sales in the first quarter of 2007 and a $7 million annualized distribution rate increase that took effect on January 1, 2007.  Earnings in the first quarter of 2006 also included approximately $1.7 million related to a fixed procurement fee of 0.50 mills per KWH that CL&P was allowed to collect from customers who purchased Transitional Standard Offer (TSO) service through December 31, 2006.  Management continues to estimate that CL&P’s ROE will be between 6 percent and 6.5 percent in 2007, below its allowed 9.85 percent ROE.  For the 12 months ended March 31, 2007, CL&P's Regulatory ROE was 7.65 percent.

PSNH’s first quarter 2007 distribution and generation segment earnings were higher than the same period of 2006 primarily due to a temporary distribution rate increase that took effect on July 1, 2006, a 2.7 percent increase in sales, and a lower effective tax rate in 2007.  For the 12 months ended March 31, 2007, PSNH's Regulatory ROE was 7.8 percent.  Management expects that PSNH will be able to earn between a 9 percent and 10 percent ROE for the two years after rates go into effect, if its settlement agreement is approved by the NHPUC.

WMECO’s first quarter 2007 distribution segment results were higher than the same period of 2006 due to a 1.7 percent increase in sales and the impact of a distribution rate settlement that took effect January 1, 2007, which included an annualized distribution rate increase of $1 million.  For the 12 months ended March 31, 2007, WMECO's Regulatory ROE was 9.9 percent.  Management expects that WMECO will be able to earn between a 9 percent and 10 percent ROE during 2007 and 2008.

Yankee Gas' first quarter 2007 earnings were higher than the same period of 2006 due to colder weather, which helped generate a 10.9 percent increase in firm natural gas sales.  Despite the improvement in weather, Yankee Gas' Regulatory ROE was 6.7 percent for the 12 months ended March 31, 2007, below the 9.9 percent ROE allowed in Yankee Gas’ 2004 rate settlement agreement. In 2007, Yankee Gas expects its earnings and ROE to improve as a result of its rate case.

For the distribution segment of the regulated companies, a summary of changes in CL&P, PSNH and WMECO electric KWH sales and Yankee Gas firm natural gas sales for the first quarter of 2007 as compared to 2006 on an actual and weather normalized basis is as follows:

	Electric								Firm Natural Gas
	CL&P		PSNH		WMECO		Total		Yankee Gas
	Percentage Increase/ (Decrease)	Weather Normalized Percentage Increase/ (Decrease)	Percentage Increase/ (Decrease)	Weather Normalized Percentage Increase/ (Decrease)	Percentage Increase/ (Decrease)	Weather Normalized Percentage Increase/ (Decrease)	Percentage Increase/ (Decrease)	Weather Normalized Percentage Increase/ (Decrease)	Percentage Increase/ (Decrease)	Weather Normalized Percentage Increase/ (Decrease)
Residential	4.9 %	1.8 %	5.7 %	3.2 %	4.2 %	1.4 %	5.0 %	2.0 %	17.8 %	8.4 %
Commercial	0.5 %	(0.1)%	3.0 %	2.2 %	2.3 %	1.8 %	1.3 %	0.7 %	12.2 %	3.9 %
Industrial	(8.3)%	(8.3)%	(4.2)%	(4.2)%	(4.3)%	(4.3)%	(6.5)%	(6.5)%	(0.5)%	(3.5)%
Other	18.3 %	18.3 %	0.2 %	0.2 %	(1.0)%	(1.0)%	15.4 %	15.4 %	N/A	N/A
Total	1.6 %	(0.1)%	2.7 %	1.4 %	1.7 %	0.4 %	1.9 %	0.3 %	10.9%	3.7 %

NU Enterprises:  NU Enterprises continues to wind down and pursue divestiture opportunities for its remaining wholesale contracts and energy services businesses.  

48

NU's condensed consolidated statements of income/(loss) for all periods presented classify the operations for the following as discontinued operations:

·

The services business of the former Woods Electrical Co., Inc. (Woods Electrical - Services), which was sold in April of 2006,

·

Select Energy Services, Inc. (SESI), which was sold in May of 2006,

·

Northeast Generation Company (NGC), which was sold in November of 2006 (including certain components of Northeast Generation Services Company (NGS)), and

·

Holyoke Water Power Company's (HWP) Mt. Tom generating plant, which was sold in November of 2006.

NU Enterprises earned $4.8 million in the first quarter of 2007, compared with a loss of $62.6 million in the first quarter of 2006.  NU Enterprises earnings in the first quarter of 2007 were primarily due to positive outcomes related to the divestiture of these businesses, a $1.5 million positive mark-to-market impact associated with Select Energy's remaining wholesale marketing contracts, and the lack of losses at the energy services businesses.

In the first quarter of 2006, NU Enterprises recorded losses related to Select Energy's retail marketing business, which was sold on June 1, 2006.  The retail marketing business recorded losses of $69.8 million in the first quarter of 2006 (excluding restructuring charges), which included an after-tax loss of $39.1 million ($59.9 million pre-tax) to reflect the estimated fair value of the retail marketing business less its cost to sell.  First quarter 2006 losses also included losses totaling $0.8 million at the energy services businesses.

Parent and Affiliates:  Parent company and affiliates earned $6.2 million in the first quarter of 2007, compared with a loss of $2.1 million in the first quarter of 2006.  First quarter 2007 results benefited from an increase in income generated by higher cash and cash equivalent balances and investments in the pool as a result of the proceeds received from the sale of the competitive generation business in 2006.  The pool investments are eliminated in consolidation along with the corresponding interest expense for the pool borrowers.  The company expects that parent company earnings will decline over the remaining quarters of 2007 as the parent company’s cash was used to pay taxes in March of 2007 related to the sale of the competitive generation business and will be used to make equity investments in the regulated companies to support capital expenditures.  Also, parent company results in the first quarter of 2006 were negatively affected by $1.3 m illion of additional environmental reserves recorded associated with a HWP manufactured gas plant coal tar site.

Future Outlook

NU continues to project consolidated 2007 earnings of between $1.30 per share and $1.55 per share.  The company's earnings guidance does not include the impact of marking-to-market NU Enterprises' remaining wholesale energy contracts.

Regulated Companies:  NU continues to project 2007 earnings of between $0.80 per share and $0.90 per share at the distribution and generation segment and between $0.50 per share and $0.60 per share at the transmission segment of the regulated companies.  Among other items, those projections may be impacted by the outcome in the Yankee Gas rate case and assume that the regulated companies achieve their projected level of capital expenditures, particularly in the transmission segment, in accordance with their present schedule.

Parent and Affiliates:  NU continues to project 2007 earnings of between zero and $0.05 per share at NU parent and affiliates.

NU Enterprises:  NU continues to project breakeven results at NU Enterprises.   This earnings guidance does not include the impact of marking-to-market NU Enterprises' remaining wholesale energy contracts.  For information regarding sensitivity analyses of the remaining wholesale energy positions, see Item 3, "Quantitative and Qualitative Disclosures About Market Risk," included in this report on Form 10-Q.  

Long-Term Growth Rate:NU continues to project that it can achieve compounded annual EPS growth of between 10 percent and 14 percent over 2006 annual EPS for the period of 2007 through 2011.  For this comparison, 2006 annual EPS represents 2006 regulated company and parent and affiliates results of $1.16 per share, which excludes a $0.48 per share benefit associated with an Internal Revenue Service private letter ruling affecting CL&P in 2006.  That growth rate is based on a compounded annual growth of approximately 7 percent in the regulated companies' distribution and generation segment rate base and approximately 23 percent in the regulated companies' transmission segment rate base.  This EPS growth rate assumes appropriate regulatory approvals and timely rate treatment associated with the company's electric transmission and distribution investments and natural gas distribution investments.  It also assumes the company achieves its projected levels of c apital expenditures and rate base growth in accordance with its present schedule.  

49

Liquidity

Consolidated:NU's liquidity position continued to be strong in the first quarter of 2007, primarily as a result of the proceeds the company received from the sale of NU Enterprises' competitive generation assets in November of 2006 and the issuance of $300 million of CL&P long-term debt.  At March 31, 2007, NU parent had no borrowings under its $500 million revolving credit line, the regulated companies had no borrowings under their $400 million revolving credit line and CL&P had no sales of accounts receivable under its $100 million accounts receivable sales facility.  The company had $214.7 million of cash and cash equivalents on hand at March 31, 2007.

The company's level of consolidated cash on hand declined in the first quarter of 2007 primarily as a result of the payment of $398.5 million in federal and state income taxes.  Of that amount, $177.2 million was paid by CL&P, $47.9 million was paid by WMECO and $173.4 million was paid by other NU companies.  CL&P and WMECO's tax obligations were due to the fact that the sale of the generation assets from CL&P and WMECO to NGC in 2000 did not trigger federal or state income tax payments by those companies at that time.  It was not until these assets were sold to an unaffiliated third party in November of 2006 that CL&P and WMECO were required to pay this deferred tax obligation.

Primarily as a result of those tax payments, NU had negative consolidated cash flows from operations in the first quarter of 2007 of $266.6 million, compared with positive cash flows from operations of $42.7 million in the first quarter of 2006.  Aside from the tax payments, NU's cash flows from operations in the first quarter of 2007 totaled $131.9 million.  The improved 2007 cash flows excluding the tax payments above were primarily due to a $115.7 million reduction in regulatory refunds related to amounts refunded primarily to CL&P ratepayers during the first quarter of 2006 as compared to the first quarter of 2007.  In addition to lower regulatory refunds paid, lower payments were made to the Yankee Companies for decommissioning and closure costs in the first quarter of 2007 as compared to 2006, primarily as a result of the extension of the collection period for CYAPC's decommissioning and closure costs.  Also impacting cash flows from operations were lower c ash payments related to Select Energy’s derivative contracts settled and changes in working capital items related to the divestiture of NU Enterprises' businesses in 2006.

NU's cash position is expected to continue to fluctuate in 2007.  NU continues to forecast capital expenditures of approximately $1.2 billion and common and preferred dividends of approximately $125 million in 2007.  As a result, NU and the regulated companies expect they will need to borrow under their respective credit facilities in 2007 and issue approximately $650 million in long-term debt in 2007.  In the first of such issuances, on March 27, 2007, CL&P sold $150 million of 10-year bonds carrying a coupon rate of 5.375 percent and $150 million of 30-year bonds carrying a coupon rate of 5.75 percent.  Because of two interest rate hedges CL&P executed earlier in 2007, CL&P paid $2.6 million to the hedge counterparties at the closing of that transaction.

On February 2, 2007, the Massachusetts Department of Telecommunications and Energy (DTE) (effective on April 11, 2007, known as the Massachusetts Department of Public Utilities (DPU)) approved the issuance of up to $60 million of unsecured long-term debt by WMECO.  On March 7, 2007, the DPUC approved the issuance of up to $60 million of secured or unsecured long-term debt by Yankee Gas and on March 30, 2007, the DPUC approved the issuance of up to $750 million of long-term debt by CL&P through 2010.  On March 30, 2007, PSNH received approval from the NHPUC which was effective on April 30, 2007 to change its short-term debt limit to 10 percent of net fixed plant and to increase that limit temporarily to 13 percent until the earlier of a PSNH long-term debt refinancing, currently planned for the second half of 2007, or December 31, 2007.  The previous short-term debt limit was fixed at $100 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), respectively.  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).  If NU's senior unsecured ratings were reduced to sub-investment grade by either Moody's or S&P, Select Energy could, under its present contracts, be asked to provide approximately $137.7 million of collateral or LOCs to various unaffiliated counterparties and approximately $57 million to several independent system operators and unaffiliated local distribution companies (LDCs) in each case at March 31, 2007.  If such a downgrade were to occur, NU would currently be able to provide that collateral.  

NU paid common dividends of $29.2 million in the first quarter of 2007, compared with $27.2 million in the first quarter of 2006.  The increase primarily reflects a 7.1 percent increase in NU's common dividend that took effect in the third quarter of 2006.  On April 10, 2007, the NU Board of Trustees approved a dividend of $0.1875 per share, payable on June 29, 2007 to shareholders of record as of June 1, 2007.  On May 8, 2007, the NU Board of Trustees approved a dividend of $0.20 per share, a 6.7 percent increase over the previous rate, payable on September 28, 2007 to shareholders of record as of September 1, 2007.  

Management expects to continue its current policy of dividend increases, subject to the approval of the NU Board of Trustees and the company's future earnings and cash requirements.  In general, the regulated companies pay approximately 60 percent of their cash earnings to NU in the form of common dividends.  In the first quarter of 2007, CL&P, PSNH, WMECO, and Yankee Gas paid $19.8 million, $7.7 million, $3.2 million, and $12.7 million, respectively, in common dividends to NU.  For the three months ended

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March 31, 2007, NU parent contributed $215 million of equity to CL&P, $9.5 million to PSNH and $4.8 million to WMECO.  There were no equity contributions made to Yankee Gas in the first quarter of 2007.  At March 31, 2007, NU parent had $443.2 million invested in the pool and will continue to infuse equity into the regulated companies as these companies build out their infrastructure.

NU's ability to pay dividends is not regulated under the Federal Power Act, but may be affected by certain state statutes, the leverage restrictions in its revolving credit agreement and the ability of its subsidiaries to pay dividends to it.  The Federal Power Act limits the payment of dividends by CL&P, PSNH and WMECO to their retained earnings balances, and PSNH is required to reserve an additional amount under its Federal Energy Regulatory Commission (FERC) hydroelectric license conditions.  In addition, certain state statutes may impose additional limitations on such companies and on Yankee Gas.  CL&P, PSNH, WMECO and Yankee Gas also have a revolving credit agreement that imposes leverage restrictions.

Cash capital expenditures included on the accompanying condensed consolidated statements of cash flows and described in the liquidity section of this management's discussion and analysis do not include cost of removal, the allowance for funds used during construction (AFUDC) related to equity funds and the capitalized portion of pension expense or income.  NU's cash capital expenditures totaled $227.7 million in the first quarter of 2007, compared with $203.8 million in the first quarter of 2006.  NU's first quarter 2007 cash capital expenditures included $158.6 million by CL&P, $39.8 million by PSNH, $10.8 million by WMECO, $14.4 million by Yankee Gas, and $4.1 million by other NU subsidiaries.  The increase in NU's cash capital expenditures was primarily the result of higher transmission capital expenditures, particularly at CL&P.  

Regulated Companies:  The regulated companies maintain a $400 million credit line that expires on November 6, 2010.  There were no borrowings outstanding under that facility at March 31, 2007.

In addition to its revolving credit facility, 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.  There were no amounts outstanding under that facility at March 31, 2007. For more information regarding the sale of receivables, see Note 1F, "Summary of Significant Accounting Policies - Sale of Customer Receivables," to the condensed consolidated financial statements.

NU Enterprises:  Most of the working capital and LOCs required by NU Enterprises are currently used to support the wholesale marketing business.  As NU Enterprises' wholesale marketing contracts expire or are exited, its liquidity requirements will continue to decline.

Business Development and Capital Expenditures

Consolidated:  NU's capital expenditures, including cost of removal, AFUDC, and the capitalized portion of pension expense or income, totaled $221.4 million in the first quarter of 2007, compared with $192.7 million in the first quarter of 2006.  These amounts include $1.3 million and $8.4 million for the first quarter of 2007 and 2006, respectively, that are unrelated to the regulated companies.  Capital expenditures for the regulated companies are expected to total $1.2 billion in 2007.

Regulated Companies:

Transmission Segment:  The increase in transmission segment capital expenditures in the first quarter of 2007 as compared with 2006 primarily relates to CL&P which is undertaking a significant enhancement of its transmission system in southwest Connecticut.  Capital expenditures for the transmission segment are expected to total $0.7 billion in 2007.  A summary of transmission segment capital expenditures by company in the first quarters of 2007 and 2006 is as follows (millions of dollars):

		For the Three Months Ended March 31,
		2007		2006
CL&P	$	106.4	$	83.3
PSNH		7.5		5.7
WMECO		2.1		3.5
Totals	$	116.0	$	92.5

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CL&P energized a 21-mile, 115 kilovolt (KV)/345 KV transmission project between Bethel, Connecticut and Norwalk, Connecticut, in October of 2006 and is working on three additional major projects in southwest Connecticut, all of which have been approved by the Connecticut Siting Council and the New England Independent System Operator (ISO-NE).  In addition to improving regional reliability, completion of the Bethel to Norwalk project is expected to reduce congestion costs charged to CL&P customers.  These three projects are:

·

A 69-mile, 115 KV/345 KV transmission project from Middletown to Norwalk, Connecticut.  This project is currently approximately 24 percent complete and CL&P's portion of this project is estimated to cost approximately $1.05 billion.  Although this project is currently expected to be completed by the end of 2009, opportunities to optimize schedule performance may result in an earlier completion date.  At March 31, 2007, CL&P has capitalized $248.9 million associated with this project;

·

A two-cable, 9-mile, 115 KV underground transmission project between Norwalk and Stamford, Connecticut (Glenbrook Cables), construction of which began in October of 2006.  Glenbrook Cables is intended to respond to the growing electric demand in the area and is expected to cost $183 million.  This project is currently approximately 30 percent complete and on schedule for a December 2008 in-service date.  At March 31, 2007, CL&P has capitalized $52.9 million associated with this project; and

·

The replacement of the existing 138 KV undersea cable between Connecticut and Long Island, which is on schedule and for which the engineering, permitting, contracting and cable manufacturing are complete or well underway.  CL&P and the Long Island Power Authority (LIPA) jointly filed plans with the Department of Environmental Protection (DEP) to replace this 11-mile 138 KV undersea electric transmission line between Norwalk and Northport - Long Island, New York and each own approximately 50 percent of the line.  CL&P's portion of the project is estimated to cost $72 million.  The project is approximately 33 percent complete and final permits are expected by mid-2007 with marine construction activities commencing in October of 2007 and a project in-service date expected in 2008.  At March 31, 2007, CL&P has capitalized $17.5 million associated with this project.

As part of a larger regional system plan, NU, ISO-NE and National Grid have begun planning upgrades to the 345 KV transmission system connecting Massachusetts, Rhode Island and Connecticut in a comprehensive study called the Southern New England Transmission Reinforcement Project.  That study has led to the identification of three interdependent 345 KV NU projects that work together to address the region's transmission needs: 1) the Greater Springfield 345 KV Reliability Project, 2) the Central Connecticut Reliability Project, and 3) the Interstate Reliability Project.  Together, these three projects, along with a fourth project, National Grid's Rhode Island Reliability Project, are referred to as the New England East-West Solution (NEEWS).  NU and National Grid have entered into a formal agreement to plan and permit these projects and expect to work with ISO-NE on the technical review of these projects for the remainder of 2007.  The filing of the first project appl ications with the various state siting authorities will occur shortly after receiving the technical approvals.  At this time, the company expects to begin construction of these projects in 2009, with construction being completed in 2013.  

In addition to NEEWS, studies also have identified that transmission infrastructure upgrades are required for the 115 KV system in the Springfield, Massachusetts area.  This WMECO project, referred to as the Springfield 115 KV Upgrade, will improve reliability and set the stage for enhancing access to competitively priced power and renewable energy.  WMECO expects to receive technical approval from ISO-NE by the end of 2007.  Once technical approval is received, WMECO also expects to present the Springfield 115 KV Upgrade to the Massachusetts Energy Facilities Siting Board in late 2007, receive all necessary siting approvals and begin construction by late 2008 or early 2009 and complete the project by 2010.  At this time, the company expects the Springfield 115 KV Upgrade to cost between $250 million and $350 million.

NU has not yet completed a detailed estimate of the total cost for NEEWS and the Springfield 115 KV Upgrade and the timing of expenditures is highly dependent upon receipt of technical and siting approvals.  Assuming virtually all of the 345 KV portions of the projects is constructed overhead and on existing rights of way, NU currently estimates that its share of the cost of both the Springfield 115 KV Upgrade and the NEEWS 345 KV projects may be towards the higher end of a $1.1 billion to $1.4 billion range, of which approximately $710 million is included in its $2.5 billion 2007 through 2011 capital budget.  

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Distribution and Generation Segment: In 2007, CL&P, PSNH, WMECO and Yankee Gas are projecting distribution segment (and in the case of PSNH also generation segment) capital expenditures of $270 million, $128 million, $34 million, and $62 million, respectively, totaling $0.5 billion.  A summary of distribution and generation segment capital expenditures by company in the first quarters of 2007 and 2006 is as follows (millions of dollars):

		For the Three Months Ended March 31,
		2007		2006
CL&P	$	56.1	$	45.8
PSNH		27.2		26.5
WMECO		7.6		5.7
Yankee Gas		13.1		13.3
Other		0.1		0.5
Totals	$	104.1	$	91.8

The first quarter 2007 capital expenditures at Yankee Gas included $4.5 million spent on 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.  Yankee Gas expects to begin filling the LNG facility in June of 2007 and it is anticipated that the LNG facility will be put in service mid-2007 in time for the 2007/2008 heating season.  The facility, which is expected to cost $108 million, is currently approximately 91 percent complete and Yankee Gas has capitalized $99.8 million related to this project.  

Transmission Rate Matters and FERC Regulatory Issues

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

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 under the FERC Electric Tariff No. 3, Open Access Transmission Tariff (OATT).  Tariff No. 3 includes the Regional Network Service (RNS) and Local Network Service (LNS) rate schedules.  The RNS rate, administered by ISO-NE, is set on June 1^st of each year and recovers the revenue requirements associated with transmission facilities that benefit the New England region.  The LNS rate, administered by NU, is set on January 1^st and June 1^st of each year and recovers the revenue requirements for local transmission facilities.  The LNS rate also provides for an annual true-up to total actual costs, which ensures that NU recovers its total (both regional and local) revenue requirements.

FERC ROE Decision:  As a result of theOctober 31, 2006 FERC ROE decision, the company recorded a total regulatory liability for refunds of $25.6 million as of December 31, 2006.  During the first quarter of 2007, the company refunded approximately $16.8 million of this regulatory liability to regional customers and expects to refund the remaining $8.8 million to local customers during 2007.  

Promoting Transmission Investment through Pricing Reform:  On July 20, 2006, the FERC issued final rules promoting transmission investment through pricing reform that included, among others, up to 100 percent of construction work in progress (CWIP) in rate base, accelerated book depreciation, and higher ROEs for belonging to an RTO.  The final rule identifies specific incentives the FERC will allow when justified in the context of specific rate applications.  The burden remains on the applicant to illustrate through its filing that the incentives requested are just and reasonable and the project involved increases reliability or decreases congestion costs.  The FERC largely reaffirmed the incentives in an order following rehearing on December 22, 2006 and on April 19, 2007, denied all requests for rehearing.

Legislative Matters

Connecticut:

2007 Legislation:  On March 13, 2007, the Connecticut legislature's Energy and Technology Committee issued favorable recommendations on a number of bills affecting the electric energy sector.  Among other initiatives, the bills seek to increase energy conservation funding, accelerate installation of "smart" metering, and provide more flexibility for procuring standard service energy for customers.  Legislative leadership is expected to combine the bills into a single bill before presenting it to the floor of the House and Senate.  The current legislative session ends on June 6, 2007. 

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New Hampshire:

2007 Legislation:   The New Hampshire legislature has passed a bill that would establish a renewable portfolio standard for electricity sold in the state.  The bill would require that 23 percent of the electricity sold to retail customers in New Hampshire have direct ties to renewable plants by 2025.  The bill has passed both the New Hampshire House and Senate.   The Governor has stated that he will sign the bill into law.

On April 12, 2007, the New Hampshire Senate passed a bill that directs the NHPUC to encourage upgrades to the transmission system in northern New Hampshire, directs the state site evaluation committee to develop new rules for siting renewable facilities by October 1, 2007 and adds utility ownership of distributed renewable generation and demand-side management to the topics that the legislature's standing committee on electric restructuring should examine.  The bill is now before the full House.  

Regulatory Developments and Rate Matters

Connecticut - CL&P:

Distribution Rates: A $7 million distribution rate increase took effect on January 1, 2007 for CL&P and CL&P expects to file a distribution rate case in mid-2007 for new rates effective in early 2008.

Time-of-Use Rates: On March 30, 2007, CL&P filed a metering compliance plan with the DPUC that would meet the DPUC's objective of offering time-of-use rates to all CL&P customers.  CL&P's filing discussed the technology, implementation options and costs comparing an Open Advanced Metering Infrastructure (AMI) system deployed on a geographic basis to a fixed AMR network system deployed on a usage-based priority schedule.  Depending on the technology and implementation schedule approved by the DPUC, the capital costs could range from $90 million to $300 million.  CL&P has requested recovery of all such costs through its Federally Mandated Congestion Charge (FMCC) rate mechanism.  The DPUC has scheduled hearings on the plan for the second quarter of 2007.

Standard Service Procurement and Rates:  On April 17, 2007, CL&P filed for new rates effective on July 1, 2007 that will decrease the average standard service rate from $0.11241 per KWH to $0.10791 per KWH, which in turn will decrease the overall rate for standard service customers by approximately 4.5 percent.  At the same time, for the average supplier of last resort rate, CL&P requested an increase from $0.11359 per KWH to $0.11571 per KWH, which in turn will increase the overall rate for supplier of last resort service customers by approximately 1.4 percent.  If approved by the DPUC, rates would take effect on July 1, 2007 through December 31, 2007.  CL&P is fully recovering the cost of its standard service and supplier of last resort service.

FMCC Filing:  On February 2, 2007, CL&P filed with the DPUC a semi-annual FMCC reconciliation filing for the period January 1, 2006 through December 31, 2006.  The reconciliation shows a combined net overrecovery of $63 million for bypassable and non-bypassable FMCC charges for 2006.  However, $58.4 million of the overrecovery was used to offset an increase in the generation service charge (GSC) and add to a decrease in non-bypassable FMCC charges that was effective on January 1, 2007.  A schedule to review this filing has not yet been set.

On April 17, 2007, CL&P filed for a decrease in non-bypassable FMCC rates of $31 million due primarily to a reduction in reliability must run (RMR) and ISO charges for 2007.  A decision is expected in May of 2007 for a July 1, 2007 implementation of this decrease.

Procurement Fee Rate Proceedings:  CL&P was allowed to collect a fixed procurement fee of 0.50 mills per KWH from customers who purchase TSO service through the end of 2006.  On December 8, 2005, a draft decision was issued by the DPUC which accepted the methodology proposed by CL&P to calculate the variable portion (incentive portion) of the procurement fee and authorized payment of the $5.8 million for its 2004 incentive fee.  A final decision, which had been scheduled for December 28, 2005, was delayed by the DPUC, and the DPUC re-opened the docket to review additional testimony.  The DPUC has not established a schedule to conclude the case.  

On April 17, 2007, CL&P filed an application with the DPUC for approval of incentive payments for the years 2005 and 2006.  The incentive portion of the procurement fee earned for 2005 is $6 million and for 2006 is $5.5 million.  A schedule for review of this application has not been set.

Management continues to believe that recovery of the $5.8 million asset 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 or 2006 incentive portions of CL&P's procurement fee.  The procurement fee expired at the end of 2006.

Act Concerning Energy Independence:Public Act 05-01, an "Act Concerning Energy Independence," (Act) was signed by Governor Rell on July 22, 2005.  Under the provisions of the Act, the DPUC issued a request for proposal (RFP) in 2006 that solicited customer-

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side distributed resources, grid-side distributed resources, and new generation facilities, including expanded or repowered generation.  The contracts under the RFP can be for terms of up to 15 years and are in the form of contracts for differences that obligate the utilities to pay the difference between a set capacity price and the value that the project receives in the ISO-NE capacity markets.  The utilities would not buy any energy directly from these projects under the contracts.  CL&P is evaluating the projects, the DPUC standard contract, and its ability to earn incentives under the terms of the Act.

On May 3, 2007, the DPUC issued a decision that selected four projects that would be eligible to sign contracts with CL&P and UI.  These projects include three new generating plants that combined would provide 782 MW of additional generating capacity and 5 MW of demand-side measures in Connecticut.  The decision substantially approved the provisions that CL&P sought regarding cost recovery of these arrangements.  Under the decision, CL&P would be required to sign contracts with two of the generators by May 18, 2007, and enter into a cost sharing arrangement with UI for the projects with 80 percent of the costs to CL&P and 20 percent of the costs to UI.  Executed contracts are scheduled to be approved by the DPUC by no later than August 15, 2007.

Connecticut - Yankee Gas:

Yankee Gas Rate Relief:  On December 29, 2006, Yankee Gas filed a request with the DPUC for a rate increase of approximately $67.8 million effective on July 1, 2007.  The request proposes to recover its LNG facility costs and increased cost of providing distribution delivery service.  Yankee Gas expects that the increase will be partially offset by projected commodity and pipeline-related savings, for a net revenue increase of $37.2 million or 8.4 percent above current rates.  Hearings in the rate case have concluded.  Yankee Gas was granted a suspension by the DPUC in the procedural schedule to engage in settlement discussions.  If no settlement agreement is reached, then the procedural schedule would resume.  

New Hampshire:

Delivery Service Rate Case:On February 26, 2007, PSNH filed a settlement agreement it reached with the NHPUC staff and the OCA related to its rate case filing.  The settlement agreement includes, among other things, a transmission cost tracking mechanism, effective on July 1, 2006, to be reset annually, and an allowed ROE of 9.67 percent.  The allowed generation ROE of 9.62 percent was unaffected.  The settlement agreement provides for a $37.7 million estimated annualized increase ($26.5 million for distribution and $11.2 million estimated for transmission) beginning on July 1, 2007, in addition to the $24.5 million temporary increase that was effective on July 1, 2006.  Included in the $37.7 million is approximately $9 million related to additional revenues for the period July 1, 2006 through June 30, 2007 that will be recovered over one year.  An additional delivery revenue increase of approximately $3 million would take effect on January 1, 2008, with a final estimated rate decrease of approximately $9 million scheduled for July 1, 2008.  The settlement agreement enables PSNH to fund a $10 million annual Reliability Enhancement Program and more accurately fund its Major Storm Cost Reserve.  The NHPUC held a hearing on the settlement agreement on March 13, 2007, during which there was no opposition to the settlement agreement.  Hearings on the settlement agreement have concluded and PSNH is awaiting a NHPUC order.  A final decision is expected in the second quarter of 2007.  

The pre-tax earnings impact of the approximately $9 million of additional revenues related to the July 1, 2006 through June 30, 2007 time period is expected to be recognized as follows:  approximately $5 million attributable to 2006 retail transmission expense is expected to be recognized in the second quarter when the NHPUC issues a final decision; $3 million attributable to distribution costs from July 1, 2006 through June 30, 2007 will be recognized over the 12-month period beginning on July 1, 2007 and the remaining $1 million of revenue will be captured as part of the 2007 retail transmission tracker and offset by an equal amount of retail transmission expenses.

Contingent Matters:  The items summarized below contain contingencies that may have an impact on the company's net income, financial position or cash flows.  See Note 6A, "Commitments and Contingencies - Regulatory Developments and Rate Matters" for further information regarding these matters.

·

CTA and SBC Reconciliation: On March 30, 2007, CL&P filed its 2006 Competitive Transition Assessment (CTA) and System Benefits Charge (SBC) reconciliation, which compared CTA and SBC revenues to revenue requirements, with the DPUC.  Management expects a decision in this docket from the DPUC by the end of 2007 and does not expect the outcome to have a material adverse impact on CL&P's net income, financial position or cash flows.

·

Underground Network Reliability:  In 2006, the DPUC opened an investigation into various underground electrical network failures on the CL&P system in 2001 and 2006 in Waterbury, Meriden and Stamford, Connecticut.  On April 25, 2007, the DPUC issued a final decision finding that it was necessary for CL&P to replace the older type cables in those municipalities as was previously proposed by CL&P.  Management is currently evaluating whether an asset retirement obligation has arisen as a result of this decision.  

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·

Purchased Gas Adjustment: In 2005 and 2006, the DPUC issued decisions regarding Yankee Gas Purchased Gas Adjustment (PGA) clause charges and required an audit of $11 million in previously recovered PGA revenues associated with unbilled sales and revenue adjustments for the period of September 1, 2003 through August 31, 2005.  Management believes the unbilled sales and revenue adjustments and resulting charges to customers through the PGA clause for this period were appropriate and that the appropriateness of the PGA charges to customers for the time period under review will be approved by the DPUC.

·

SCRC/ES Reconciliation:  On May 1, 2007, PSNH filed its 2006 stranded cost recovery charge (SCRC)/energy service (ES) reconciliation with the NHPUC.  Management does not expect the outcome of the NHPUC's review of this filing to have a material adverse impact on PSNH's net income, financial position or cash flows.

·

Transition Cost Reconciliations:  WMECO filed its 2005 transition cost reconciliation with the DPU on March 31, 2006 and filed its 2006 transition cost reconciliation with the DPU on March 31, 2007.  Management does not expect the outcome of the DPU's review of these filings to have a material adverse impact on WMECO's net income, financial position or cash flows.

NU Enterprises Divestitures

As of March 31, 2007, NU has exited substantially all of the competitive businesses.  NU Enterprises continues to wind down and pursue divestiture opportunities for its remaining wholesale contracts and energy services businesses.  

Wholesale Marketing Business:During the first quarter of 2007, NU Enterprises continued to manage its remaining obligations in the PJM power pool and under a long-term contract with the New York Municipal Power Association (NYMPA).  In addition to the PJM and NYMPA contracts, Select Energy's only other long-term wholesale obligation is a contract to purchase the output of certain generating units in New England through 2012.  Based on the current value of this contract, when combined with the net wholesale derivative contract portfolio that has been marked-to-market at March 31, 2007 at a value of negative $96.9 million, management believes, under present conditions, that the total cash cost to exit the remaining wholesale marketing business is significantly less than $100 million.

Retail Marketing Business:  On June 1, 2006, Select Energy sold its retail marketing business and paid approximately $24.4 million in 2006 and will pay $14.8 million by the end of 2007 under that sales agreement.  These amounts were included in other current liabilities on the accompanying condensed consolidated balance sheets.  

Competitive Generation Business:  NU completed the sale of NU Enterprises' competitive generation assets in November of 2006.  

Energy Services Businesses:  Most of NU Enterprises' energy services businesses were sold in 2005 and 2006.

In connection with the sale of the retail marketing business, the competitive generation business and certain of the energy services businesses, NU provided various guarantees and indemnifications to the purchasers of these businesses.  See Note 6F, "Commitments and Contingencies - Guarantees and Indemnifications," for information regarding these items.

NU Enterprises Contracts

Wholesale Marketing Contracts:  At March 31, 2007 and December 31, 2006, the fair value of Select Energy's wholesale derivative assets and derivative liabilities, which are subject to mark-to-market accounting, are as follows:

(Millions of Dollars)	March 31, 2007		December 31, 2006
Current wholesale derivative assets	$	60.8	$	43.6
Long-term wholesale derivative assets		16.3		22.3
Current wholesale derivative liabilities		(86.1)		(82.3)
Long-term wholesale derivative liabilities		(87.9)		(110.1)
Portfolio position	$	(96.9)	$	(126.5)

Numerous factors could either positively or negatively affect the realization of the wholesale net fair value amounts in cash.  These factors include the amounts paid or received to exit some or all of these contracts, the volatility of commodity prices until the contracts are exited or expire, the outcome of future transactions, the performance of counterparties, and other factors.

Select Energy has policies and procedures requiring all of its wholesale energy positions to be valued daily and segregating responsibilities between the individuals actually transacting (front office) and those confirming the trades (middle office).  The middle office is responsible for determining the portfolio's fair value independent from the front office.

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The methods Select Energy used to determine the fair value of its wholesale energy contracts are identified and segregated in the table of fair value of contracts at March 31, 2007 and December 31, 2006.  A description of each method is as follows: 1) prices actively quoted primarily represent New York Mercantile Exchange (NYMEX) futures and swaps 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, 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 also has a contract for which a portion of the contract's fair value is determined based on a model.  The model utilizes natural gas prices and a conversion factor to electricity fo r the years 2012 through 2013.  Broker quotes for electricity at locations for which Select Energy has entered into transactions are generally available through the year 2011.  

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.

At March 31, 2007 and December 31, 2006, the sources of the fair value of wholesale contracts are included in the following tables:

	Fair Value of Wholesale Contracts at March 31, 2007
(Millions of Dollars) 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	$	2.2	$	(6.2)	$	(1.0)	$	(5.0)
Prices provided by external sources		(27.5)		(38.3)		(7.3)		(73.1)
Model-based		-		6.2		(25.0)		(18.8)
Totals	$	(25.3)	$	(38.3)	$	(33.3)	$	(96.9)

	Fair Value of Wholesale Contracts at December 31, 2006
(Millions of Dollars) 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	$	(6.9)	$	(11.2)	$	(1.9)	$	(20.0)
Prices provided by external sources		(32.2)		(44.8)		(12.7)		(89.7)
Model-based		0.4		3.5		(20.7)		(16.8)
Totals	$	(38.7)	$	(52.5)	$	(35.3)	$	(126.5)

For the three months ended March 31, 2007, the changes in fair value of these contracts are included in the following table:

	For the Three Months Ended March 31, 2007
(Millions of Dollars)	Total Portfolio Fair Value
Fair value of wholesale contracts outstanding at the beginning of the period	$	(126.5)
Contracts realized or otherwise settled during the period		27.1
Changes in fair value recorded in fuel, purchased and net interchange power		2.5
Fair value of wholesale contracts outstanding at the end of the period	$	(96.9)

Changes in the fair value of wholesale contracts within the New England and PJM portfolio and a generation purchase contract in New York totaling a positive $2.5 million for the three months ended March 31, 2007 are recorded as fuel, purchased and net interchange power on the accompanying condensed consolidated statements of income/(loss).  

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 Select Energy establishing credit limits prior to 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, eith er positively or negatively, in that the counterparties may be similarly affected by changes to economic, regulatory or other conditions.  At March 31, 2007, Select Energy's counterparty credit exposure to wholesale and trading counterparties was approximately 26 percent collateralized or rated BBB- or better and approximately 74 percent was non-rated.  The composition of Select Energy's credit portfolio has shifted from being largely investment grade-rated to being mostly non-rated.  This is largely due to the exit from Select Energy's wholesale New England and retail portfolios.  The bulk of the non-rated credit exposure

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is comprised of one counterparty (96 percent of total) that is a creditworthy, non-rated public entity.  Select Energy was provided $1.4 million and $0.1 million of counterparty deposits at March 31, 2007 and December 31, 2006, respectively.

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 all critical accounting policies and estimates.  All of these critical accounting policies and estimates were reported in the NU 2006 Form 10-K. There have been no material changes with regard to these critical accounting policies and estimates except as follows:

Income Taxes:  Effective on January 1, 2007, NU implemented Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 48, "Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109."  FIN 48 applies to all income tax positions previously filed in a tax return and tax positions expected to be taken in a future tax return that have been reflected on the balance sheets.  FIN 48 addresses the methodology to be used prospectively in recognizing, measuring and classifying the amounts associated with tax positions that are deemed to be uncertain, including related interest and penalties.  As a result of implementing FIN 48, the company recognized a cumulative effect of a change in accounting principle of $32.5 million as a reduction to the January 1, 2007 balance of retained earnings relating to those uncertain tax positions that met the more likely than not recognition threshold.

The determination of whether a tax position meets the recognition threshold under FIN 48 is based on facts, circumstances and information available to the company and requires significant management judgment.  Once a tax position meets the recognition threshold, the tax benefit is measured using a cumulative probability assessment of all possible outcomes.  Assigning probabilities in measuring a recognized tax position, and evaluating new information or events in subsequent periods could change previous conclusions used to measure the tax position estimate and requires significant judgment.  New information or events may include tax examinations or appeals, developments in case law, settlements of tax positions, changes in tax law and regulations, rulings by taxing authorities and statute of limitation expirations.  Such information or events may have a significant impact on the company's net income, financial position and cash flows.  

Other Matters

Contractual Obligations and Commercial Commitments:  For updated information regarding NU's contractual obligations and commercial commitments at March 31, 2007, see Note 6C, "Commitments and Contingencies - Long-Term Contractual Arrangements," to the condensed consolidated financial statements.  

Environmental Matters:  The company is in the process of evaluating additional potential remediation requirements at a river site in Massachusetts containing coal tar deposits.  HWP is partially responsible for this site, and substantial remediation activities at this site have already been conducted.  The company’s reserve with respect to this site is based on its current site assessment and estimate of remediation costs.  The cost to remediate any additional coal tar may be more significant than currently estimated.  The ultimate remediation requirements are the subject of ongoing discussions with the Massachusetts Department of Environmental Protection and may change from time-to-time.  The cost of remediation to HWP will depend, among other things, on the level and extent of the remaining coal tar required to be removed, and the extent of HWP’s responsibility.  HWP's share of the costs related to this site is not recoverable from r atepayers.  At this time, management cannot predict the outcome of this matter or its ultimate effect on NU.  Any increase to the environmental remediation reserve for this site would be recorded in earnings in future periods, may be material, and will be in addition to the approximately $13 million expensed to date of which $11.8 million has been spent and $1.2 million remains in the reserve for this site.  

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.  

In 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).  In March of 2001, NU filed suit against Con Edison seeking damages in excess of $1 billion.  

In a 2005 opinion, 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 in 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.  In April of 2006, NU filed its motion for partial summary judgment on Con Edison's damage claim.  NU's motion asserts that NU is entitled to a judgment in its favor with respect to this claim based on the undisputed material

58

facts and applicable law.  The matter is fully briefed and awaiting a decision.  At this time, NU cannot predict the outcome of this matter or its ultimate effect on NU.

For further information regarding other commitments and contingencies, see Note 6, "Commitments and Contingencies," to the condensed consolidated financial statements.

Accounting Standards Issued But Not Yet Adopted:

A.

Fair Value Measurements:  On September 15, 2006, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 157, "Fair Value Measurements," which establishes a framework for identifying and measuring fair value and is required to be implemented in the first quarter of 2008.  SFAS No. 157 provides a fair value hierarchy, giving the highest priority to quoted prices in active markets, and is expected to be applied to fair value measurements of derivative contracts that are subject to mark-to-market accounting and other assets and liabilities reported at fair value.  In most cases, SFAS No. 157 is required to be implemented prospectively with adjustments to fair value reflected as a cumulative effect adjustment to the opening balance of retained earnings as of January 1, 2008.  The company is evaluating the potential impact of SFAS No. 157 on its condensed consolidated financial statements.

B.

The Fair Value Option:  On February 15, 2007, the FASB issued SFAS No. 159, "The Fair Value Option for Financial Assets and Financial Liabilities - including an amendment of FAS 115."  SFAS No. 159 allows entities to choose, at specified election dates, to measure at fair value eligible financial assets and liabilities that are not otherwise required to be measured at fair value.  If a company elects the fair value option for an eligible item, changes in that item's fair value in subsequent reporting periods must be recognized in earnings.  The company is evaluating the measurement options available under SFAS No. 159, which is effective in the first quarter of 2008.

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 or inactions by local, state and federal regulatory bodies, competition and industry restructuring, changes in economic conditions, changes in weather patterns, changes in laws, regulations or regulatory policy, changes in levels or timing of capital expenditures, developments in legal or public policy doctrines, technological developments, changes in accounting standards and financial reporting regulations, fluctuations in the value of our remaining electricity positions, actions of rating agencies, subsequent recognition, derecognition and measurement of tax positions, and other presently unknown or unforeseen factors. Other risk factors are detailed from time to time in our reports to the SEC, including the factors set forth in our Annual Report on Form 10-K for the year ended December 31, 2006.  Any forward looking statement speaks only as of the date on which such statement is made and the company undertakes no obligation to update the information contained in any forward looking stat ements to reflect developments or circumstances occurring after the statement is made.

Web Site:  Additional financial information is available through NU's web site atwww.nu.com.

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RESULTS OF OPERATIONS - NU CONSOLIDATED

The following table provides the variances in income statement line items for the condensed consolidated statements of income/(loss) for NU included in this report on Form 10-Q for the three months ended March 31, 2007:

	Income Statement Variances (Millions of Dollars) 2007 over/(under) 2006
	Amount		Percent
Operating Revenues:	$	(443)	(21)	%
Operating Expenses:
Fuel, purchased and net interchange power		(474)	(31)
Other operation		(72)	(23)
Restructuring charges		(5)	(96)
Maintenance		8	20
Depreciation		5	8
Amortization		(52)	(89)
Amortization of rate reduction bonds		3	6
Taxes other than income taxes		(4)	(5)
Total operating expenses		(591)	(28)
Operating Income		148	(a)
Interest expense, net		-	-
Other income, net		-	-
Income/(loss) from continuing operations before income tax		148	(a)
Income tax expense/(benefit)		51	(a)
Preferred dividends of subsidiary		-	-
Income/(loss) from continuing operations		97	(a)
Income/(loss) from discontinued operations		(12)	(a)
Net Income/(Loss)	$	85	(a)	%

(a) Percent greater than 100.

Comparison of the First Quarter of 2007 to the First Quarter of 2006

Operating Revenues

Operating revenues decreased $443 million in 2007 primarily due to lower revenues from NU Enterprises ($448 million), partially offset by higher revenues from the regulated companies ($5 million).  

NU Enterprises' revenues decreased $448 million due to the exit from significant components of the competitive businesses during the latter part of 2006.

Revenues from the regulated companies increased $5 million due to higher transmission segment revenues ($23 million), partially offset by lower distribution segment revenues ($18 million).  Transmission segment revenues increased $23 million primarily due to a higher transmission investment base and higher operating expenses which are recovered under FERC-approved transmission tariffs.  Distribution segment revenues decreased $18 million primarily due to lower electric distribution revenues ($19 million), partially offset by higher gas distribution revenues ($1 million).  

Lower 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 ($26 million).  The distribution revenue tracking components decrease of $26 million is primarily due to lower CL&P revenue associated with the recovery of FMCC ($57 million) and a decrease in PSNH’s SCRC revenues mainly as a result of a rate decrease that went into effect July 1, 2006 ($40 million), partially offset by the pass through of higher energy supply costs ($46 million), higher retail transmission revenues ($22 million) and higher WMECO pension tracker revenues ($3 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 the electric distribution segment which flows through to earnings increased $7 million primarily due to an increase in retail sales ($5 million) and an increase in PSNH and WMECO retail rates.  The distribution retail electric sales were

60

positively affected by weather impacts in 2007 as compared with 2006.  Retail KWH electric sales increased by 1.9 percent in 2007 compared with 2006 (a 0.3 percent increase on a weather normalized basis).    

The decrease in electric distribution revenues is partially offset by higher gas distribution revenues of $1 million primarily due to higher sales volumes as a result of a colder winter in 2007.  Firm gas sales increased 10.9 percent in 2007 compared with 2006.  On a weather normalized basis, firm gas sales increased 3.7 percent.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expenses decreased $474 million in 2007 primarily due to lower costs at NU Enterprises ($474 million) due to the exit from significant components of the competitive businesses.  

Other Operation

Other operation expenses decreased $72 million in 2007 primarily due to lower NU Enterprises' expenses ($81 million), partially offset by higher regulated company distribution and transmission segment expenses ($10 million).  

NU Enterprises' expenses decreased $81 million primarily due to the exit from significant components of the competitive business.  

Higher regulated company distribution and transmission segment expenses of $10 million are primarily due to higher general and administrative expenses ($7 million) and higher CL&P conservation and load management expenses ($2 million).  

Restructuring Charges

See Note 2, "Restructuring Charges," to the condensed consolidated financial statements for a description and explanation of these charges.

Maintenance

Maintenance expenses increased $8 million in 2007 primarily due to higher regulated company distribution and transmission segment expenses ($6 million).  

Higher regulated company distribution and transmission segment expenses of $6 million are primarily due to higher boiler maintenance expenses for PSNH as a result of the planned wood boiler outage ($2 million) and higher maintenance of underground lines, overhead lines and station equipment at CL&P and WMECO ($2 million).  

Depreciation

Depreciation increased $5 million in 2007 primarily due to higher distribution and transmission depreciation expense ($5 million) as a result of higher plant balances from the ongoing construction program.  

Amortization

Amortization decreased $52 million in 2007 for the regulated companies' distribution segments primarily due to PSNH distribution ($58 million).  The PSNH decrease is primarily due to completing the recovery of certain identified non-securitized stranded costs in June of 2006 and lower ES overrecoveries.  This PSNH decrease is partially offset by higher amortization for WMECO distribution ($4 million) and CL&P distribution ($3 million).   

Amortization of Rate Reduction Bonds

Amortization of rate reduction bonds increased $3 million in 2007.  The higher portion of principal within the rate reduction bonds payment results in a corresponding increase in the amortization of regulatory assets.  

Taxes Other Than Income Taxes

Taxes other than income taxes decreased $4 million in 2007 primarily due to lower NU Enterprises' other taxes from the competitive businesses not classified as discontinued operations.  

Income Tax Expense/(Benefit)

Income tax expense increased $51 million due primarily to an increase in pre-tax earnings, partially offset by a decrease in the effective tax rate.  The decrease in the effective tax rate was due to an increase in the tax credits and lower flow through regulatory amortizations.  The increase in tax credits results from a full year of production tax credits at the Northern Woods Power Project (NWPP).  In the prior year flow through regulatory amortizations were high as a result of the regulatory recovery of tax expense associated with nondeductible acquisition costs.

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Income from Discontinued Operations

See Note 3, "Assets Held for Sale and Discontinued Operations," to the condensed consolidated financial statements for a description and explanation of the discontinued operations.

62

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 and the NU 2006 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, 2007:

	Income Statement Variances (Millions of Dollars) 2007 over/(under) 2006
	Amount		Percent
Operating Revenues:	$	39	4	%
Operating Expenses:
Fuel, purchased and net interchange power		24	4
Other operation		(11)	(7)
Maintenance		1	5
Depreciation		3	7
Amortization of regulatory (liabilities)/assets, net		2	83
Amortization of rate reduction bonds		2	7
Taxes other than income taxes		-	-
Total operating expenses		21	2
Operating Income		18	30
Interest expense, net		7	25
Other income, net		(3)	(37)
Income before income tax expense		8	19
Income tax expense		7	82
Preferred dividends		-	-
Net Income	$	1	3	%

Comparison of the First Quarter of 2007 to the First Quarter of 2006

Operating Revenues

Operating revenues increased $39 million due to higher transmission business revenues ($20 million) and higher distribution business revenues ($19 million).

Transmission business revenues increased $20 million primarily due to a higher rate base and higher operating expenses which are recovered under FERC-approved transmission tariffs.

The distribution business revenue increase of $19 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 ($18 million).  The distribution business revenue tracking components increased $18 million primarily due to higher TSO related revenues ($70 million), as a result of the pass through of higher energy supply costs, and higher retail transmission revenues ($5 million), partially offset by a decrease in revenues associated with the recovery of FMCC charges ($57 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 revenues which impacts earnings increased $1 million primarily due to higher retail sales.  Retail sales increased 1.6 percent in 2007 compared to the same period in 2006.

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Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expense increased $24 million primarily due to an increase of $120 million resulting from a reduction in supply and reliability cost credit deferrals, partially offset by a decrease in supply costs ($79 million), lower other purchased power costs ($10 million) and lower financial transmission rights costs ($7 million), all of which are included in regulatory commission-approved tracking mechanisms.  The $120 million increase resulting from a reduction in supply and reliability cost credit deferrals was largely the result of more timely collection of supply costs from customers due to a change in customer supply rates from average annual rates to average semi-annual rates.  The $79 million decrease in supply costs was due primarily to a reduction in load caused primarily by customer migration, partially offset by higher first quarter 2007 supply prices.  These supply costs are the contractual amounts the company must pay to various suppliers that have earned the right to supply Standard Service and Last Resort Service load through a competitive solicitation process.

Other Operation

Other operation expenses decreased $11 million primarily due to lower RMR costs ($24 million) which are tracked and recovered through the FMCC, partially offset by higher retail transmission expenses ($5 million), higher administrative expenses ($3 million), higher conservation and load management expenses ($2 million), and higher uncollectible accounts expense ($1 million).

Maintenance

Maintenance expenses increased $1 million primarily due to higher expenses related to underground and overhead lines.

Depreciation

Depreciation expense increased $3 million primarily due to higher utility plant balances.

Amortization of Regulatory Liabilities, Net

Amortization of regulatory liabilities, net increased $2 million primarily due to higher SFAS No. 109 amortization ($3 million) and a higher system benefit charge deferral ($3 million), partially offset by lower amortization related to the recovery of transition charges ($4 million).

Amortization of Rate Reduction Bonds

Amortization of rate reduction bonds increased $2 million.  The higher portion of principal within the rate reduction bonds’ payment results in a corresponding increase in the amortization of regulatory assets.

Interest Expense, Net

Interest expense, net increased $7 million primarily due to higher interest on long-term debt mainly as a result of $250 million of new debt issued in June of 2006 ($4 million), higher carrying costs for unbilled energy adjustment clause revenues per the draft decision docket 06-08-01 issued April 2007 ($2 million), higher FIN 48 interest ($2 million), and higher short-term debt interest ($2 million), partially offset by lower rate reduction bond interest resulting from lower principal balances outstanding ($3 million).

Other Income, Net

Other income, net decreased $3 million primarily due to a lower TSO procurement fee ($3 million).

Income Tax Expense

Income tax expense increased $7 million due primarily to an increase in the effective tax rate and pre-tax earnings.  The increase in the effective tax rate was primarily due to changes in prior year tax reserves resulting from the favorable settlement of a state refund claim and lower current year state tax credits.

LIQUIDITY

Net cash flows from operations decreased by $109.8 million from net cash flows used in operating activities of $34.5 million for the first quarter of 2006 to net cash flows used in operating activities of $144.3 million for the first quarter of 2007.  CL&P’s operating cash flows declined in the first quarter of 2007 primarily as a result of the payment in March of 2007 of $177.2 million in federal and state income taxes.  CL&P’s tax obligation was due to the fact that the sale of the generation assets from CL&P to NGC in 2000 did not trigger federal or state income tax payments by those companies at that time.  It was not until these assets were sold to an unaffiliated third party in November of 2006 that CL&P was required to pay this deferred tax obligation.  

In addition, the timing of payments to suppliers related to purchased power also reduced operating cash flows in 2007 compared to 2006, as a higher level of payments were made in the first quarter of 2007 as compared to 2006.  Offsetting these increased operating cash outflows was a $84 million reduction in regulatory refunds related to amounts refunded to CL&P ratepayers during the first quarter of 2006 as compared to the first quarter of 2007 and lower payments made to the Yankee Companies for decommissioning and closure costs in the first quarter of 2007 as compared to 2006, primarily as a result of the extension of the collection period for CYAPC's decommissioning and closure costs.

64

Capital expenditures described herein are cash capital expenditures and exclude cost of removal, AFUDC related to equity funds and the capitalized portion of pension expense or income.  CL&P's capital expenditures totaled $158.6 million in the first three months of 2007, compared with $124.2 million in the first three months of 2006.  This increase is primarily due to higher transmission capital expenditures.

On March 27, 2007, CL&P closed on the sale of $150 million of 10-year bonds carrying a coupon rate of 5.375 percent and on the sale of $150 million of 30-year bonds carrying a coupon rate of 5.75 percent.

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, 2007, there were no amounts outstanding under that facility.  Financing activities for the three months ended March 31, 2007 included a capital contribution from NU parent in the amount of $215 million.  Financing activities also included the payment of $19.8 million in dividends to NU during the first three months of 2007 compared to $15.9 million during the first three months of 2006.

65

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 2006 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, 2007:

	Income Statement Variances (Millions of Dollars) 2007 over/(under) 2006
	Amount			Percent
Operating Revenues:	$	(38)	(12)		%
Operating Expenses:
Fuel, purchased and net interchange power		-	-
Other operation		10	23
Maintenance		4	29
Depreciation		1	8
Amortization of regulatory assets		(58)	(94)
Amortization of rate reduction bonds		1	6
Taxes other than income taxes		-	-
Total operating expenses		(42)	(14)
Operating Income		4	20
Interest expense, net		-	-
Other income, net		-	-
Income before income tax expense		4	35
Income tax expense		(1)	(29)
Net Income	$	5	94		%

(a) Percent greater than 100.  

Comparison of the First Quarter of 2007 to the First Quarter of 2006

Operating Revenues

Operating revenues decreased $38 million primarily due to lower distribution business revenue.

The distribution business revenue decrease of $38 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 ($43 million).  The distribution revenue tracking components decreased $43 million primarily due to a decrease in the SCRC revenue ($40 million) mainly as a result of a rate decrease effective July 1, 2006.  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 PSNH’s retail rates which impacts earnings increased $5 million, as a result of the rate increases effective July 1, 2006 and higher retail sales.  Retail sales increased 2.7 percent in 2007 compared to the same period of 2006.

66

Other Operation

Other operation expenses increased $10 million primarily due to higher retail transmission expenses ($3 million), higher Energy Assistance Program expenses ($2 million) and higher administrative expenses primarily due to higher employee incentive program costs ($2 million).

Maintenance

Maintenance expenses increased $4 million primarily due to higher boiler maintenance costs as a result of the planned wood boiler outage ($2 million), and higher overhead line and station equipment maintenance expenses.

Depreciation

Depreciation expense increased $1 million primarily due to higher utility plant balances.

Amortization of Regulatory Assets

Amortization of regulatory assets decreased $58 million primarily due to PSNH completing the recovery of certain identified non-securitized stranded costs in June 2006 and lower ES over recoveries in the first quarter of 2007 as compared to the first quarter of 2006.

Amortization of Rate Reduction Bonds

Amortization of rate reduction bonds increased $1 million.  The higher portion of principal within the rate reduction bonds’ payment results in a corresponding increase in the amortization of regulatory assets.

Income Tax Expense

Income tax expense decreased $1 million due to a 23 percent decrease in the effective tax rate, partially offset by higher pre-tax earnings.  The decrease in the effective tax rate was due to an increase in the tax credits, lower state income tax expense, and lower flow through regulatory amortizations.  The increase in tax credits results from a full year of production tax credits at the NWPP.  The state tax expense was high in the prior year due to an increase in unitary taxable income resulting from the sale of generation assets and in the prior year flow through regulatory amortizations were high as a result of the regulatory recovery of tax expense associated with nondeductible acquisition costs.

LIQUIDITY

Net cash flows from operations decreased by $37 million from $97.3 million for the first quarter of 2006 to $60.3 million for the first quarter of 2007.  The decrease in operating cash flows is primarily due to a significant reduction in approved SCRC rates effective on January 1, 2007 to an average rate of $0.0113 per KWH from the average rate of $0.0335 per KWH in the first quarter of 2006.  That decline is the result of the completion of PSNH's recovery of its Part 3 non-securitized stranded costs in the second quarter of 2006.  

Capital expenditures described herein are cash capital expenditures and exclude cost of removal, AFUDC related to equity funds and the capitalized portion of pension expense.  PSNH's capital expenditures totaled $39.8 million in the first three months of 2007 compared to $35.1 million in the first three months of 2006.

Financing activities for the three months ended March 31, 2007 included a capital contribution from NU parent in the amount of $9.5 million as well as the payment of $7.7 million in dividends to NU, compared to $23 million in dividend payments to NU during the first three months of 2006.

67

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 2006 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, 2007:

	Income Statement Variances (Millions of Dollars) 2007 over/(under) 2006
	Amount			Percent
Operating Revenues:	$	-	-		%
Operating Expenses:
Fuel, purchased and net interchange power		(18)	(20)
Other operation		9	57
Maintenance		1	13
Depreciation		1	22
Amortization of regulatory liabilities, net		4	(a)
Amortization of rate reduction bonds		-	-
Taxes other than income taxes		-	-
Total operating expenses		(3)	(2)
Operating Income		3	27
Interest expense, net		-	-
Other income, net		-	-
Income before income tax expense		3	36
Income tax expense		1	41
Net Income	$	2	34		%

(a) Percent greater than 100.  

Comparison of the First Quarter of 2007 to the First Quarter of 2006

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expense decreased $18 million primarily due to lower default service supply costs, which are included in a regulatory commission approved tracking mechanism.  These default service supply costs are the contractual amounts the company must pay to various suppliers that have earned the right to supply default service load through a competitive solicitation process.  The decrease in these costs is primarily the result of decreased load levels and a decrease in the price of electricity paid under these contracts during the first quarter of 2007 as compared to the first quarter of 2006.

Other Operation

Other operation expenses increased $9 million primarily due to an increase in retail transmission expenses ($7 million), as a result of the regulatory tracking mechanism and the increase in retail transmission revenue rates, and higher administrative expenses ($1 million).  

Maintenance

Maintenance expense increased $1 million primarily due to higher tree trimming.  

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Depreciation

Depreciation expense increased $1 million primarily due to revised depreciation rates effective January 1, 2007 per the final rate case and higher utility plant balances.

Amortization of Regulatory Liabilities, Net

Amortization of regulatory liabilities, net increased $4 million primarily due to the deferral of transition costs, as a result of a higher transition cost revenue rate and lower power contract costs.

Income Tax Expense

Income tax expense increased $1 million primarily due to higher pre-tax earnings.

LIQUIDITY

Net cash flows from operations decreased by $19.6 million from net cash flows used in operating activities of $9.9 million for the first three months of 2006 to net cash flows used in operating activities of $29.5 million for the first three months of 2007.  WMECO’s operating cash flows declined in the first quarter of 2007 primarily as a result of the payment of $47.9 million in federal and state income taxes.  WMECO’s tax obligation was due to the fact that the sale of the generation assets from WMECO to NGC in 2000 did not trigger federal or state income tax payments by those companies at that time.  It was not until these assets were sold to an unaffiliated third party in November of 2006 that WMECO was required to pay this deferred tax obligation.  These tax payments have been partially offset with recoveries from ratepayers due to retail rate adjustments that were effective in January of 2007.

Capital expenditures described herein are cash capital expenditures and exclude cost of removal, AFUDC related to equity funds and the capitalized portion of pension expense or income.  WMECO's capital expenditures totaled $10.8 million in the first three months of 2007, compared with $10.4 million in the first three months of 2006.

Financing activities for the three months ended March 31, 2007 included a capital contribution from NU parent in the amount of $4.8 million as well as the payment of $3.2 million in dividends to NU during the first three months of 2007, compared to $14.5 million and $2 million, respectively, during the first three months of 2006.

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ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risk Information

The merchant energy business utilizes the sensitivity analysis methodology to disclose quantitative information for its commodity price risks (including where applicable capacity and ancillary components).  Sensitivity analysis provides a presentation of the potential loss of future earnings, fair values or cash flows from market risk-sensitive instruments over a selected time period due to one or more hypothetical changes in commodity price components, or other similar price changes.  Under sensitivity analysis, the fair value of the portfolio is a function of the underlying commodity components, contract prices and market prices represented by each derivative contract. For swaps, forward contracts and options, fair value reflects management's best estimates considering over-the-counter quotations, time value and volatility factors of the underlying commitments.  Exchange-traded futures and options are recorded at fair value based on closing exchange prices.  As the NU Enterprises' businesses are exited, the risks associated with commodity prices are expected to be reduced.  

NU Enterprises - Wholesale Portfolio:  When conducting sensitivity analyses of the change in the fair value of Select Energy's wholesale portfolio, which includes a non-derivative power purchase contract, 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, 2007, Select Energy has calculated the market price resulting from a 10 percent change in forward market prices of those contracts.  A 10 percent increase in prices for all products would have resulted in a pre-tax decrease in fair value of $2.9 million and a 10 percent decrease in prices for all products would have resulted in a pre-tax increase in fair value of $1.7 million.  A 10 percent increase in energy prices would have resulted in a $12.5 million pre-tax decrease, and a 10 percent decrease in energy prices would have resulted in an $11.3 million pre-tax increase.  A 10 percent increase/(decrease) in capacity prices would have resulted in a $2.4 million pre-tax increase/(decrease).  A 10 percent increase/(decrease) in ancillary prices would have resulted in a $7.2 million pre-tax increase/(decrease).  

The impact of a change in electricity and natural gas prices on Select Energy's wholesale transactions at March 31, 2007 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.

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 long-term debt.  At March 31, 2007, approximately 90 percent (82 percent including the long-term debt subject to the fixed-to-floating interest rate swap as variable long-term 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 long-term debt subject to the fixed-to-floating interest rate swap, annual interest expense would have increased by $3.2 million.  At March 31, 2007, NU parent maintained a fixed-to-floating interest rate swap to manage the interest rate risk associated with its $263 million of fixed-rate long-term 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.  The Risk Oversight Council is generally comprised of individuals from outside of the business lines that create or actively manage these risk exposures and functions 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.

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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 coun terparties may be similarly affected by changes to economic, regulatory or other conditions.

At March 31, 2007 and December 31, 2006, Select Energy maintained collateral balances from counterparties of $1.4 million and $0.1 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 $29.9 million and $48.5 million at March 31, 2007 and December 31, 2006, respectively, which are included in special deposits on the accompanying condensed consolidated balance sheets.

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

NU has implemented an Enterprise Risk Management (ERM) methodology for identifying the principal risks of the company.  ERM involves the application of a well-defined, enterprise-wide methodology that 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.  However, there can be no assurances that the ERM process will identify every risk or event that could impact the company's financial condition or results of operations.  The findings of this process are periodically discussed with NU's Finance Committee of the Board of Trustees.

Additional quantitative and qualitative disclosures about market risk are set forth in Part II, Item 7, "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, 2007 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 have concluded, based on their review, that NU’s disclosure controls and procedures are 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 time periods 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 changes in internal controls over financial reporting for NU during the quarter ended March 31, 2007 that have materially affected, or are reasonably likely to materially affect internal controls over financial reporting.  

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PART II.  OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

The company is a party to various legal proceedings.  The company has identified these legal proceedings in Part I, Item 3, "Legal Proceedings" in our Annual Report on Form 10-K for the year ended December 31, 2006.  There have been no material changes with regard to the legal proceedings previously disclosed in our most recent 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."  The company has identified a number of these risk factors in our Annual Report on Form 10-K for the year ended December 31, 2006.  NU's susceptibility to certain risks, including those discussed in detail in our Annual Report on Form 10-K, could exacerbate other risks. These risk factors should be considered carefully in evaluating NU's risk profile.  There have been no material changes with regard to the risk factors previously disclosed in our most recent Form 10-K.

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, 2007.

ITEM 6.

EXHIBITS

Document designated with a (*) are filed herewith.  

(a)

Listing of Exhibits (NU)

Exhibit No.

Description

*15

Deloitte & Touche LLP Letter Regarding Unaudited Financial Information

*31

Certification of Charles W. Shivery, Chairman, President and Chief Executive Officer of Northeast Utilities, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated May 9, 2007

*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 9, 2007

*32

Certification of Charles W. Shivery, Chairman, President and Chief Executive Officer of Northeast Utilities and David R. McHale, Senior Vice President and Chief Financial Officer of Northeast Utilities, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated May 9, 2007

Listing of Exhibits (CL&P)

4.2.3

Supplemental Indenture (2007 Series A Bonds and 2007 Series B Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee (Exhibit 99.2 to CL&P Form 8-K filed March 29, 2007, File No. 0-00404)

*31

Certification of Leon J. Olivier, 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 9, 2007

*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 9, 2007

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*32

Certification of Leon J. Olivier, 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 9, 2007

Listing of Exhibits (PSNH)

*31

Certification of Leon J. Olivier, 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 9, 2007

*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 9, 2007

*32

Certification of Leon J. Olivier, 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 9, 2007

Listing of Exhibits (WMECO)

*31

Certification of Leon J. Olivier, 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 9, 2007

*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 9, 2007

*32

Certification of Leon J. Olivier, 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 9, 2007

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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 9, 2007	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 9, 2007	By	/s/ David R. McHale
		David R. McHale
		Senior Vice President and Chief Financial Officer
		(for the Registrant and as Principal Financial Officer)

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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 9, 2007	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 9, 2007	By	/s/ David R. McHale
		David R. McHale
		Senior Vice President and Chief Financial Officer
		(for the Registrant and as Principal Financial Officer)

75