Form 8-K

EX-99.1 3 exhibit991draft3edgar.htm 2005 ANNUAL REPORT Form 8-K

Exhibit 99.1

EXPLANATORY NOTE

In 2005 and 2006, Northeast Utilities (NU) reported discontinued operations in quarterly reports on Form 10-Q as a result of meeting the accounting criteria requiring this presentation. NU presented in quarterly reports on Form 10-Q the operating results of the following as discontinued operations:

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

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

Woods Network Services, Inc.;

Woods Electrical Co., Inc.;

Northeast Generation Company (NGC); and

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

As a result of the presentation of NGC and Mt. Tom as discontinued operations in the first quarter of 2006 and the requirement to present discontinued operations in prior period financial statements, NU is filing Exhibit 99.1 to this report on Form 8-K to conform certain financial information presented in its 2005 annual report on Form 10-K to the presentation of the discontinued operations in its first quarter 2006 report on Form 10-Q. Accordingly, Exhibit 99.1 contains the complete text of Part II, Items 6, 7 and 8, as amended. Unaffected items in the 2005 annual report on Form 10-K have not been repeated in this exhibit.

PART II

Item 6.

Selected Consolidated Financial Data (Unaudited)


(Thousands of Dollars, except percentages and share information)		2005			2004			2003			2002			2001
Balance Sheet Data:
Property, Plant and Equipment, Net	$	6,417,230		$	5,864,161		$	5,429,916		$	5,049,369		$	4,472,977
Total Assets (a)		12,569,075			11,638,396			11,216,487			10,764,880			10,331,923
Total Capitalization (b)		5,595,405			5,293,644			4,926,587			4,670,71			4,576,858
Obligations Under Capital Leases (b)		13,987			14,806			15,938			16,803			17,539
Income Data:
Operating Revenues (c)	$	7,397,743		$	6,542,038		$	5,943,358		$	5,159,552		$	5,709,916
(Loss)/Income from Continuing Operations (c)		(266,576)			69,776			77,266			116,645			221,754
Income from Discontinued Operations (c)		14,093			46,812			43,886			35,464			44,188
(Loss)/Income Before Cumulative Effects of Accounting Changes, Net of Tax Benefits		(252,483)			116,588			121,152			152,109			265,942
Cumulative Effects of Accounting Changes, Net of Tax Benefits		(1,005)			-			(4,741)			-			(22,432)
Net (Loss)/Income	$	(253,488)		$	116,588		$	116,411		$	152,109		$	243,510
Common Share Data:
Basic and Fully Diluted (Loss)/Earnings per Common Share:
(Loss)/Income from Continuing Operations (c)	$	(2.03)		$	0.54		$	0.61		$	0.90		$	1.63
Income from Discontinued Operations (c)		0.11			0.37			0.34			0.28			0.34
Cumulative Effects of Accounting Changes, Net of Tax Benefits		(0.01)			-			(0.04)			-			(0.17)
Net (Loss)/Income	$	(1.93)		$	0.91		$	0.91		$	1.18		$	1.80
Basic Common Shares Outstanding (Average)		131,638,953			128,245,860			127,114,743			129,150,549			135,632,126
Fully Diluted Common Shares Outstanding (Average)		131,638,953			128,396,076			127,240,724			129,341,360			135,917,423
Dividends Per Share	$	0.68		$	0.63		$	0.58		$	0.53		$	0.45
Market Price – Closing (high) (d)	$	21.79		$	20.10		$	20.17		$	20.57		$	23.75
Market Price – Closing (low) (d)	$	17.61		$	17.30		$	13.38		$	13.20		$	16.80
Market Price – Closing (end of year) (d)	$	19.69		$	18.85		$	20.17		$	15.17		$	17.63
Book Value Per Share (end of year)	$	15.85		$	17.80		$	17.73		$	17.33		$	16.27
Tangible Book Value Per Share (end of year)	$	13.98		$	15.17		$	15.05		$	14.62		$	13.71
Rate of Return Earned on Average Common Equity (%)		(10.7)			5.1			5.2			7.0			11.2
Market-to-Book Ratio (end of year)		1.2			1.1			1.1			0.9			1.1
Capitalization:
Common Shareholders' Equity		43	%		44	%		46	%		47	%		46	%
Preferred Stock (b) (e)		2			2			2			3			3
Long-Term Debt (b)		55			54			52			50			51
		100	%		100	%		100	%		100	%		100	%

(a)

Total assets were not adjusted for cost of removal prior to 2002.

(b)

Includes portions due within one year.

(c)

Adjusted from the original 2005 Form 10-K filing to reflect NGC and Mt. Tom as discontinued operations. See Note 4 for a complete list of discontinued operations companies.

(d)

Market price information reflects closing prices as reflected by the New York Stock Exchange.

(e)

Excludes $100 million of Monthly Income Preferred Securities.

Item 7.

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

Financial Condition and Business Analysis

Executive Summary

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

Strategy, Results and Outlook:

In 2005, Northeast Utilities (NU or the company) recorded losses of $253.5 million, or $1.93 per share. Those results included net income after payment of preferred dividends of $163.4 million, or $1.24 per share, at the regulated Utility Group businesses and losses of $398.2 million, or $3.03 per share, at the competitive NU Enterprises businesses.

On March 9, 2005, NU announced that NU Enterprises would exit its wholesale marketing business and its energy services businesses. On November 7, 2005, NU announced its decision to exit the remainder of NU Enterprises’ competitive businesses, which includes the retail marketing and competitive generation businesses. NU expects that exiting the NU Enterprises businesses will benefit shareholders by producing a company with a simpler, lower risk business model, and with more predictable financial results and cash flows. NU expects to use the net proceeds from exiting the NU Enterprises businesses to reduce debt and make equity investments in the Utility Group businesses.

The NU Enterprises 2005 losses of $398.2 million included a net negative after-tax mark-to-market charge of $278.9 million on wholesale energy contracts and after-tax restructuring and impairment charges of $43.7 million. $26.2 million of these charges is included in discontinued operations.

Included in these negative mark-to-market charges, in 2005 NU Enterprises paid or agreed to pay approximately $242 million to exit all of its New England wholesale energy contracts. Of the approximately $242 million, in 2005 approximately $186 million was paid. Also in 2005, NU Enterprises sold two of its energy services businesses for a total of $6.5 million and part of another energy services business in January of 2006 for approximately $2 million.

Utility Group 2005 earnings increased by $7.8 million or 5 percent as a result of higher transmission business earnings due to a higher level of investment, retail distribution rate increases at all four regulated companies and a 2.6 percent increase in regulated retail electric sales in 2005. These results were offset by after-tax employee termination and benefit plan curtailment charges totaling $12.3 million, higher pension, depreciation, and interest expense.

NU expects the Utility Group to invest up to $4.3 billion in its electric transmission and distribution and natural gas distribution businesses from 2006 through 2010. NU estimates that when it successfully meets this goal, it will achieve significant compounded annual regulated rate base growth through 2010. After accounting for the dilutive impact of projected issuances of additional common shares beyond 2007 and parent company expenses, the company expects such rate base growth, assuming appropriate regulatory actions, to result in regulated earnings per share growth of between 8 percent and 10 percent annually beginning with 2007.

NU projects that 2006 combined earnings for the Utility Group and parent company will be between $1.09 per share and $1.22 per share. NU is not providing consolidated earnings guidance or guidance for NU Enterprises due to the uncertainty of any potential financial impacts of exiting its competitive businesses.

Legislative and Legal Items:

On July 6, 2005, Connecticut adopted legislation creating a mechanism to true-up annually the retail transmission charge in local electric distribution company rates. In accordance with this legislation, effective January 1, 2006, The Connecticut Light and Power Company (CL&P) raised its retail transmission rate to collect $21 million of additional revenues over the first six months of 2006.

On July 22, 2005, Connecticut also adopted legislation that provides local electric distribution companies, including CL&P, with financial Incentives to promote construction of distributed generation. The Connecticut Department of Public Utility Control (DPUC) is conducting a number of new dockets to implement this legislation.

On August 8, 2005, President Bush signed into law comprehensive federal energy legislation with several provisions affecting NU. As part of this legislation, the Public Utility Holding Company Act of 1935 (PUHCA) was repealed. Some but not all of the Securities and Exchange Commission’s (SEC) responsibilities under PUHCA were transferred to the Federal Energy Regulatory Commission (FERC).

In an opinion dated October 12, 2005, a panel of three judges at the United States Court of Appeals for the Second Circuit (Court of Appeals) held that the shareholders of NU had no right to sue Consolidated Edison, Inc. (Con Edison) for its alleged breach of the parties’ Merger Agreement. NU’s request for rehearing was denied on January 3, 2006. This ruling left intact the remaining claims between NU and Con Edison for breach of contract, which include NU’s claim for recovery of costs and expenses of approximately $32 million and Con Edison’s claim for damages of "at least $314 million." NU is currently considering whether to seek review by the United States Supreme Court. At this stage, NU cannot predict the outcome of this matter or its ultimate effect on NU.

In November of 2005, Public Service Company of New Hampshire (PSNH) and various legislative, state government and environmental leaders announced that they had reached a consensus to propose legislation to reduce the level of mercury emissions from PSNH’s coal-

fired plants by 2013 with incentives for early reductions. As part of the proposed legislation, PSNH’s primary long-term alternative to comply with the proposed legislation would be to install wet scrubber technology at its two Merrimack coal units, which combined generate 433 megawatts (MW), at a cost of approximately $250 million. The proposed legislation is being considered during the 2006 legislative session.

The Regional Greenhouse Gas Initiative (RGGI) agreement, signed on December 20, 2005, is a cooperative effort by the states of Connecticut, Delaware, Maine, New Jersey, New Hampshire, New York, and Vermont, to develop a regional program for stabilizing current levels and ultimately reducing carbon dioxide (CO2) emissions by ten percent by 2020 from fossil-fired electric generators. RGGI may impact PSNH’s Merrimack, Newington and Schiller stations. At this time, the impact of this agreement on NU cannot be determined.

Regulatory Items:

Each of NU’s Utility Group regulated electric companies, CL&P, PSNH and Western Massachusetts Electric Company (WMECO), has received regulatory approvals to recover the increased cost of energy being supplied to their customers in 2006. These increased costs are primarily the result of new solicitations from the market.

PSNH’s 2004 stranded cost recovery charge (SCRC) reconciliation filing was filed with the New Hampshire Public Utilities Commission (NHPUC) on May 2, 2005. In October of 2005, PSNH, the NHPUC staff and the New Hampshire Office of Consumer Advocate (OCA) reached a settlement agreement in this case. This settlement agreement was approved by the NHPUC on December 22, 2005. That settlement agreement also recommended that the NHPUC staff engage a coal procurement expert to analyze PSNH’s coal procurement and transportation operations. Consistent with the settlement agreement, the NHPUC deferred action on coal-related costs until that analysis has been completed.

On September 9, 2005 the DPUC issued a draft decision regarding Yankee Gas Services Company (Yankee Gas) Purchased Gas Adjustment (PGA) clause charges for the period of September 1, 2003 through August 31, 2004. The draft decision disallowed approximately $9 million in previously recovered PGA revenues associated with two separate Yankee Gas unbilled sales and revenue adjustments. At the request of Yankee Gas, the DPUC reopened the PGA hearings on September 20, 2005 and requested that Yankee Gas file supplemental information regarding the two adjustments. Yankee Gas complied with this request. The remaining schedule for the proceeding has not yet been established.

On December 1, 2005, NU filed at the FERC a request to include 50 percent of construction work in progress (CWIP) for its four major southwest Connecticut transmission projects in its formula rate for transmission service. The FERC approved the filing with the new rates, including the CWIP, effective on February 1, 2006. The new rates allow NU to collect 50 percent of the construction financing expenses while these projects are under construction.

On December 1, 2005, WMECO made its 2006 annual rate change filing implementing the $3 million distribution revenue increase allowed under its rate case settlement agreement. WMECO requested that this change become effective on January 1, 2006. On December 29, 2005, the Massachusetts Department of Telecommunications and Energy (DTE) approved rates reflecting the $3 million distribution revenue increase as well as increases for new basic service supply.

On December 2, 2005, the NHPUC issued an order to rehear the order that lowered the return on equity (ROE) on PSNH’s generating facilities to 9.62 percent from 11 percent effective August 1, 2005. On January 3, 2006, PSNH appealed the revised decision to the New Hampshire Supreme Court and simultaneously asked the NHPUC for reconsideration of its decision. The appeal before the New Hampshire Supreme Court is pending. On February 10, 2006, PSNH’s most recent request for reconsideration by the NHPUC was denied.

On December 23, 2005, the DPUC denied Yankee Gas’ request for interim rate relief of $12.4 million on the grounds that the prerequisite circumstances of the settlement agreement had not been met. Management expects to file a rate case in late 2006 that would be effective the earlier of July 1, 2007 or the date the Waterbury liquefied natural gas (LNG) facility enters service. Management expects Yankee Gas to earn below its allowed ROE until the next rate case goes into effect. Management has also begun to take steps to reduce Yankee Gas’ nonfuel operation and maintenance costs by combining certain operations of Yankee Gas and CL&P.

A final decision in the 2004 Competitive Transition Assessment (CTA) and System Benefits Charge (SBC) docket was issued on December 19, 2005 by the DPUC. In a subsequent decision in CL&P’s docket to establish the 2006 transitional standard offer (TSO) rates dated December 28, 2005, the DPUC ordered CL&P to issue a revised CTA refund of $108 million over the twelve-month period beginning with January 2006 consumption and an additional CTA refund of $40 million for the months of January, February and March of 2006.

On March 6, 2006, the New England Independent System Operator (ISO-NE) and a broad cross-section of critical stakeholders from around the region, including CL&P, PSNH and Select Energy, filed a comprehensive settlement agreement at the FERC implementing a Forward Capacity Market in place of Locational Installed Capacity (LICAP). The settlement agreement must be approved by the FERC, and the parties have asked for a decision by June 30, 2006.

Liquidity:

Exiting the competitive generation and retail marketing businesses is expected to benefit NU’s liquidity and reduce debt. The net proceeds from NU Enterprises’ competitive generation asset sales are expected to be an important factor in NU’s financing plans.

On October 28, 2005, the SEC approved NU’s application to increase its authorized borrowing limit from $450 million to $700 million. On December 9, 2005, NU parent also increased its revolving credit arrangement from $500 million to $700 million and extended its termination date by one year to November 6, 2010. A separate $400 million Utility Group company revolving credit facility was also extended by one year to November 6, 2010.

On November 2, 2005, NU arranged a separate $600 million unsecured credit facility that supplements other sources of liquidity. That facility was reduced to $310 million in December of 2005 after the issuance of $425 million of NU common shares and the increase in the NU parent and Utility Group revolving credit arrangements was completed.

On December 12, 2005, NU received net proceeds of approximately $425 million from the sale of 23 million NU common shares. These proceeds were used to reduce short-term debt and will be used in the future to continue to contribute common equity to the Utility Group companies.

In 2005, NU Enterprises paid approximately $186 million to exit all of its New England wholesale sales arrangements through cash on hand and cash provided by borrowings under the NU parent $500 million revolving credit arrangement.

In 2005, the Utility Group companies issued $350 million of first mortgage bonds and senior notes with maturities ranging from 10 years to 30 years, the proceeds from which were used to repay short-term borrowings used to finance capital expenditures.

In 2005, NU’s capital expenditures totaled $775.4 million compared with $671.5 million in 2004. The increased level of capital expenditures was caused primarily by a need to continue to improve the capacity and reliability of NU’s regulated transmission system.

Cash flows from operations decreased by $19.4 million to $441.2 million in 2005 from $460.6 million in 2004.

Overview

Consolidated: NU lost $253.5 million, or $1.93 per share, in 2005, compared with earnings of $116.6 million, or $0.91 per share, in 2004, and $116.4 million, or $0.91 per share, in 2003. Earnings per share in 2004 and 2003 are reported on a fully diluted basis and the weighted average common shares outstanding at December 31, 2005 include the impact of the issuance of 23 million NU common shares on December 12, 2005 which were outstanding for 20 days in 2005. The 2005 loss reflects losses of $398.2 million, or $3.03 per share, at NU Enterprises, the holding company for NU’s competitive businesses, and earnings of $163.4 million, or $1.24 per share, at NU’s regulated Utility Group companies. In 2005, NU also had $18.7 million, or $0.14 per share, of parent company and other expense, compared with $23.9 million, or $0.18 per share, in 2004 and $12.7 million, or $0.10 per share, in 2003. NU’s 2005 losses also include after-tax employee termination and benefit plan curtailment charges totaling $15 million.

The losses at NU Enterprises reflect decisions announced in 2005 to exit all of its competitive business lines. As a result of those decisions, NU Enterprises recorded $296.4 million of after-tax restructuring and impairment and mark-to-market charges, primarily on wholesale electric marketing sales contracts. In 2005, NU Enterprises exited all of its wholesale sales obligations in New England. NU Enterprises still has below-market wholesale obligations in the New York power pool through 2013 and Pennsylvania-New Jersey-Maryland (PJM) power pool through 2008, all of which were marked-to-market in 2005. Those positions will continue to create volatility in NU’s quarterly earnings until the contracts expire or are exited.

NU’s 2004 results included an after-tax loss of $48.3 million associated with mark-to-market accounting for certain natural gas positions established to mitigate the risk of electricity purchased in anticipation of winning certain levels of wholesale electric load in New England. NU’s 2004 results also included after-tax investment write-downs of approximately $8.8 million, which is included in the $23.9 million.

NU's consolidated statements of (loss)/income for the years ended December 31, 2005, 2004 and 2003 present the operations for the following as discontinued operations as a result of meeting the criteria requiring this presentation:

Northeast Generation Company (NGC);

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

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

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

Woods Network Services, Inc. (Woods Network); and

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

Management concluded that NGC and Mt. Tom should be presented as discontinued operations beginning in the first quarter of 2006, when a plan to market these businesses was implemented and the criteria for this presentation were met. For further information, see Note 4, "Assets Held for Sale and Discontinued Operations," and Note 18, "Subsequent Events," to the consolidated financial statements.

A summary of NU’s (losses)/earnings by major business line for 2005, 2004 and 2003 is as follows:


	For the Years Ended December 31,
(Millions of Dollars)	2005	2004	2003
Utility Group	$ 163.4	$155.6	$132.5
NU Enterprises (1)	(398.2)	(15.1)	(3.4)
Parent and Other	(18.7)	(23.9)	(12.7)
Net (Loss)/Income	$(253.5)	$116.6	$116.4

(1)

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

In 2005, NU announced decisions to exit all of its competitive businesses. NU expects that exiting the NU Enterprises businesses will benefit shareholders by producing a company with a simpler, lower risk business model, and with more predictable financial results and cash flows. In 2005, those businesses accounted for approximately $2 billion of NU’s revenues of $7.4 billion. At December 31, 2005, these businesses also accounted for $2.4 billion of NU’s total assets. NU Enterprises is comprised of two business segments: the merchant energy business segment, which includes the wholesale marketing, retail marketing and competitive generation businesses, and the energy services business segment. In 2005, in addition to exiting all of its New England wholesale sales obligations, NU Enterprises sold two of its six energy services businesses for approximately $6.5 million and part of another energy services business in January of 2006 for approximately $2 million. NU Enterprises expects to complete the sale of all its remaining competitive businesses in 2006. The net proceeds from these sales will be used to reduce debt and make equity investments in the Utility Group companies.

For the Utility Group, NU segments its earnings between its transmission and distribution businesses with regulated generation included in the distribution business. The electric transmission business earned $42.5 million, or $0.32 per share, in 2005, compared with earnings of $29.5 million, or $0.23 per share, in 2004, and $28.2 million, or $0.22 per share, in 2003. The higher level of earnings was due primarily to a return on a higher level of transmission investment at CL&P. In 2005, the electric distribution and regulated generation companies earned $103.6 million, or $0.79 per share, compared with earnings of $112 million, or $0.87 per share, in 2004 and $97 million, or $0.76 per share, in 2003. Distribution company results in 2005 were primarily affected by rate increases implemented at CL&P, PSNH and WMECO in 2005. Those increases were more than offset by higher operation, interest and depreciation costs at CL&P and PSNH. Yankee Gas earned $17.3 million, or $0.13 per share, in 2005, compared with earnings of $14.1 million, or $0.11 per share, in 2004, and $7.3 million, or $0.06 per share, in 2003. Improved 2005 Yankee Gas results were primarily due to a $14 million base rate increase implemented on January 1, 2005.

NU’s consolidated revenues increased to $7.4 billion in 2005 from $6.5 billion in 2004 and $5.9 billion in 2003. Utility Group revenues totaled $5.5 billion in 2005, compared with $4.6 billion in 2004, and $4.3 billion in 2003. Higher regulated revenues are primarily caused by higher fuel and energy costs which are passed through to customers. NU Enterprises revenues totaled $2 billion before eliminations in 2005, compared with $2.7 billion in 2004 and $2.4 billion in 2003. The lower 2005 NU Enterprises revenues reflect lower wholesale electric sales.

NU’s revenues during 2004 increased due to increased revenues from NU Enterprises primarily as a result of higher merchant energy retail sales volumes and higher prices. The remainder of the increase in 2004 revenues related to higher Utility Group transmission and distribution revenues as a result of higher rates and higher revenues to recover federally mandated congestion charges (FMCC).

Utility Group: The Utility Group is comprised of CL&P, PSNH, WMECO, and Yankee Gas, and is comprised of their transmission, distribution and generation businesses. The Utility Group earned $163.4 million in 2005, or $1.24 per share, compared with $155.6 million, or $1.21 per share, in 2004 and $132.5 million, or $1.04 per share, in 2003. A summary of Utility Group earnings by company and business segment for 2005, 2004 and 2003 is as follows:


	For the Years Ended December 31,
(Millions of Dollars)	2005	2004	2003
CL&P Distribution	$ 58.6	$ 62.7	$ 46.3
CL&P Transmission	30.7	19.8	17.1
Total CL&P*	89.3	82.5	63.4
PSNH Distribution and Generation	33.9	39.9	38.3
PSNH Transmission	7.8	6.7	7.3
Total PSNH	41.7	46.6	45.6
WMECO Distribution	11.1	9.4	12.4
WMECO Transmission	4.0	3.0	3.8
Total WMECO	15.1	12.4	16.2
Yankee Gas	17.3	14.1	7.3
Total Utility Group Net Income	$163.4	$155.6	$132.5

*After preferred dividends of $5.6 million in all years.

CL&P earned $89.3 million in 2005, compared with $82.5 million in 2004 and $63.4 million in 2003. CL&P’s transmission results benefited from higher revenues due to earning on a higher level of investment. The 2005 decline in CL&P’s distribution earnings to $58.6 million in 2005 from $62.7 million in 2004 resulted from after-tax employee termination and benefit plan curtailment charges totaling $8.5 million, the positive $6.9 million after-tax impact of a regulatory decision in 2004 concerning a 2003 rate case, a negative $2.5 million after-tax impact of a regulatory decision in 2005 concerning streetlighting refunds, and higher operation, interest and depreciation expenses, partially offset by a $25 million distribution rate increase that took effect January 1, 2005 and a 3 percent increase in retail electric sales. The increase in CL&P’s transmission earnings resulted primarily from increased investment in its transmission system.

PSNH earned $41.7 million in 2005, compared with $46.6 million in 2004 and $45.6 million in 2003. PSNH’s distribution and generation earnings in 2005 were lower primarily due to a lower ROE on the generation facilities in 2005 and higher interest and operating expenses, partially offset by delivery rate increases of $3.5 million in October of 2004 and $10 million in June of 2005.

WMECO earned $15.1 million in 2005, compared with $12.4 million in 2004 and $16.2 million in 2003. Improved 2005 distribution results were due to a $6 million distribution rate increase that took effect on January 1, 2005, a 1.4 percent increase in retail electric sales and higher rate base earnings as a result of WMECO refinancing its prior spent nuclear fuel obligation, partially offset by higher operating and interest costs.

Yankee Gas earned $17.3 million in 2005, compared with $14.1 million in 2004 and $7.3 million in 2003. Yankee Gas results benefited from a $14 million base rate increase and a reduction in depreciation expense, both of which resulted from a 2004 rate settlement and were effective January 1, 2005.

The Utility Group’s retail electric sales were positively impacted by weather in 2005, particularly by an unseasonably hotter than average third quarter of 2005, which increased electricity consumption. Overall, retail kilowatt-hour electric sales increased 2.6 percent in 2005, but decreased by 0.1 percent on a weather adjusted basis. Residential sales increased 4.4 percent, or 0.7 percent on a weather adjusted basis while commercial sales increased 3.6 percent, or 1.4 percent on a weather adjusted basis, and industrial sales decreased 4 percent, or 5.5 percent on a weather adjusted basis as a result of the increase in energy costs, business closings and the installation of cogeneration equipment.

For the Utility Group, a summary of changes in retail electric sales for 2005 as compared to 2004 is as follows:


	Percentage Increase/(Decrease)	Weather Adjusted Percentage Increase/(Decrease)
CL&P	3.0%	0.1%
PSNH	1.9%	(0.2)%
WMECO	1.4%	(0.8)%

As noted above, when adjusted for the weather, retail kilowatt-hour electric sales were virtually unchanged from 2004 to 2005. With commodity-driven rate increases taking effect early in 2006 and the weather being much milder to date in 2006, management is concerned that actual sales could be lower in 2006 than in 2005. While sales volume does not affect transmission business earnings positively or negatively, lower electric and natural gas sales do negatively affect distribution company earnings.

NU Enterprises: During 2005, NU Enterprises was the parent of Select Energy, Inc. (Select Energy), SESI and its subsidiaries, NGC, Northeast Generation Services Company (NGS) and its subsidiaries, E.S. Boulos Company (Boulos) and Woods Electrical, Woods Network and SECI, all of which are collectively referred to as "NU Enterprises." The generation operations of HWP (Mt. Tom), which is a direct subsidiary of NU, are also included in the results of NU Enterprises. The companies included in the NU Enterprises segment are grouped into two business segments: the merchant energy business segment and the energy services business segment. The merchant energy business segment is currently comprised of Select Energy’s wholesale marketing business, the competitive generation businesses which includes 1,296 MW of pumped storage and hydroelectric generation assets owned by NGC and 146 MW of coal-fired generation assets owned by HWP (Mt. Tom), Select Energy’s retail marketing business, and NGS. The energy services businesses consist of SESI, Boulos, Woods Electrical, Woods Network, and SECI. NGC, Mt. Tom, SESI, SECI-NH, a division of SECI, Woods Electrical, and Woods Network are classified as discontinued operations.

In March of 2005, NU announced the exit from NU Enterprises’ wholesale marketing business and the energy services businesses, and in November of 2005, announced the exit from NU Enterprises’ retail marketing and competitive generation businesses. In the fourth quarter of 2005, Woods Network and SECI-NH (including Reeds Ferry) were sold for a total of approximately $6.5 million. In January of 2006, the Massachusetts service location of Select Energy Contracting – Connecticut (SECI-CT), a division of SECI, was sold for approximately $2 million.

NU Enterprises also exited all of its New England wholesale sales obligations by either buying out those contracts or assigning its obligations to third parties. Most of these contracts were with municipal electric companies. In 2005, NU Enterprises paid approximately $186 million to exit those obligations and agreed to pay another approximately $56 million.

NU Enterprises recorded a loss of $398.2 million in 2005, or $3.03 per share, compared with a loss of $15.1 million, or $0.12 per share, in 2004, and a loss of $3.4 million, or $0.03 per share, in 2003. The 2005 loss was primarily due to a net after-tax charge of $278.9 million as a result of the marking-to-market of various wholesale contracts, including the approximately $186 million contract payment and the $56 million obligation noted above. $9.8 million of the $278.9 million after-tax charge is included in discontinued operations. In 2004, NU Enterprises results included an after-tax loss of $48.3 million associated with mark-to-market accounting for certain natural gas positions established to

mitigate the risk of electricity purchased in anticipation of winning certain levels of wholesale electric load in New England. These positions were balanced by entering into offsetting positions in the first quarter of 2005 and had no impact on earnings since then.

NU Enterprises 2005 results also reflect $43.7 million of after-tax restructuring and impairment charges related to both the merchant energy and the energy services businesses. Those charges include $16.4 million associated with discontinued operations. There were no impairment charges in 2004.

A summary of NU Enterprises’ (losses)/earnings for 2005, 2004, and 2003 is as follows:


	For the Years Ended December 31,
(Millions of Dollars)	2005	2004	2003
Merchant Energy (1)	$(360.6)	$(17.3)	$(6.7)
Energy Services, Parent and Other (2)	(37.6)	2.2	3.3
Total NU Enterprises Net Loss	$(398.2)	$(15.1)	$(3.4)

(1)

The merchant energy losses above totaling $360.6 include $397 million of continuing operations losses, offset by $36.4 million (including a negative $1 million cumulative effect of accounting change) of discontinued operations earnings for the year ended December 31, 2005. The 2004 losses totaling $17.3 million include $60.5 million of continuing operations losses, offset by $43.2 million of discontinued operations earnings. The 2003 losses totaling $6.7 million include $45.9 million of continuing operations losses offset by $39.2 million of discontinued operations earnings.

(2)

The energy services, parent and other losses include losses totaling $23.3 million for the year ended December 31, 2005 and earnings totaling $3.6 million and $4.7 million for the years ended December 31, 2004 and 2003, respectively, which are classified as discontinued operations.

The merchant energy business lost $360.6 million in 2005, compared with $17.3 million in 2004 and $6.7 million in 2003. A significant number of charges impacted NU Enterprises’ merchant energy business results in 2005. Extreme increases in gas and oil prices in 2005 negatively affected sale obligations which had not yet been exited.

NU recorded $269.1 million of after-tax ($425.4 million pre-tax) wholesale contract market changes for the year ended December 31, 2005, related to changes in the fair value of wholesale contracts that the company is in the process of exiting. The changes are comprised of the following items:

A charge of $257.4 million after-tax ($406.9 million pre-tax) related to the mark-to-market of certain long-dated wholesale electricity contracts in New England and New York with municipal and other customers. The charge reflects negative mark-to-market movements on these contracts through December 31, 2005 as a result of rising energy prices, partially offset by positive effects of buying out certain obligations in 2005 at prices less than their marks at the time;

A charge of approximately $50.6 million after-tax (approximately $80 million pre-tax) related to purchases of additional electricity for an increase in the load forecasts related to a full requirements contract with a customer in the PJM power pool;

A benefit of approximately $24 million after-tax (approximately $38 million pre-tax) related to mark-to-market gains on certain generation related contracts which the company is in the process of exiting;

A benefit of $37.9 million after-tax ($59.9 million pre-tax) for mark-to-market gains primarily related to retail supply contracts that were previously held by the wholesale business to serve certain retail electric load, which the company has exited or settled. Included in the $37.9 million of after-tax gains ($59.9 million pre-tax) is $19 million of after-tax ($30 million pre-tax) gains related to retail supply contracts marked-to-market as a result of the March 9, 2005 decision to exit the wholesale marketing business.

A charge of $23 million after-tax ($36.4 million pre-tax) for mark-to-market contract asset write-offs related to long-term wholesale electricity contracts and a contract termination payment in March of 2005.

A charge of $9.8 million after-tax ($15.5 million pre-tax) was also recorded in the fourth quarter of 2005 in connection with the decision to exit the competitive generation business related to marking-to-market two contracts to sell the output of its generation in 2007 and 2008 and is included in discontinued operations. NU Enterprises is in the process of exiting these contracts. These two generation sales contracts were formerly accounted for under accrual accounting; however, accrual accounting was terminated in the fourth quarter of 2005 due to the high probability that these contracts would be net settled instead of physically delivered.

The termination of several municipal wholesale contracts in New England resulted in NU Enterprises having additional generation from HWP’s Mt. Tom coal-fired plant and NGC’s conventional hydroelectric plants available for sale in the wholesale market. In 2005, NU Enterprises signed agreements to sell a total of approximately 1.4 million megawatt-hours (MWhs) from Mt. Tom to counterparties during the years 2006 through 2008. Approximately 1 million MWhs are generated annually at Mt. Tom per year. Those sales are at prices significantly in excess of Mt. Tom’s contracted coal cost.

For further information regarding these derivative assets and liabilities that are being exited, see Note 2, "Wholesale Contract Market Changes," and Note 6, "Derivative Instruments," to the consolidated financial statements.

In addition to the mark-to-market, restructuring and impairment charges noted above, NU Enterprises results in 2005 reflect lower sales for the wholesale marketing business than in 2004 as a result of the announced exit from that business in March of 2005.

In 2004, NU Enterprises recorded an after-tax charge of $48.3 million associated with marking-to-market certain wholesale natural gas contracts intended to hedge certain wholesale electricity purchase obligations.

Exclusive of after-tax charges related to wholesale supply totaling $29.1 million and other after-tax restructuring and impairment charges totaling $5.8 million, NU Enterprises’ retail marketing business earned $6.3 million in 2005, compared with earnings of $4.9 million in 2004 and a loss of $1.8 million in 2003. The charges related to wholesale supply were the result of a requirement to account for the sourcing of its customers’ electric requirements at March 31, 2005 market prices for supply contracts signed in the past at lower prices. This was necessitated by the fact that the source of those contracts, wholesale marketing, is being divested. As a result, an after-tax gain on those contracts of $59.9 million was recorded in the first quarter of 2005 that represented estimated future margins on existing retail transactions. As a result, future retail marketing business results will be negatively affected until the exit from that business is completed.

The energy services businesses and NU Enterprises parent lost $37.6 million in 2005, compared with earnings of $2.2 million in 2004 and earnings of $3.3 million in 2003. The 2005 loss was due to after-tax restructuring and impairment charges of $26.7 million primarily associated with the impairment of goodwill and intangible assets and as a result of construction contract losses. The portion of the charges directly relating to the energy services businesses totaling $16.4 million after-tax is included in the income from discontinued operations on the accompanying consolidated statements of (loss)/income as the charges relate to the energy services companies that are presented as discontinued operations.

For information regarding the current status of the exit from the NU Enterprises businesses, see "NU Enterprises Divestitures," included in this management’s discussion and analysis.

Parent and Other: Parent company and other after-tax expenses totaled $18.7 million in 2005, or $0.14 per share, compared with $23.9 million in 2004, or $0.18 per share, and $12.7 million, or $0.10 per share, in 2003. The losses in 2005 included after-tax investment write-downs totaling $4.3 million while the losses in 2004 included after-tax investment write-downs totaling $8.8 million.

Future Outlook

NU projects that 2006 combined earnings for the Utility Group and parent company will be between $1.09 per share and $1.22 per share.

Utility Group: NU believes that the combination of the current mild winter to date in 2006, slowing non-weather related sales and the denial of interim rate relief for Yankee Gas in 2005 may cause the Utility Group’s regulated distribution and generation businesses earnings to be below its previously estimated 2006 earnings range of between $0.89 and $0.96 per share. Utility Group earnings will also be affected by the outcome of various retail distribution rate proceedings and by the outcome of a transmission ROE proceeding at the FERC. NU continues to estimate 2006 transmission business earnings of between $0.32 and $0.35 per share.

NU Enterprises: NU is not providing 2006 earnings guidance for NU Enterprises due to the uncertainty of any potential financial impacts of exiting those businesses.

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

Liquidity

Consolidated: NU continues to maintain an adequate level of liquidity. At December 31, 2005, NU’s total unused borrowing capacity through its revolving credit agreement, its separate liquidity facility, the Utility Group’s revolving credit agreement, and CL&P’s accounts receivable facility totaled $1.1 billion. At December 31, 2005, NU also had $45.8 million of cash and cash equivalents on hand compared with $47 million at December 31, 2004.

Cash flows from operations decreased by $19.4 million to $441.2 million in 2005 from $460.6 million in 2004. The decrease in operating cash flows is primarily due to the 2005 payments made for the exit from long-term wholesale power contracts by NU Enterprises of approximately $186 million and an accounts receivable increase due to the retail distribution rate increases that took effect in 2005 offset by increases in working capital items including an accounts payable increase related to timing of payments to standard offer suppliers and a change in year over year accrued taxes.

Cash flows from operations decreased by $228.4 million from $689 million in 2003 to $460.6 million in 2004. Increases in cash flows related to deferred income taxes were offset by decreases related to regulatory (refunds)/overrecoveries. The decrease in year over year cash flows from regulatory (refunds)/overrecoveries was primarily due to lower CTA and Generation Service Charge (GSC) collections in 2004 as CL&P refunded amounts to its ratepayers for past over collections or used those amounts to recover current costs. These refunds were also the primary reason for the positive change in year over year deferred income taxes, which had increased operating cash flows as refunded amounts were currently deducted for tax purposes. Lower taxes paid also benefited cash flows from operations in 2004 due to bonus tax depreciation on newly completed plant assets.

On October 20, 2005, the SEC approved NU’s application which sought the authority to issue up to $750 million of new securities, including common equity, preferred stock and long-term debt. On December 12, 2005, under an S-3 registration statement that became effective on November 3, 2005, NU sold 23 million common shares at a price of $19.09 per share. Proceeds from this issuance, which were approximately $425 million after underwriter commissions and expenses, were used to reduce short-term debt and will be used in the future to continue to contribute equity to the Utility Group companies. In 2005, NU contributed $198 million of equity to CL&P, $53.6 million to PSNH and $6.9 million to WMECO. No contributions were made to Yankee Gas.

On October 28, 2005, NU received approval from the SEC to increase its short-term borrowing limit from $450 million to $700 million. On December 9, 2005, NU entered into an amended revolving credit agreement that increased NU’s credit line from $500 million to $700 million and extended the maturity date of the agreement by one year to November 6, 2010. As of December 31, 2005, NU had $32 million of borrowings and $253 million of letters of credit (LOCs) outstanding under that agreement.

On November 2, 2005, NU entered into a separate $600 million liquidity facility, which added to other sources of liquidity. After NU amended its revolving credit agreement and closed on its equity issuance as described above, the commitment level under this supplemental credit facility was reduced to $310 million. At December 31, 2005, there were no borrowings outstanding under this facility.

Exiting the NU Enterprises’ wholesale marketing business had a negative impact on cash flows in 2005 and is expected to continue to have a negative impact in 2006. During 2005, approximately $186 million was paid to exit contracts either directly with municipal electric companies in New England or with other counterparties. During 2005, commitments were also made to pay another approximately $56 million to a counterparty to exit obligations with a New England municipality.

The exit from NU Enterprises’ competitive generation and retail marketing business is expected to benefit NU’s liquidity and reduce debt. The net proceeds from NU Enterprises’ competitive generation asset sales are expected to be an important factor in NU’s financing plans. The NGC and HWP generation assets of 1,442 MW of pumped storage, conventional hydroelectric, coal-fired, and peaking generation assets are expected to have a book value of approximately $825 million. The cash proceeds available to NU after the sale will be reduced by NGC’s debt of $320 million and by any taxes that will have to be paid.

Negotiations are continuing with parties interested in acquiring NU Enterprises’ remaining services businesses, which had an aggregate book value of approximately $45 million at December 31, 2005 and debt owed to third-party lenders of approximately $90 million. In the fourth quarter of 2005, NU Enterprises sold SECI-NH and Woods Network to separate third parties for a total of approximately $6.5 million. In January of 2006, the Massachusetts service location of SECI-CT was sold for approximately $2 million.

NU’s senior unsecured debt is rated Baa2 and BBB- with a stable outlook by Moody’s Investors Service (Moody’s) and Standard & Poor’s (S&P), respectively, and is rated BBB with a stable outlook by Fitch Ratings. At December 31, 2005, Select Energy at NU’s current credit ratings levels could have been requested to provide $12.7 million of collateral under certain contracts which counterparties have not required to date. If NU were to be downgraded to a sub-investment grade level by either Moody’s or S&P, a number of Select Energy’s contracts would require the posting of additional collateral in the form of cash or LOCs. Were NU’s senior unsecured ratings to be reduced to sub-investment grade by either Moody’s or S&P, Select Energy could, under its present contracts, be asked to provide approximately $406.6 million of collateral or LOCs to various unaffiliated counterparties and approximately $95.7 million to several independent system operators and unaffiliated local distribution companies (LDCs) at December 31, 2005. If such a downgrade were to occur, management believes NU would currently be able to provide this collateral. The company’s decision to exit its competitive generation business resulted in S&P downgrading NGC debt by three notches to B+, well below investment grade. Moody’s and Fitch Ratings have both placed NGC under review for downgrade, but management does not believe that such a downgrade, in and of itself, would have a negative impact on the ratings of NU or any other subsidiary.

NU paid common dividends of $87.6 million in 2005, compared with $80.2 million in 2004 and $73.1 million in 2003. The increase in common dividends reflects increases in quarterly dividends of $0.0125 per share in the third quarters of 2003, 2004, and 2005. Management expects to continue its current policy of dividend increases, subject to the approval of the NU Board of Trustees and the company’s future earnings and cash requirements. On February 14, 2006, the NU Board of Trustees approved a quarterly dividend of $0.175 per share, payable March 31, 2006, to shareholders of record as of March 1, 2006. In general, the Utility Group companies pay approximately 60 percent of their cash earnings to NU in the form of common dividends. In 2005, CL&P, PSNH, WMECO, and Yankee Gas paid $53.8 million, $42.4 million, $7.7 million, and $30.8 million, respectively, in common dividends to NU.

Capital expenditures described herein are cash capital expenditures and do not include cost of removal, allowance for funds used during construction (AFUDC), and the capitalized portion of pension expense or income. NU’s capital expenditures totaled $775.4 million in 2005, compared with $671.5 million in 2004 and $558.1 million in 2003. NU’s 2005 capital expenditures included $444.4 million by CL&P, $158.8 million by PSNH, $44.7 million by WMECO, $74.6 million by Yankee Gas, and $52.9 million by other NU subsidiaries, including $23.2 million by NU Enterprises. The increase in NU’s capital expenditures was primarily the result of higher transmission capital expenditures, particularly at CL&P and was also the result of higher capital expenditures at Yankee Gas, primarily due to construction of its liquefied natural gas storage and production facility. Utility Group capital expenditures are expected to increase further approaching $900 million in 2006, including approximately $600 million, $150 million, $50 million, and $100 million for CL&P, PSNH, WMECO, and Yankee Gas, respectively. On a consolidated basis, NU estimates capital expenditures of approximately $900 million in 2007, $950 million in 2008, $800 million in 2009 and $800 million in 2010.

NU expects to fund approximately half of its expected capital expenditures over the next several years through internally generated cash flows. As a result, the company expects its Utility Group companies, particularly CL&P, to issue debt regularly. In 2005, CL&P issued $200 million of first mortgage bonds, PSNH and Yankee Gas each issued $50 million of first mortgage bonds and WMECO issued $50 million of senior notes.

Management does not currently expect to issue additional common equity before 2008. The actual timing of a common equity issuance will depend on a number of factors, including actual levels of capital expenditures, net proceeds from the exit from the NU Enterprises businesses and proposals now before the FERC to provide financial incentives for the construction of additional electric transmission facilities in the United States. Some of the incentives under consideration by the FERC, such as accelerated depreciation and the inclusion of CWIP in rate base, could increase NU’s internally generated cash flows.

Utility Group: The Utility Group companies entered into an amended revolving credit agreement that maintained their $400 million credit line and extended the maturity date of their agreement by one year to November 6, 2010. There were no borrowings outstanding under that agreement at December 31, 2005.

In addition to its revolving credit line, CL&P has an arrangement with a financial institution under which CL&P can sell up to $100 million of accounts receivable and unbilled revenues. At December 31, 2005, CL&P had sold $80 million to that financial institution. For more information regarding the sale of receivables, see Note 1O, "Summary of Significant Accounting Policies – Sale of Receivables" to the consolidated financial statements.

On April 7, 2005, CL&P sold $100 million of 10-year first mortgage bonds carrying a coupon rate of 5.0 percent and $100 million of 30-year first mortgage bonds carrying a coupon rate of 5.625 percent. Proceeds were used to repay short-term borrowings.

On July 21, 2005, Yankee Gas sold $50 million of 30-year first mortgage bonds. The interest rate was 5.35 percent. Proceeds were used to repay short-term borrowings used to finance capital expenditures.

On August 11, 2005, WMECO sold $50 million of 10-year senior notes with an interest rate of 5.24 percent. On October 5, 2005, PSNH sold $50 million of 30-year first mortgage bonds with an interest rate of 5.6 percent. Proceeds from both issuances were used to repay short-term borrowings used to finance capital expenditures.

NU Enterprises: Currently, NU Enterprises’ liquidity is impacted by both the amount of collateral it receives from other counterparties and the amount of collateral it is required to deposit with counterparties. From December 31, 2004 to December 31, 2005, NU Enterprises’ liquidity was negatively impacted by $76.5 million from counterparty collateral deposits being repaid and higher counterparty collateral deposits being made. In 2005, NU Enterprises also made approximately $186 million of payments to exit municipal and certain other long-term wholesale power contracts in New England.

Most of the working capital and LOCs required by NU Enterprises are currently used to support the wholesale marketing business. As NU Enterprises’ wholesale contracts expire or are exited, its liquidity requirements are expected to decline. However, the sale or renegotiation of additional longer-term below market wholesale power contracts will likely require NU Enterprises to continue to make significant payments to the counterparties in such transactions.

Strategic Overview

In 2005, NU announced the decision to exit all of NU Enterprises’ competitive businesses and increase its investment in its regulated businesses to a significantly higher level. Exiting these businesses, which management expects to substantially complete by the end of 2006, will simplify NU’s business model, reduce business risk, improve financial flexibility, enhance earnings visibility and predictability, and capitalize on the value of generation assets in New England. Exiting these businesses is also expected to help benefit the credit ratings of NU and its Utility Group companies. Credit rating agencies generally require lower coverage ratios for regulated transmission and distribution companies than for competitive generating and marketing companies because the stability and predictability of regulated company cash flows is generally much higher. As a result, management believes that once the competitive businesses are fully exited, the company will be able to maintain its current investment grade ratings with higher levels of debt and interest expense than if the competitive businesses were retained.

NU expects the Utility Group to invest up to $4.3 billion in its electric transmission and distribution and natural gas distribution businesses from 2006 through 2010. Those amounts include up to $2.3 billion for the high-voltage electric transmission system and $2 billion for the electric and natural gas distribution systems and regulated generation. NU estimates that when it successfully meets this goal, it will achieve compounded annual regulated rate base growth through 2010 of approximately 14 percent, assuming appropriate regulatory actions. That growth rate would include compounded annual growth of approximately 29 percent in its regulated electric transmission rate base and 8 percent in its regulated distribution and generation rate base. Based on the issuance of 23 million common shares in December of 2005 and projected issuances of additional common shares beyond 2007, parent company expenses, and assuming appropriate regulatory actions, NU estimates that it could achieve earnings per share growth of between 8 percent and 10 percent annually beginning with 2007.

Enterprise Risk Management

In 2005, NU adopted Enterprise Risk Management (ERM) as a methodology for managing the principle risks of the company. ERM involves the application of a well-defined, enterprise-wide methodology which will enable NU’s Risk and Capital Committee, comprised of senior NU officers, to oversee the identification, management and reporting of the principal risks of the business.

NU Enterprises Divestitures

On March 9, 2005, NU announced that NU Enterprises would exit its wholesale marketing business and its energy services businesses. On November 7, 2005, NU announced its decision to exit the remainder of NU Enterprises’ competitive businesses, which includes the retail marketing and competitive generation businesses. NU intends to apply the net proceeds from the exiting of these businesses to debt reduction and the financing of the regulated businesses’ capital spending programs. An overview of this process is as follows:

Wholesale Marketing Business: In 2005, NU Enterprises recorded a net negative after-tax mark-to-market charge of $278.9 million related to the wholesale energy contracts being exited. Included in this negative mark-to-market charge, in 2005 NU Enterprises paid or agreed to pay approximately $242 million to complete the exit from its New England wholesale sales contracts. In 2005, all but approximately $56 million of that sum was paid. NU Enterprises’ exposure related to its remaining wholesale power obligations in the PJM power pool, which expire in 2008, and in New York, which consists of a single contract that expires in 2013, continues to decline as these obligations roll off.

Retail Marketing Business: NU has retained J. P. Morgan as a financial advisor in exiting the retail marketing business, which provides electricity and natural gas service to approximately 30,000 customer locations in New England, New York and PJM. Sales documents were distributed to prospective buyers of the retail marketing business in January of 2006 and indicative bids, which were received in February of 2006, are under evaluation. NU plans to close on the sale of the retail marketing business in mid-2006.

The decision to exit the retail marketing business also required that the retail sales contracts be evaluated to determine whether these contracts are derivatives, and if so, whether these contracts should be marked-to-market. After a thorough review, the company concluded that these contracts should not be marked-to-market at December 31, 2005 because most of these contracts are not derivatives, but should continue to be accounted for on the accrual basis. The sales revenue to be received from these contracts is below current market prices, and the retail marketing business will likely be sold without the benefit of either certain below market supply contracts or supply from NU Enterprises’ generation resources. As a result, a payment to the buyer may be required to exit the retail marketing business. This payment will depend upon the results of the bidding process currently underway and market prices at the time of divestiture and could be significant. NU is currently in the process of marketing the retail business.

Competitive Generation Business: NU has also retained J. P. Morgan as a financial advisor in exiting the competitive generation business, which includes NGC’s and HWP’s competitive generation assets in Massachusetts and Connecticut. Sales documents were distributed to prospective buyers of the generation assets in February of 2006 and NU expects to close on the sale of the generation assets by the end of 2006.

Energy Services Businesses: In 2005, NU Enterprises sold two of its six energy services businesses, SECI-NH and Woods Network, for a total of approximately $6.5 million. In January of 2006, the Massachusetts service location of SECI-CT was sold for approximately $2 million. NU Enterprises expects to complete the sale of SESI during 2006. NU Enterprises is in the process of marketing Woods Electrical to potential buyers and expects to complete the sale of Woods Electrical during 2006.

NU Enterprises’ two remaining energy services businesses, SECI-CT and Boulos will be actively marketed during 2006. For further information regarding these companies, see Note 4, "Assets Held For Sale and Discontinued Operations," to the consolidated financial statements.

Business Development and Capital Expenditures

Consolidated: In 2005, NU’s capital expenditures totaled $775.4 million, compared with depreciation of $235.2 million. In 2004 and 2003, capital expenditures totaled $671.5 million and $558.1 million, compared with depreciation of $224.9 million and $204.4 million, respectively. In 2006, total capital expenditures are projected to approach $900 million. The increasing level of capital expenditures was caused primarily by a need to continue to improve the capacity and reliability of NU’s regulated transmission system. That increased level of capital expenditures, compared with depreciation levels, also is increasing the amount of plant in service and the regulated companies’ earnings base, provided that NU’s Utility Group companies achieve timely recovery of their investment. Unless otherwise noted, the capital expenditure amounts below exclude AFUDC.

NU currently forecasts transmission expenditures of up to $2.3 billion from 2006 through 2010. Those expenditures include $1.3 billion on the four southwest Connecticut projects as more fully described below, $0.8 billion of additional transmission projects management expects to be built, and $0.2 billion on projects that remain in the conceptual phase. Management forecasts approximately $450 million of transmission capital expenditures in 2006 and approximately $550 million of transmission capital expenditures in 2007 and 2008, including AFUDC. In addition, approximately $2 billion of distribution and generation projects is currently forecasted from 2006 to 2010, totaling up to $4.3 billion in total Utility Group capital projects. Capital expenditures for NU Enterprises are still expected to be modest.

Utility Group:

CL&P: In December of 2003, the DPUC approved a total of $900 million of distribution capital expenditures for CL&P from 2004 through 2007. Those expenditures are intended to improve the reliability of the distribution system and to meet growth requirements on the distribution system. In 2005, CL&P’s distribution capital expenditures totaled $236.6 million, compared with $254.7 million in 2004 and $255.9 million in 2003. In 2006, CL&P projects distribution capital expenditures of approximately $200 million.

CL&P’s transmission capital expenditures totaled $207.8 million in 2005, compared with $134.6 million in 2004 and $62.6 million in 2003. The increase in CL&P’s transmission capital expenditures in 2005 was primarily the result of increased spending on a new 21-mile 345 kilovolt (kV) transmission project between Bethel, Connecticut and Norwalk, Connecticut. In 2006, CL&P’s transmission capital expenditures are projected to total approximately $400 million.

Transmission capital expenditures in Connecticut are focused primarily on four major transmission projects in southwest Connecticut. These projects include 1) the Bethel to Norwalk project noted above, 2) a Middletown to Norwalk 345 kV transmission project, 3) a related 115 kV underground project (Glenbrook Cables), and 4) the replacement of the existing 138 kV cable between Connecticut and Long Island. Each of these projects has received approval from the Connecticut Siting Council (CSC) and ISO-NE. Capital expenditures for these projects in southwest Connecticut totaled $156 million (including AFUDC) in 2005 out of the $207.8 million ($257.3 million including AFUDC) in total transmission and other capital expenditures in 2005.

Underground line construction activities began in April of 2005 on a 21-mile 115 kV/345 kV line project between Bethel and Norwalk, with overhead line work commencing in September of 2005. The first substation (Plumtree) was successfully energized on September 23, 2005. The first 6.2 mile section of 115 kV cable was energized in the fourth quarter of 2005. This project is expected to cost approximately $350 million of which CL&P spent $130.7 million (including AFUDC) in 2005. The project is approximately 70 percent complete and CL&P had capitalized $196 million associated with the project at December 31, 2005. This project is expected to be completed by the end of 2006.

On April 7, 2005, the CSC unanimously approved a proposal by CL&P and United Illuminating to build a 69-mile 345 kV transmission line from Middletown to Norwalk, Connecticut. Approximately 24 miles of the 345 kV line will be built underground with the balance being built overhead. The project still requires CSC review of detailed construction plans, as well as United States Army Corps of Engineers approval to bury the line beneath certain navigable rivers and Department of Environmental Protection (DEP) approvals. The CSC decision included provisions for low-magnetic field designs in certain areas and made variations to the proposed route. CL&P’s portion of the project is estimated to cost approximately $1.05 billion. CL&P received final technical approval from ISO-NE on January 20, 2006 and expects to award the major construction-related contracts during the second quarter of 2006. CL&P expects the project to be completed by the end of 2009. Legal review of three appeals related to this project is ongoing. At this time, CL&P does not expect any of these three appeals to delay construction. At December 31, 2005, CL&P has capitalized $41 million associated with this project.

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

On October 1, 2004, CL&P and the Long Island Power Authority (LIPA) jointly filed plans with the Connecticut DEP to replace an undersea 13-mile electric transmission line between Norwalk, Connecticut and Northport – Long Island, New York, consistent with a comprehensive settlement agreement reached on June 24, 2004. CL&P and LIPA each own approximately 50 percent of the line. On June 20, 2005, the New York State Controller’s Officer and the New York State Attorney General approved the settlement agreement between CL&P and LIPA to replace the cable and the project had earlier received CSC approval. State and federal permits are expected to be issued in the second quarter of 2006. Assuming these permits are received by no later than the second quarter of 2006 and the necessary construction contracts are signed, construction activities will begin when material lead times allow. Management will provide the estimated removal and in service dates when these construction contracts are signed. At December 31, 2005, CL&P has capitalized $6 million associated with this project.

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

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

Yankee Gas: In 2005, Yankee Gas’ capital expenditures totaled $74.6 million. Yankee Gas is constructing a LNG storage and production facility in Waterbury, Connecticut, which will be capable of storing the equivalent of 1.2 billion cubic feet of natural gas. Construction of the facility began in March of 2005 and is expected to be completed in time for the 2007/ 2008 heating season. The facility, which is expected to cost $108 million, is approximately 48 percent complete. Yankee Gas has capitalized $46.4 million related to this project at December 31, 2005.

The LNG project represented approximately 45 percent of Yankee Gas’ capital expenditures in 2005. In 2005, including AFUDC, Yankee Gas also spent $17.7 million on its reliability improvement program, $13.8 million on connecting new customers, and $10.1 million on other initiatives, including meters and information technology systems. In 2006, Yankee Gas projects total capital expenditures of approximately $100 million.

PSNH: In 2005, PSNH’s capital expenditures totaled $158.8 million, including $131.9 million on PSNH’s electric distribution system and generation. This $158.8 million includes $45 million related to the conversion of a 50 MW coal-fired unit at Schiller Station in Portsmouth, New Hampshire to burn wood (Northern Wood Power Project). The Northern Wood Power Project began in late 2004 and is expected to achieve commercial generation in the second half of 2006. The NHPUC’s 2004 approval of the project was appealed to the New Hampshire Supreme Court by some of New Hampshire’s existing wood-fired generating plant owners. The Supreme Court upheld the NHPUC’s finding that the project is in the public interest and, as a result, the project was able to proceed in accordance with the original schedule. This project is approximately 90 percent complete and PSNH has capitalized $64.7 million related to this project at December 31, 2005.

In 2005, PSNH also spent $26.9 million on upgrading and expanding its electric transmission system. In 2006, PSNH projects total capital expenditures of approximately $150 million.

WMECO: In 2005, WMECO’s capital expenditures totaled $44.7 million, including $32.4 million in its electric distribution system and other capital expenditures and $12.3 million on its electric transmission system. As part of WMECO’s rate settlement approved by the DTE on December 29, 2004, WMECO agreed to invest not less than $24 million in capital expenditures in 2005 and 2006 related to reliability improvements. In 2006, WMECO projects total capital expenditures of approximately $50 million.

NU Enterprises: In March of 2005, HWP notified Massachusetts environmental regulators that it planned to install a selective catalytic reduction system at the 146 MW Mt. Tom coal-fired station in Holyoke, Massachusetts. The system will significantly reduce nitrogen oxide emissions from the unit and extend its operating life by meeting expected emission requirements through 2010. The $14 million project commenced in July of 2005 and is expected to be complete by mid-2006. At December 31, 2005, this project was approximately 75 percent complete and HWP has capitalized $9.9 million related to this project.

Transmission Access and FERC Regulatory Changes

In January of 2005, the New England transmission owners approved activation of the New England Regional Transmission Organization (RTO) which occurred on February 1, 2005. CL&P, PSNH and WMECO are now members of the New England RTO and provide regional open access transmission service over their combined transmission system under the ISO-NE Transmission, Markets and Services Tariff, FERC Electric Tariff No. 3 and local open access transmission service under the ISO-NE Transmission, Markets and Services Tariff, FERC Electric No. 3, Schedule 21 – NU.

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

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

Legislative Matters

Federal Energy Legislation: On August 8, 2005, President Bush signed into law comprehensive energy legislation. Among provisions potentially affecting NU are the repeal of PUHCA, FERC backstop siting authority for transmission, transmission pricing and rate reform, renewable production tax credits, and accelerated depreciation for certain new electric and gas facilities. The renewable production tax credits provision is expected to save PSNH approximately $3 million annually in federal income taxes for the first 10 years after the Northern Wood Power Project becomes operational. The accelerated depreciation provision, assuming timely rate recovery, is expected to increase Utility Group cash flows by more than $5 million annually. As part of this legislation, some but not all of the SEC’s responsibilities under PUHCA were transferred to the FERC.

Environmental Legislation: The RGGI is a cooperative effort by certain northeastern states to develop a regional program for stabilizing and ultimately reducing CO2 emissions from fossil-fired electric generators. This initiative proposed to stabilize CO2 emissions at current levels and require a ten percent reduction by 2020. he RGGI agreement was signed on December 20, 2005 by the states of Connecticut, Delaware, Maine, New Jersey, New Hampshire, New York, and Vermont. Each state commits to propose for approval legislative and regulatory mechanisms to implement the program. RGGI may impact PSNH’s Merrimack, Newington and Schiller stations. At this time, the impact of this agreement on NU cannot be determined.

On January 1, 2006 a CO2 cap on emissions from fossil-fired electric generators took effect in Massachusetts, with a separate CO2 emissions rate limit effective in 2008. Affected parties are currently awaiting the Massachusetts DEP’s proposal concerning a trading or other form of offset program. HWP’s Mt. Tom plant would be impacted by this regulation. Given the uncertainty of the future compliance mechanism under these regulations, the impact of this regulation on NU and the potential sale of Mt. Tom cannot be determined.

Connecticut:

Transmission Tracking Mechanism: On July 6, 2005, Connecticut adopted legislation creating a mechanism to allow the DPUC to true-up, at least annually, the retail transmission charge in local electric distribution company rates based on changes in FERC-approved charges. This mechanism allows CL&P to include forward-looking transmission charges in its retail transmission rate and promptly recover its transmission expenditures. On December 20, 2005, the DPUC approved CL&P’s August 1, 2005 proposal to implement the mechanism effective July 1, 2005, which includes two adjustments annually, in January and June. On January 1, 2006, consistent with that approval, CL&P raised its retail transmission rate to collect $21 million of additional revenues over the first six months of 2006.

Energy Legislation: Public Act 05-01, an "Act Concerning Energy Independence," (Act) was signed by Governor Rell on July 22, 2005. The new legislation provides incentives to encourage the construction of distributed generation, new large-scale generation, and conservation and load management initiatives to reduce FMCC charges. FMCC charges represent the costs of power market rules approved by the FERC that are resulting in significantly higher costs for Connecticut. The most significant cost item in 2005 is reliability must run (RMR) contracts. The legislation requires regulators to a) implement near-term measures as soon as possible, and b) commence a new request for proposals to build customer side distributed resources and contracts for new or repowered larger generating facilities in the state. Developers could receive contracts of up to 15 years from the distribution companies. The legislation provides utilities with the opportunity to earn one-time awards for generation that is installed in their service territories. Those awards can be as high as $200 per kilowatt for distributed generation and $25 per kilowatt for more traditional generation. It also allows distribution companies, such as CL&P, to bid as much as 250 MW of capacity into the request for proposals. If such utility bid was accepted, then the unit after five years would have to be a) sold, b) have its capacity sold, or c) both, provided that the DPUC could waive these requirements. The DPUC is conducting a number of new dockets to implement this legislation. The legislation also requires the DPUC to investigate the financial impact on distribution companies of entering into long-term contracts and to

allow distribution companies to recover through rates any increased costs. The DPUC ruled that at this point the impact is hypothetical and instructed the utilities to raise the issue in subsequent rate cases.

New Hampshire:

Environmental Legislation: The New Hampshire legislature is considering a bill in its 2006 legislative session that would place strict limitations on the level of mercury that PSNH’s existing generation plants can emit. Legislation was first proposed in the 2005 session and passed by the New Hampshire senate in 2005 which would require PSNH to achieve fixed annual caps as early as 2009. The bill was subsequently defeated by the New Hampshire House of Representatives early in 2006. The legislature will now take up a new bill that requires PSNH to reduce power plant mercury emissions by at least 80 percent by 2013 while providing incentives for early reductions. Management has been reviewing the proposed legislation. PSNH’s primary long-term alternative is to install wet scrubber equipment at its Merrimack Station at a cost of approximately $250 million. PSNH’s other alternatives include the use of carbon injection pollution control equipment, reducing operating capacity of its plants and possible retirement or repowering of one or more of its generating units. While state law and PSNH’s restructuring agreement provide for the recovery of its generation costs, including the cost to comply with state environmental regulations, at this time management is unable to determine the impact of any potential new legislation on PSNH’s net income or financial position.

Utility Group Regulatory Issues and Rate Matters

Transmission – Wholesale Rates: Wholesale transmission revenues are based on rates and formulas that are approved by the FERC. Most of NU’s wholesale transmission revenues are collected through a combination of the RNS tariff and NU’s LNS tariff. NU’s LNS rate is reset on January 1 and June 1 of each year. NU’s RNS rate is reset on June 1 of each year. On January 1, 2006, NU’s LNS rates increased NU wholesale revenues by approximately $18 million on an annualized basis. The LNS and RNS rates to be effective on June 1, 2006 have not yet been determined. Additionally, NU’s LNS tariff provides for a true-up to actual costs, which ensures that NU’s transmission business recovers its total transmission revenue requirements, including the allowed ROE. At December 31, 2005, this true-up resulted in the recognition of a $2.1 million regulatory liability, including approximately $1.5 million due to NU’s electric distribution companies.

On December 1, 2005, NU filed at the FERC a request to include 50 percent of construction work in progress for its four major southwest Connecticut transmission projects in its formula rate for transmission service (Schedule 21 – NU (LNS)). The FERC approved the filing with new rates effective on February 1, 2006. The new rates allow NU to collect 50 percent of the construction financing expenses while these projects are under construction.

Transmission – Retail Rates: A significant portion of the NU transmission business revenue comes from ISO-NE charges to the distribution businesses of CL&P, PSNH and WMECO. The distribution businesses recover these costs through the retail rates that are charged to their retail customers. In July of 2005, CL&P began tracking its retail transmission revenues and expenses and on January 1, 2006 raised its retail transmission rate to collect $21 million of additional revenues over the first six months of 2006. CL&P adjusts its retail transmission rates on a regular basis, thereby recovering all of its retail transmission expenses on a timely basis. This new tracking mechanism resulted from the enactment of the new legislation passed by the Connecticut legislature in 2005. WMECO implemented its retail transmission tracker and rate adjustment mechanism in January of 2002 as part of its 2002 rate change filing. PSNH does not currently have a retail transmission rate tracking mechanism.

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

After opposition from state regulators, utilities and various Congressional delegations, the FERC ordered settlement negotiations before an ALJ to determine whether there was an acceptable alternative to LICAP. On March 6, 2006, ISO-NE and a broad cross-section of critical stakeholders from around the region, including CL&P, PSNH and Select Energy, filed a comprehensive settlement agreement at the FERC implementing a Forward Capacity Market (FCM) in place of LICAP. The settlement agreement provides for a fixed level of compensation to generators from December 1, 2006 through May 31, 2010 without regard to location in New England, and annual forward capacity auctions, beginning in 2008, for the 1-year period ending on May 31, 2011, and annually thereafter. The settlement agreement must be approved by the FERC, and the parties have asked for a decision by June 30, 2006. According to preliminary estimates, FCM would require the operating companies to pay approximately the following amounts during the 3 1/2-year transition period: CL&P - $470 million; PSNH - $80 million; and WMECO - $100 million. CL&P would be able to recover these costs from its customers through the FMCC mechanism. PSNH and WMECO also would be able to recover these costs from their customers.

Connecticut – CL&P:

Streetlighting Decision: On June 30, 2005, the DPUC issued a final decision which required CL&P to recalculate all previously issued refunds (except the towns of Stamford and Middletown) utilizing applicable approved pre-tax cost of capital rates. The final decision also provided for a five-year period for those towns that wish to phase in the purchase of their streetlights in which they can complete the asset purchase. As a result of this decision, CL&P recorded an additional $7.4 million pre-tax reserve for streetlight billing in the second quarter of 2005 and subsequently reduced the reserve by $3.3 million after submitting its compliance calculations and receiving approval from the DPUC. The net impact in 2005 was an additional $4.1 million of pre-tax reserve. CL&P filed an appeal of this decision on August 11, 2005 in the Connecticut Superior Court. The court has not yet set a schedule for the appeal.

Procurement Fee Rate Proceedings: CL&P is currently allowed to collect a fixed procurement fee of 0.50 mills per kilowatt-hour (kWh) from customers who purchase TSO service through 2006. One mill is equal to one-tenth of a cent. That fee can increase to 0.75 mills per kWh if CL&P outperforms certain regional benchmarks. The fixed portion of the procurement fee amounted to approximately $12 million (approximately $7 million after-tax) for 2004. CL&P submitted to the DPUC its proposed methodology to calculate the variable portion

(incentive portion) of the procurement fee. CL&P requested approval of $5.8 million for its 2004 incentive payment. On December 8, 2005, a draft decision was issued in this docket, which accepted the methodology proposed by CL&P and authorized payment of the $5.8 million incentive fee. The DPUC has not set a date for issuing a final decision.

Retail Transmission Rate Filing: As a result of the legislation described above, CL&P filed for a transmission adjustment clause on August 1, 2005 with the rate tracking mechanism effective on July 1, 2005. The DPUC approved the mechanism on December 20, 2005. On January 1, 2006, consistent with that approval, CL&P raised its retail transmission rate to collect $21 million of additional revenues over the first six months of 2006.

CTA and SBC Reconciliation: The CTA allows CL&P to recover stranded costs, such as securitization costs associated with the rate reduction bonds, amortization of regulatory assets, and IPP over market costs, while the SBC allows CL&P to recover certain regulatory and energy public policy costs, such as public education outreach costs, hardship protection costs, transition period property taxes, and displaced worker protection costs.

A final decision in the 2004 CTA and SBC docket was issued on December 19, 2005 by the DPUC. That decision ordered a refund to customers of $100.8 million over the twelve-month period beginning with January 2006 consumption. In a subsequent decision in CL&P’s docket to establish the 2006 TSO rates dated December 28, 2005, the DPUC ordered CL&P to issue a revised CTA refund of $108 million over the twelve-month period beginning with January 2006 consumption and an additional CTA refund of $40 million for the months of January, February and March of 2006.

In the 2001 CTA and SBC reconciliation filing, and subsequently in a September 10, 2002 petition to reopen related proceedings, CL&P requested that a deferred intercompany tax liability associated with the intercompany sale of generation assets be excluded from the calculation of CTA revenue requirements. This liability is currently included as a reduction in the calculation of CTA revenue requirements. On September 10, 2003, the DPUC issued a final decision denying CL&P’s request, and on October 24, 2003, CL&P appealed the DPUC’s final decision to the Connecticut Superior Court. The appeal has been fully briefed and argued. If CL&P’s request is granted and upheld through these court proceedings, there would be additional amounts due to CL&P from its customers. The amount due is contingent upon the findings of the court. However, management believes that CL&P’s pre-tax earnings would increase by a minimum of $15 million in 2006 if CL&P’s position is adopted by the court.

CL&P TSO Rates: Most of CL&P’s customers buy their energy at CL&P’s TSO rate, rather than buying energy directly from competitive suppliers. CL&P secured half of its 2006 TSO requirements during bidding in 2003 and 2004. Bids to supply CL&P with its remaining 50 percent 2006 TSO requirements were received on November 15, 2005. On December 29, 2005, the DPUC approved CL&P’s TSO rates for 2006. As a result of significantly higher supplier bids for 2006, CL&P increased TSO rates by 17.5 percent on January 1, 2006 and will increase rates another 4.9 percent on April 1, 2006, representing a total increase of $676.5 million on an annualized basis.

On December 22, 2004, the DPUC approved an increase of 16.2 percent in TSO rates effective January 1, 2005, although the impact was partially offset by a continuation of the CTA refund. The DPUC also ordered that projected 2004 and 2005 CTA overrecoveries and half of projected 2004 distribution overrecoveries be used to moderate increases for customers that otherwise would occur when the current CTA refund expired on May 1, 2005. Overall, the final decision approved an increase to the January 2004 TSO rates of approximately 10.4 percent, including the effects of existing and new refunds and overrecoveries. The DPUC denied requests by the Connecticut Attorney General and Office of Consumer Counsel (OCC) to defer the recovery of higher supplier costs into future years. On February 3, 2005, the OCC filed an appeal with the Connecticut Superior Court challenging this decision, which was dismissed by the court on October 20, 2005.

Also, pursuant to state law, on December 19, 2003, the DPUC set CL&P’s TSO rates for January 1, 2004 through December 31, 2004 and confirmed that state law exempted FMCC charges, Energy Adjustment Clause (EAC) charges and certain other charges from the statutorily imposed rate cap. The OCC filed appeals of this decision with the Connecticut Superior Court. The OCC claimed that the decision improperly implements an EAC charge under Connecticut law, fails to properly define and identify the fees that CL&P will be allowed to collect from customers and improperly calculates base rates for purposes of determining the rate cap.

On May 16, 2005, the DPUC approved a 4.8 percent increase to customer rates related to $79.8 million of additional RMR contract costs, which have been approved by the FERC. This additional amount was recovered over the period June through December of 2005 through an increase to the FMCC rates effective June 1, 2005. On August 24, 2005, the DPUC issued a final decision supporting the interim rate increase approved in May of 2005. On February 1, 2006, CL&P filed with the DPUC its annual FMCC reconciliation filing for the year ended 2005. No change in the current rates was proposed. The DPUC has not set a schedule for review of this filing.

Application for Issuance of Long-Term Debt: On January 26, 2005, the DPUC approved CL&P’s request to issue $600 million in long-term debt through December 31, 2007. Additionally, the final decision approved CL&P’s request to enter into hedging transactions in connection with any prospective or outstanding long-term debt in order to reduce the interest rate risk associated with the debt or debt issuances. On April 7, 2005, CL&P closed on the sale of $200 million of first mortgage bonds with maturities ranging from 10 years to 30 years. Proceeds were used to repay short-term borrowings.

Distribution Rates: In its December 2003 rate case decision, the DPUC allowed CL&P to increase distribution rates annually from 2004 through 2007. A $25 million distribution rate increase effective January 1, 2005, combined with strong hot weather driven third quarter sales, offset by after-tax employee termination and benefit plan curtailment charges totaling $8.5 million, resulted in CL&P earning a cost of capital ROE of 7.51 percent on its average distribution equity in 2005, compared with an allowed ROE of 9.85 percent. An additional $11.9 million distribution rate increase took effect on January 1, 2006 and another $7 million distribution rate increase is due to take effect on January 1, 2007. While these

increases will help CL&P’s performance, they may be inadequate to offset a possible combination of lower retail sales, higher employee-related expenses and higher costs related to the distribution capital investment program.

Connecticut – Yankee Gas:

Purchased Gas Adjustment: On September 9, 2005 the DPUC issued a draft decision regarding Yankee Gas PGA clause charges for the period of September 1, 2003 through August 31, 2004. The draft decision disallowed approximately $9 million in previously recovered PGA revenues associated with two separate Yankee Gas unbilled sales and revenue adjustments. At the request of Yankee Gas, the DPUC reopened the PGA hearings on September 20, 2005 and requested that Yankee Gas file supplemental information regarding the two adjustments. Yankee Gas complied with this request. The remaining schedule for the proceeding has not yet been established. If upheld, this disallowance would result in a $9 million pre-tax write-off. Management believes the unbilled sales and revenue adjustments and resultant charges to customers through the PGA clause were appropriate. Based on the facts of the case and the supplemental information provided to the DPUC, management believes the appropriateness of the PGA charges to customers for the time period under review will be approved.

Yankee Gas Rate Relief: As a result of a settlement agreement reached with various parties in 2004 and approved by the DPUC, Yankee Gas instituted a $14 million increase in base rates on January 1, 2005. That rate increase improved Yankee Gas’ cost of capital ROE from 7.8 percent in 2004 to 8.42 percent in 2005 compared with an allowed ROE of 9.9 percent. On December 23, 2005, the DPUC denied Yankee Gas’ request for interim rate relief on the grounds that the prerequisite circumstances of the settlement agreement had not been met. As prescribed in the settlement agreement, management expects to file a rate case in late 2006 that would be effective the earlier of July 1, 2007 or the date the Waterbury LNG facility enters service. Management expects Yankee Gas to earn below its allowed ROE until the next rate case goes into effect. Management has also begun to take steps to reduce Yankee Gas’ nonfuel operation and maintenance costs by combining certain operations of Yankee Gas and CL&P.

New Hampshire:

ES Rates: In accordance with the "Agreement to Settle PSNH Restructuring" and state law, PSNH files for updated Transition Energy Service Rate and Default Energy Service Rate, collectively referred to as Energy Service Rate (ES), periodically to ensure timely recovery of its costs. The ES rate recovers PSNH’s generation and purchased power costs, including a return on PSNH’s generation assets. PSNH defers for future recovery or refund any difference between its ES revenues and the actual costs incurred.

On January 28, 2005, the NHPUC issued an order approving an ES rate of $0.0649 per kWh for the period February 1, 2005 through January 31, 2006 which included an 11 percent ROE on PSNH’s generation assets. This generation ROE was the subject of a second set of proceedings. On June 8, 2005, the NHPUC issued an order requiring PSNH to use a generation ROE of 9.63 percent, effective July 1, 2005. On July 7, 2005, PSNH filed a motion for reconsideration in the ROE portion of above docket. On December 2, 2005 the NHPUC issued a revised decision, lowering PSNH’s allowed ROE to 9.62 percent that was retroactive to an effective date of August 1, 2005. On January 3, 2006, PSNH appealed the revised decision to the New Hampshire Supreme Court and simultaneously asked the NHPUC for reconsideration of its decision. The appeal before the New Hampshire Supreme Court is pending. On February 10, 2006, PSNH’s most recent request for reconsideration by the NHPUC was denied. This decrease in allowed ROE will lower PSNH’s net income by approximately $1.5 million annually based on the current level of generation asset investment.

On July 1, 2005, PSNH filed a petition with the NHPUC requesting an increase in the ES rate from the then current $0.0649 per kWh to $0.0734 per kWh based on actual costs and underrecoveries incurred through June 30, 2005 and updated cost projections. The updated cost projections included an increase in costs as a direct result of higher fuel and purchased power costs that PSNH expected to incur. The generation ROE used in the updated cost projections was based upon the 9.63 percent ROE ordered on June 8, 2005. An order changing the ES rate to $0.0724 per kWh, effective August 1, 2005, was issued by the NHPUC on August 1, 2005.

On September 30, 2005, PSNH filed a petition with the NHPUC requesting a change in ES rates for the period February 1, 2006 through January 31, 2007. On December 14, 2005, PSNH and other parties, including the NHPUC staff and the OCA, filed a stipulation and settlement agreement related to the September 30, 2005 filing. A provision of the settlement agreement included an allowance to implement deferred accounting treatment for asset retirement obligations (AROs) that PSNH will be required to recognize under generally accepted accounting principles, including the future amortization of these ARO deferrals.

On December 19, 2005, PSNH filed updated ES cost information and requested approval of an ES rate of $0.0913 per kWh for the 11-month period from February 1, 2006 through December 31, 2006. Hearings regarding the settlement agreement and the updated ES rate were held on December 21, 2005 and the NHPUC issued an order on January 20, 2006 approving the settlement agreement, as filed, and the ES rate of $0.0913 per kWh for the 11-month period.

SCRC Reconciliation Filing: The SCRC allows PSNH to recover its stranded costs. On an annual basis, PSNH files with the NHPUC a SCRC reconciliation filing for the preceding calendar year. This filing includes the reconciliation of stranded cost revenues and costs and ES revenues and costs. The NHPUC reviews the filing, including a prudence review of the operations within PSNH’s generation business segment. The cumulative deferral of SCRC revenues in excess of costs was $303.3 million at December 31, 2005. This cumulative deferral will decrease the amount of non-securitized stranded costs to be recovered from PSNH’s customers in the future from $368 million to $64.7 million.

The 2004 SCRC reconciliation filing was filed with the NHPUC on May 2, 2005. In October of 2005, PSNH, the NHPUC staff and the OCA reached a settlement agreement in this case. The major provisions of this settlement agreement include the following: 1) PSNH will be allowed to recover its 2004 ES costs and stranded costs without disallowances, 2) PSNH will be allowed to include its cumulative unbilled revenues in its ES and stranded cost reconciliations and 3) the NHPUC will defer any action regarding PSNH’s coal supply and transportation procedures until it completes a review using an outside expert. The NHPUC issued its order on December 22, 2005, approving the settlement agreement

as filed. While management believes its coal procurement and transportation policies and procedures are prudent and consistent with industry practice, it is unable to determine the impact, if any, of the expected NHPUC review on PSNH’s net income or financial position.

Litigation with Independent Power Producers (IPPs): Two wood-fired IPPs that sell their output to PSNH under long-term rate orders issued by the NHPUC brought suit against PSNH in state superior court. The IPPs and PSNH dispute the end dates of the above-market long-term rates set forth in the respective rate orders. Subsequent to the IPP’s court filing, PSNH petitioned the NHPUC to decide this matter, and requested that the court stay its proceeding pending the NHPUC’s decision. By court order dated October 20, 2005, the court granted PSNH’s motion to stay indicating that the NHPUC had primary jurisdiction over this matter.

On November 11, 2005, the IPPs filed motions with the NHPUC seeking to disqualify two of the three NHPUC commissioners from participating in this proceeding. As a result, the NHPUC chair excused himself from participating in this proceeding. On December 7, 2005, the IPPs then filed an interlocutory appeal with the New Hampshire Supreme Court (Supreme Court) on the basis that the forum for resolving this dispute is in state superior court. On December 27, 2005, PSNH and the New Hampshire Attorney General’s Office (representing the NHPUC) each filed motions for summary disposition with the Supreme Court. On February 7, 2006, the Supreme Court declined to accept the IPP’s interlocutory appeal. As a result, the matter will return to the NHPUC for decision. PSNH recovers the over market costs of IPP contracts through the SCRC.

Massachusetts:

Transition Cost Reconciliation: On March 31, 2005, WMECO filed its 2004 transition cost reconciliation with the DTE. The DTE has combined the 2003 transition cost reconciliation filing, standard offer service and default service reconciliation, the transmission cost adjustment filing, and the 2004 transition cost reconciliation filing into a single proceeding. The timing of a decision in the combined proceeding is uncertain, but management does not expect the outcome to have a material adverse impact on WMECO’s net income or financial position.

Distribution Rate Case Settlement Agreement: On December 29, 2004, the DTE approved a rate case settlement agreement submitted by WMECO, the Massachusetts Attorney General’s Office, the Associated Industries of Massachusetts, and the Low-Income Energy Affordability Network. The settlement agreement provides for a $6 million increase in WMECO’s distribution rate effective on January 1, 2005 and an additional $3 million increase in WMECO’s distribution rate effective on January 1, 2006 and for a decrease in WMECO’s transition charge by approximately $13 million annually. The lower transition charge will delay recovery of transition costs and will reduce WMECO’s cash flows but not its earnings as part of the rate case settlement agreement. WMECO agreed not to file for a distribution rate increase to be effective prior to January 1, 2007.

Annual Rate Change Filing: On December 1, 2005, WMECO made its 2006 annual rate change filing implementing the $3 million distribution revenue increase allowed under its rate case settlement agreement. WMECO requested that this change become effective on January 1, 2006. On December 29, 2005, the DTE approved rates reflecting the $3 million distribution revenue increase as well as increases for new basic service supply.

Basic Service: WMECO owns no generation and seeks bids at regular intervals to provide full requirements service for its customers who do not contract directly with competitive retail suppliers for their energy. As a result of higher energy prices, the prices for 2006 are significantly higher than 2005.

Deferred Contractual Obligations

FERC Proceedings: In 2003, the Connecticut Yankee Atomic Power Company (CYAPC) increased the estimated decommissioning and plant closure costs for the period 2000 through 2023 by approximately $395 million over the April 2000 estimate of $436 million approved by the FERC in a 2000 rate case settlement. The revised estimate reflects the increases in the projected costs of spent fuel storage, increased security and liability and property insurance costs, and the fact that CYAPC is now self performing all work to complete the decommissioning of the plant due to the termination of the decommissioning contract with Bechtel Power Corporation (Bechtel) in July of 2003. NU’s share of CYAPC’s increase in decommissioning and plant closure costs is approximately $194 million. On July 1, 2004, CYAPC filed with the FERC for recovery seeking to increase its annual decommissioning collections from $16.7 million to $93 million for a six-year period beginning on January 1, 2005. On August 30, 2004, the FERC issued an order accepting the rates, with collection beginning on February 1, 2005, subject to refund.

Both the DPUC and Bechtel filed testimony in the FERC proceeding claiming that CYAPC was imprudent in its management of the decommissioning project. In its testimony, the DPUC recommended a disallowance of $225 million to $234 million out of CYAPC’s requested rate increase of approximately $395 million. NU’s share of the DPUC’s recommended disallowance would be between $110 million to $115 million. The FERC staff also filed testimony that recommended a $38 million decrease in the requested rate increase claiming that CYAPC should have used a different gross domestic product (GDP) escalator. NU’s share of this recommended decrease is $18.6 million.

On November 22, 2005, a FERC administrative law judge issued an initial decision finding no imprudence on CYAPC’s part. However, the administrative law judge did agree with the FERC staff’s position that a lower GDP escalator should be used for calculating the rate increase and found that CYAPC should recalculate its decommissioning charges to reflect the lower escalator. Briefs to the full FERC addressing these issues were filed in January and February of 2006, and a final order is expected later in 2006. Management expects that if the FERC staff’s position on the decommissioning GDP cost escalator is found by the FERC to be more appropriate than that used by CYAPC to develop its proposed rates, then CYAPC would review whether to reduce its estimated decommissioning obligation and reduce the customers’ obligation, including CL&P, PSNH and WMECO.

customers of CL&P, PSNH and WMECO. However, there is a risk that some portion of these increased costs may not be recovered, or will have to be refunded if recovered, as a result of the FERC proceedings.

On June 10, 2004, the DPUC and the Connecticut OCC filed a petition seeking a declaratory order that CYAPC be allowed to recover all decommissioning costs from its wholesale purchasers, including CL&P, PSNH and WMECO, but that such purchasers may not be allowed to recover in their retail rates any costs that the FERC might determine to have been imprudently incurred. On August 30, 2004, the FERC denied this petition. On September 29, 2004, the DPUC and OCC asked the FERC to reconsider the petition and on October 20, 2005, the FERC denied the reconsideration, holding that the sponsor companies are only obligated to pay CYAPC for prudently incurred decommissioning costs and the FERC has no jurisdiction over the sponsors’ rates to their retail customers. On December 12, 2005, the DPUC sought review of these orders by the United States Court of Appeals for the D.C. Circuit. The FERC and CYAPC have asked the court to dismiss the case and the DPUC has objected to a dismissal. NU cannot predict the timing or the outcome of these proceedings.

Bechtel Litigation: CYAPC and Bechtel commenced litigation in Connecticut Superior Court over CYAPC’s termination of Bechtel’s contract for the decommissioning of CYAPC’s nuclear generating plant. After CYAPC terminated the contract, responsibility for decommissioning was transitioned to CYAPC, which recommenced the decommissioning process.

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

Spent Nuclear Fuel Litigation: CYAPC, the Yankee Atomic Electric Company (YAEC) and Maine Yankee Atomic Power Company (MYAPC) (Yankee Companies) also commenced litigation in 1998 charging that the federal government breached contracts it entered into with each company in 1983 under the Act. Under the Act, the DOE was to begin removing spent nuclear fuel from the nuclear plants of the Yankee Companies no later than January 31, 1998 in return for payments by each company into the nuclear waste fund. No fuel has been collected by the DOE, and spent nuclear fuel is stored on the sites of the Yankee Companies’ plants. The Yankee Companies collected the funds for payments into the nuclear waste fund from wholesale utility customers under FERC-approved contract rates. The wholesale utility customers in turn collect these payments from their retail electric customers. The Yankee Companies’ individual damage claims attributed to the government’s breach ranging between $523 million and $543 million are specific to each plant and include incremental storage, security, construction and other costs through 2010. The CYAPC damage claim ranges from $186 million to $198 million, the YAEC damage claim ranges from $177 million to $185 million and the MYAPC damage claim is $160 million. The DOE trial ended on August 31, 2004 and a verdict has not been reached. Post-trial findings of facts and final briefs were filed by the parties in January of 2005. The Yankee Companies’ current rates do not include an amount for recovery of damages in this matter. Management can predict neither the outcome of this matter nor its ultimate impact on NU.

YAEC: In November of 2005, YAEC established an updated estimate of the cost of completing the decommissioning of its plant resulting in an increase of approximately $85 million. NU’s share of the increase in estimated costs is $32.7 million. This estimate reflects the cost of completing site closure activities from October of 2005 forward and storing spent nuclear fuel and other high level waste on site until 2020. This estimate projects a total cost of $192.1 million for the completion of decommissioning and long-term fuel storage. To fund these costs, on November 23, 2005, YAEC submitted an application to the FERC to increase YAEC’s wholesale decommissioning charges. The DPUC and the Massachusetts attorney general protested these increases. On January 31, 2006, the FERC issued an order accepting the rate increase, effective February 1, 2006, subject to refund after hearings and settlement judge proceedings. The hearings have been suspended pending settlement discussions between YAEC, the FERC and other intervenors in the case. NU has a 38.5 percent ownership interest in YAEC and can predict neither the outcome of this matter nor its ultimate impact on NU.

NU Enterprises

NU Enterprises currently has two business segments: the merchant energy business segment and the energy services and other business segment. NU has decided to exit all aspects of both segments.

Merchant Energy Segment: The merchant energy business segment includes Select Energy’s retail marketing business, 1,442 MW of generation assets, including 1,296 MW of primarily pumped storage and hydroelectric generation assets at NGC and 146 MW of coal-fired generation assets at HWP (Mt. Tom), and NGS.

The merchant energy segment also continues to include the wholesale marketing business, which NU Enterprises is exiting. Prior to the March 2005 decision to exit the wholesale marketing business, this business was comprised primarily of full requirements sales to LDCs and bilateral sales to other load-serving counterparties. These sales were sourced by the generation assets and an inventory of energy contracts.

Energy Services and Other Segment: In March of 2005, NU Enterprises also announced that it would explore ways to exit the energy services businesses in a manner that maximizes their value. These businesses include or have included the operations of SESI, Boulos, Woods Electrical and SECI. SECI-NH, including Reeds Ferry, and Woods Network were sold in November of 2005. In January of 2006, the Massachusetts service location of SECI-CT was sold for approximately $2 million.

Outlook: NU is not providing 2006 earnings guidance for NU Enterprises due to many factors, including:

The application of mark-to-market accounting to certain energy contracts until those contracts are settled or until the commodities are delivered. The value of these contracts has fluctuated and will continue to fluctuate with changes in electricity and capacity values and with gas prices that are used to value the long-term portions of the contracts. These changes in value have been reflected in earnings and have been significant. These changes could continue to be significant.

Proceeds and the related gain or loss on the sale of competitive generation assets should the sale of NU Enterprises generation assets occur in 2006.

The recognition of additional mark-to-market gains or losses on wholesale marketing contracts that have not been recorded yet. Serving full requirements contracts could result in quantities of electricity to be delivered in amounts different from the notional amounts that were multiplied by current market prices to determine the mark-to-market gains or losses. Differences have impacted and are reasonably likely to continue to impact NU Enterprises’ earnings. In addition, gains or losses may be recorded on the disposition of these wholesale contracts.

Additional asset impairments or losses on disposals associated with the wholesale and retail marketing, competitive generation and energy service businesses. As these businesses are exited, there could be additional impairments or gains or losses on the disposals to the extent sales are consummated.

NU guarantees the performance of certain services companies. The fair value of those guarantees may be recognized if they become guarantees to third parties.

The recognition of additional restructuring costs. Costs associated with certain restructuring activities and employee costs are expected to be recognized in future periods as incurred.

Intercompany Transactions: There were no CL&P TSO purchases from Select Energy in 2005, compared to $502 million of CL&P standard offer purchases in 2004. Other energy purchases between CL&P and Select Energy totaled $53.4 million in 2005 compared to $109.3 million in 2004. WMECO purchases from Select Energy totaled $36.3 million and $108.5 million for the year ended December 31, 2005 and 2004, respectively. In February of 2005, WMECO entered into a contract with Select Energy under which Select Energy provided default service from April through June of 2005.

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

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

Wholesale Marketing Activities: As a result of NU’s decision to exit the wholesale marketing business, certain wholesale energy contracts previously accounted for under accrual accounting were required to be marked-to-market beginning in the first quarter of 2005. Existing energy trading contracts have been and will continue to be marked-to-market with changes in fair value reflected in earnings.

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


(Millions of Dollars)
Current wholesale derivative assets	$ 256.6
Long-term wholesale derivative assets	103.5
Current wholesale derivative liabilities	(369.3)
Long-term wholesale derivative liabilities	(220.9)
Portfolio position	$(230.1)

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

Select Energy has policies and procedures requiring all wholesale positions to be marked-to-market at the end of each business day and segregating responsibilities between the individuals actually transacting (front office) and those confirming the trades (middle office). The determination of the portfolio’s fair value is the responsibility of the middle office independent from the front office.

The methods used to determine the fair value of wholesale energy contracts are identified and segregated in the table of fair value of contracts at December 31, 2005. A description of each method is as follows: 1) prices actively quoted primarily represent New York Mercantile Exchange (NYMEX) futures, swaps and options that are marked to closing exchange prices; and 2) prices provided by external sources primarily include over-the-counter forwards and options, including bilateral contracts for the purchase or sale of electricity or natural gas, and are marked to the mid-point of bid and ask market prices. The mid-points of market prices are adjusted to include all applicable market information, such as prior contract settlements with third parties. Currently, Select Energy has a contract for which a portion of the contract’s fair value is determined based on a model or other valuation method. The model utilizes natural gas prices and a conversion factor to electricity. Broker quotes for electricity at locations for which Select Energy has entered into transactions are generally available through the year 2009. For all natural gas positions, broker quotes extend through 2013.

Generally, valuations of short-term contracts derived from quotes or other external sources are more reliable should there be a need to liquidate the contracts, while valuations for longer-term contracts are less certain. Accordingly, there is a risk that contracts will not be realized at the amounts recorded.

As of and for the years ended December 31, 2005 and 2004, the sources of the fair value of wholesale contracts and the changes in fair value of these contracts are included in the following tables:


(Millions of Dollars)	Fair Value of Wholesale Contracts at December 31, 2005
Sources of Fair Value	Maturity Less than One Year	Maturity of One to Four Years	Maturity in Excess of Four Years	Total Fair Value
Prices actively quoted	$ 31.3	$ 19.1	$ -	$ 50.4
Prices provided by external sources	(147.5)	(94.7)	(2.8)	(245.0)
Models based	0.7	(10.3)	(25.9)	(35.5)
Totals	$(115.5)	$(85.9)	$(28.7)	$(230.1)


(Millions of Dollars)	Fair Value of Wholesale Contracts at December 31, 2004
Sources of Fair Value	Maturity Less than One Year	Maturity of One to Four Years	Maturity in Excess of Four Years	Total Fair Value
Prices actively quoted	$(58.9)	$(7.3)	$ -	$(66.2)
Prices provided by external sources	(6.5)	11.3	12.5	17.3
Totals	$(65.4)	$ 4.0	$12.5	$(48.9)


	Years Ended December 31,
	2005	2004
(Millions of Dollars)	Total Portfolio Fair Value
Fair value of wholesale contracts outstanding at the beginning of the year	$ (48.9)	$ 33.4
Contracts realized or otherwise settled during the year	254.2	(3.5)
Changes in fair value recorded:
Wholesale contract market changes, net	(419.0)	-
Fuel, purchased and net interchange power	(43.7)	(86.3)
Operating revenues	13.1	2.0
Changes in model based assumption included in operating revenues	14.2	5.5
Fair value of wholesale contracts outstanding at the end of the year	$(230.1)	$(48.9)

Changes in the fair value of wholesale contracts that became marked-to-market as a result of the exit decisions totaling a negative $419 million in 2005 are recorded as wholesale contract market changes, net, changes in fair value of natural gas contracts totaling a negative $43.7 million in 2005 are recorded as fuel, purchased and net interchange power and changes in fair value of contracts formerly designated as trading totaling a positive $13.1 million in 2005 are recorded as revenue on the accompanying consolidated statements of (loss)/income.

During the fourth quarter of 2005, Select Energy assigned a wholesale contract for $55.9 million with payments commencing in January of2006 and ending in December of 2008. This amount is included in the contracts realized or otherwise settled during the year amount of $254.2 million above. At December 31, 2005, this contractual assignment was reclassified from short and long-term derivative liabilities to other current liabilities ($18.5 million) and other long-term liabilities ($37.4 million) on the consolidated balance sheets. This amount is included in the $419 million of wholesale contract market changes, net in the table above. The payments under this assignment bear interest at 12.5 percent. If certain conditions are met, these payments could be accelerated.

In the first quarter of 2005, the mark-to-market of Select Energy’s wholesale contracts increased by $14.2 million as a result of the removal of a modeling reserve for one of its trading contracts. The change in fair value associated with this removal is included in the changes in model based assumption included in operating revenues category in the table above. This contract was subsequently sold to a third-party wholesale marketer in the third quarter of 2005.

Retail Marketing Activities: Select Energy manages its portfolio of retail marketing contracts to maximize value while operating within NU’s corporate risk tolerance. Select Energy generally acquires retail customers in small increments, which while requiring careful sourcing, allows energy purchases to be acquired in small increments. However, fluctuations in prices, fuel costs, competitive conditions, regulations, weather, transmission costs, lack of market liquidity, plant outages and other factors can all impact the retail marketing business adversely from time to time.

In 2005, the retail marketing business was the successful bidder on more than 30 percent of its bids, from a revenue standpoint, compared with just under 25 percent in 2004.

For the year ended December 31, 2005, approximately 11 million MWhs were delivered as compared to approximately 10 million MWhs in 2004. For natural gas, approximately 46 billion cubic feet were delivered in 2005 as compared to approximately 39.5 billion cubic feet in 2004.

Retail margins ranged from approximately $1.60 to $2.00 per MWh in 2005. For natural gas, sales margins averaged between approximately $0.20 and $0.25 per thousand cubic feet in 2005.

The retail marketing business periodically enters into supply contracts that do not immediately meet the criteria for the normal election and accrual accounting and therefore, changes in fair value are required to be marked-to-market and included in earnings. At December 31, 2005, Select Energy had retail derivative assets and liabilities as follows:


(Millions of Dollars)
Current retail derivative assets	$35.3
Long-term retail derivative assets	-
Current retail derivative liabilities	(18.3)
Long-term retail derivative liabilities	-
Portfolio position	$17.0

The methods used to determine the fair value of retail energy sourcing contracts are identified and segregated in the table of fair value of contracts at December 31, 2005. A description of each method is as follows: 1) prices actively quoted primarily represent exchange traded futures and swaps that are marked to closing exchange prices; and 2) prices provided by external sources primarily include over-the-counter forwards, including bilateral contracts for the purchase or sale of electricity or natural gas, and are marked to the mid-point of bid and ask market prices.

As of and for the year ended December 31, 2005, the sources of the fair value of retail energy sourcing contracts and the changes in fair value of these contracts are included in the following tables:


(Millions of Dollars)	Fair Value of Retail Sourcing Contracts at December 31, 2005
Sources of Fair Value	Maturity Less Than One Year	Maturity of One to Four Years	Maturity in Excess of Four Years	Total Fair Value
Prices actively quoted	$(8.8)	$ -	$ -	$(8.8)
Prices provided by external sources	25.8	-	-	25.8
Totals	$17.0	$ -	$ -	$17.0


		Year Ended December 31, 2005
		Total Portfolio Fair Value
Fair value of retail sourcing contracts outstanding at the beginning of the year		$ -
Contracts realized or otherwise settled during the year		(25.7)
Changes in fair value recorded:
Wholesale contract market changes, net		30.0
Fuel, purchased power and net interchange power		12.7
Fair value of retail sourcing contracts outstanding at the end of the year		$ 17.0

Upon the decision to exit the wholesale marketing business in March of 2005, Select Energy identified $30 million of previously designated wholesale contracts and redesignated them to help support its retail marketing business. Subsequent changes in fair value are now recorded in fuel, purchased and net interchange power. Fuel, purchased and net interchange power increased $12.7 million primarily due to power price increases in the PJM power pool in the second half of 2005.

Competitive Generation Activities: The competitive generation assets, owned by NU Enterprises are subject to certain operational risks, including but not limited to the length of scheduled and non-scheduled outages, bidding and scheduling with various ISOs, environmental issues and fuel costs. Competitive generation activities are also subject to various federal, state and local regulations. These risks may result in changes in the anticipated gross margins which the merchant energy business realizes from its competitive generation portfolio/activities.

For the year ended December 31, 2005, NU Enterprises’ competitive generation assets continued to run well while energy prices increased and reserve margins started to tighten. NU Enterprises believes that generating unit availability will become increasingly important as the capacity market tightens in New England due to load growth and the absence of new plant construction. For the year ended December 31, 2005, the 146 MW Mt. Tom plant at HWP had a capacity factor of just over 80 percent while the 1,080 MW Northfield Mountain facility had an availability factor of nearly 95 percent. The approximately 200 MW of other hydroelectric units had an aggregate availability factor of 85 percent.

Total competitive generation was 2.6 million MWhs through December 31, 2005. HWP’s Mt. Tom station, a coal-fired unit located in Holyoke, Massachusetts, generated more than one million MWhs in 2005, while NGC’s Northfield Mountain facility and other hydroelectric units generated approximately 0.9 million MWhs and approximately 0.7 million MWhs, respectively, in 2005.

For the Northfield Mountain facility, the ratio of on-peak to off-peak spreads averaged 1.5 for 2005. As a result, NU Enterprises realized $17.5 million of energy-related gross margin in 2005.

The value of NGC’s generating assets could be affected by the adoption of FCM in place of the prior LICAP proposal. For further information, see "Utility Group Regulatory Issues and Rate Matters - LICAP," included in this management’s discussion and analysis.

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


(Millions of Dollars)
Current generation derivative assets	$ 9.2
Long-term generation derivative assets	-
Current generation derivative liabilities	(5.1)
Long-term generation derivative liabilities	(15.5)
Portfolio position	$(11.4)

The methods used to determine the fair value of generation contracts are identified and segregated in the table of fair value of contracts at December 31, 2005. A description of each method is as follows: 1) prices actively quoted primarily represent exchange traded futures and swaps that are marked to closing exchange prices; and 2) prices provided by external sources primarily include over-the-counter forwards, including bilateral contracts for the purchase or sale of electricity and are marked to the mid-point of bid and ask market prices.

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


(Millions of Dollars)	Fair Value of Generation Contracts at December 31, 2005
Sources of Fair Value	Maturity Less than One Year	Maturity of One to Four Years	Maturity in Excess of Four Years	Total Fair Value
Prices actively quoted	$(1.8)	$ -	$ -	$ (1.8)
Prices provided by external sources	5.9	(15.5)	-	(9.6)
Totals	$ 4.1	$(15.5)	$ -	$(11.4)


		Year Ended December 31, 2005
(Millions of Dollars)		Total Portfolio Fair Value
Fair value of competitive generation contracts outstanding at the beginning of the year		$ -
Contracts realized or otherwise settled during the year		(0.1)
Changes in fair value recorded:
Discontinued operations		(15.5)
Operating revenues		4.2
Fair value of competitive generation contracts outstanding at the end of the year		$ (11.4)

As a result of NU’s decision to exit the competitive generation business, certain competitive generation contracts to sell plant output in future periods previously accounted for under accrual accounting were required to be marked-to-market in the fourth quarter of 2005 and are included in discontinued operations on the accompanying consolidated statements of (loss)/income. The contracts whose changes in fair value flow through operating revenues are primarily sales contracts used to hedge competitive generation. The $4.2 million change in fair value is the result of high priced sales positions in the third quarter of 2005 combined with falling market prices during the fourth quarter of 2005.

For further information regarding Select Energy’s derivative contracts, see Note 6, "Derivative Instruments," to the consolidated financial statements.

Counterparty Credit: Counterparty credit risk relates to the risk of loss that Select Energy would incur because of non-performance by counterparties pursuant to the terms of their contractual obligations. Select Energy has established credit policies with regard to its counterparties to minimize overall credit risk. These policies require an evaluation of potential counterparties’ financial condition (including credit ratings), collateral requirements under certain circumstances (including cash advances, LOCs, and parent guarantees), and the use of standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. This evaluation results in establishing credit limits prior to Select Energy’s entering into contracts. The appropriateness of these limits is subject to continuing review. Concentrations among these counterparties may affect Select Energy’s overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes to economic, regulatory or other conditions. At December 31, 2005, approximately 72 percent of Select Energy’s counterparty credit exposure to wholesale and trading counterparties was collateralized or rated BBB- or better. Select Energy was provided $28.9 million and $57.7 million of counterparty deposits at December 31, 2005 and 2004, respectively. For further information, see Note 1Y, "Summary of Significant Accounting Policies – Counterparty Deposits," to the consolidated financial statements.

Consolidated Edison, Inc. Merger Litigation

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

In an opinion dated October 12, 2005, a panel of three judges at the Second Circuit held that the shareholders of NU had no right to sue Con Edison for its alleged breach of the parties’ Merger Agreement. NU’s request for rehearing was denied on January 3, 2006. This ruling left intact the remaining claims between NU and Con Edison for breach of contract, which include NU’s claim for recovery of costs and expenses of approximately $32 million and Con Edison’s claim for damages of "at least $314 million." NU is currently considering whether to seek review by the United States Supreme Court. At this stage, NU cannot predict the outcome of this matter or its ultimate effect on NU.

Off-Balance Sheet Arrangements

Utility Group: The CL&P Receivables Corporation (CRC) was incorporated on September 5, 1997 and is a wholly owned subsidiary of CL&P. CRC has an agreement with CL&P to purchase and has an arrangement with a highly-rated financial institution under which CRC can sell up to

$100 million of an undivided interest in accounts receivable and unbilled revenues. At December 31, 2005 and 2004, CRC had sold an undivided interest in its accounts receivable and unbilled revenues of $80 million and $90 million, respectively, to that financial institution with limited recourse.

CRC was established for the sole purpose of selling CL&P’s accounts receivable and unbilled revenues and is included in the consolidated NU financial statements. On July 6, 2005, CRC renewed its Receivables Purchase and Sale Agreement with CL&P and the financial institution through July 5, 2006. CL&P’s continuing involvement with the receivables that are sold to CRC and the financial institution is limited to the servicing of those receivables.

The transfer of receivables to the financial institution under this arrangement qualifies for sale treatment under Statement of Financial Accounting Standards (SFAS) No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities – A Replacement of SFAS No. 125." Accordingly, the $80 million and $90 million outstanding under this facility are not reflected as debt or included in the consolidated financial statements at December 31, 2005 and 2004, respectively.

This off-balance sheet arrangement is not significant to NU’s liquidity or other benefits. There are no known events, demands, commitments, trends, or uncertainties that will, or are reasonably likely to, result in the termination, or material reduction in the amount available to the company under this off-balance sheet arrangement.

NU Enterprises: During 2001, SESI created HEC/CJTS which is a special purpose entity (SPE). SESI created HEC/CJTS for the sole purpose of providing a bankruptcy remote entity for the financing of an energy center to serve the Connecticut Juvenile Training School (CJTS). The owner of CJTS, the State of Connecticut, entered into a 20-year lease with a 10-year renewal option with HEC CJTS for the energy center. Simultaneously, HEC/CJTS transferred its interest in the lease with the State of Connecticut to investors who are unaffiliated with NU in exchange for the issuance of $19.2 million of Certificates of Participation. The transfer of HEC/CJTS’ interest in the lease was accounted for as a sale under SFAS No. 140. The debt of $19.2 million created in relation to the transfer of interest and issuance of the Certificates of Participation was derecognized and is not reflected as debt or included in the consolidated financial statements. No gain or loss was recorded. HEC/CJTS does not provide any guarantees or on-going services, and there are no contingencies related to this arrangement. SESI has a separate contract with the State of Connecticut to operate and maintain the energy center. The transaction was structured in this manner to obtain tax-exempt financing and therefore to reduce the State of Connecticut’s lease payments. This off-balance sheet arrangement is not significant to NU’s liquidity, capital resources or other benefits.

SESI entered into a master purchase agreement with an unaffiliated third party on April 30, 2002 under which SESI may sell certain receivables that are due or become due under delivery orders issued pursuant to federal energy savings performance contracts. At December 31, 2005, SESI had sold $38.6 million of receivables related to the installation of the energy efficiency projects under this arrangement. The transfer of receivables to the unaffiliated third party under this arrangement qualified as a sale under SFAS No. 140. Accordingly, the $38.6 million sold at December 31, 2005 is not included as debt in the consolidated financial statements. Under the delivery order with the United States government, SESI is responsible for on-going maintenance and other services related to the energy efficiency project installation. SESI receives payment for those services in addition to the amounts sold under the master purchase agreement.

SESI has entered into assignment agreements to sell an additional $17.9 million of receivables. These sales will be complete upon customer acceptance of the project installations. Until construction is completed, the advances under the purchase agreement are included in long-term debt in the consolidated financial statements and the receivables are recorded under the percentage of completion method.

These off-balance sheet arrangements are not significant to NU’s liquidity or other benefits.

Since NU Enterprises is in the process of exiting SESI, NU’s consolidated statements of (loss)/income for the years ended December 31, 2005, 2004 and 2003 present the operations for SESI, including HEC/CJTS, as discontinued operations as a result of meeting the criteria requiring this presentation. For further information regarding this classification, see Note 4, "Assets Held for Sale and Discontinued Operations," to the consolidated financial statements. These off-balance sheet arrangements are expected to be assigned to the purchaser when SESI is exited.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates, assumptions and at times difficult, subjective or complex judgments. Changes in these estimates, assumptions and judgments, in and of themselves, could materially impact the financial statements of NU. Management communicates to and discusses with NU’s Audit Committee of the Board of Trustees all critical accounting policies and estimates. The following are the accounting policies and estimates that management believes are the most critical in nature.

Discontinued Operations Presentation: In order for discontinued operations treatment to be appropriate, management must conclude that there is a component of a business that is "held for sale" in accordance with the provisions of SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," and that it meets the criteria for discontinued operations. Based on the status of exiting these businesses, discontinued operations presentation is appropriate for NGC, Mt. Tom, SESI, SECI-NH, Woods Network and Woods Electrical. In the fourth quarter of 2005, NU Enterprises sold SECI-NH and Woods Network to unaffiliated buyers for approximately $6.5 million. In January of 2006, the Massachusetts service location of SECI-CT was sold for approximately $2 million.

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

Impairment of Long-Lived Assets: The company evaluates long-lived assets such as property, plant and equipment to determine if these assets are impaired when events or changes in circumstances occur such as the 2005 announced decisions to exit all of the NU Enterprises businesses.

When the company believes one of these events has occurred, the determination needs to be made if a long-lived asset should be classified as an asset to be held and used or if that asset should be classified as held for sale. For assets classified as held and used, the company estimates the undiscounted future cash flows associated with the long-lived asset or asset group and an impairment loss is recognized if the carrying amount of an asset is not recoverable and exceeds its fair value. The carrying amount is not recoverable if it exceeds the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset. For assets held for sale, a long-lived asset or disposal group is measured at the lower of its carrying amount or fair value less cost to sell.

In order to estimate an asset’s future cash flows, the company considers historical cash flows, changes in the market and other factors that may affect future cash flows. The company considers various relevant factors, including the method and timing of recovery, forward price curves for energy, fuel costs, and operating costs. Actual future market prices, costs and cash flows could vary significantly from those assumed in the estimates, and the impact of such variations could be material.

In 2005, management evaluated the wholesale and retail marketing businesses and competitive generation long-lived assets and determined that these assets should continue to be classified as assets to be held and used. As assets to be held and used, they are required to be tested for impairment because of the expectation that the long-lived assets in these groups will be disposed of significantly before the end of their previously estimated useful lives. As a result of impairment analyses performed, assets totaling $8 million were determined to be impaired and were written off. At December 31, 2005, NU determined that no impairment existed for the competitive generation business generation assets based on NU’s evaluation of their fair value using discounted cash flows and an analysis of reference transactions.

In 2005, management also evaluated the energy services businesses and determined that the assets of SESI, Woods Electrical, SECI-NH, and Woods Network should be classified as assets held for sale. As a result of impairment analyses performed, the company impaired certain fixed assets by $0.8 million.

The assets and liabilities of the wholesale and retail marketing and competitive generation businesses, along with the remaining two energy services businesses, SECI-CT and Boulos, are being accounted for as assets to be held and used. A change in classification from assets to be held and used to assets held for sale may result in additional asset impairments and write-offs.

For further information regarding these impairment charges and assets held for sale, see Note 3, "Restructuring and Impairment Charges," and Note 4, "Assets Held for Sale and Discontinued Operations," to the consolidated financial statements.

Goodwill and Intangible Assets: SFAS No. 142, "Goodwill and Other Intangible Assets," requires that goodwill balances be reviewed for impairment at least annually by applying a fair value-based test. NU selected October 1st as the annual goodwill impairment testing date. Goodwill impairment is deemed to exist if the net book value of a reporting unit exceeds its estimated fair value and if the implied fair value of goodwill based on the estimated fair value of the reporting unit is less than the carrying amount of the goodwill. If goodwill is deemed to be impaired it is written-off to the extent it is impaired. The impact of this goodwill impairment review would be limited to Yankee Gas. During 2005, the goodwill and intangible asset balances previously recorded by NU Enterprises totaling $50.7 million were written off.

NU has completed its impairment analysis as of October 1, 2005 for Yankee Gas and has determined that no impairment exists. In performing the required impairment evaluation, NU estimated the fair value of the Yankee Gas reporting unit and compared it to the carrying amount of the reporting unit, including goodwill. NU estimated the fair value of Yankee Gas using discounted cash flow methodologies and an analysis of comparable companies or transactions. The discounted cash flow analysis requires the input of several critical assumptions, including future growth rates, operating cost escalation rates, allowed ROE, a risk-adjusted discount rate, and long-term earnings multiples of comparable companies. These assumptions are critical to the estimate and can change from period to period.

Modifications to these assumptions in future periods, particularly changes in discount rates, could result in future impairments of goodwill. Actual financial performance and market conditions in upcoming periods could also impact future impairment analyses.

For further information, see Note 8, "Goodwill and Other Intangible Assets," to the consolidated financial statements.

Revenue Recognition: Utility Group retail revenues are based on rates approved by the state regulatory commissions. These regulated rates are applied to customers’ use of energy to calculate a bill. In general, rates can only be changed through formal proceedings with the state regulatory commissions.

The determination of the energy sales to individual customers is based on the reading of meters, which occurs on a systematic basis throughout the month. Billed revenues are based on these meter readings. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and an estimated amount of unbilled revenues is recorded.

Certain Utility Group companies utilize regulatory commission-approved tracking mechanisms to track the recovery of certain incurred costs. The tracking mechanisms allow for rates to be changed periodically, with overcollections refunded to customers or undercollections collected from customers in future periods.

Wholesale transmission revenues are based on rates and formulas that are approved by the FERC. Most of NU’s wholesale transmission revenues are collected through a combination of the RNS tariff and NU’s LNS tariff. The RNS tariff, which is administered by ISO-NE, recovers

the revenue requirements associated with transmission facilities that are deemed by the FERC to be Pool Transmission Facilities. The LNS tariff, which was accepted by the FERC, provides for the recovery of NU’s total transmission revenue requirements, net of revenue credits received from various rate components, including revenues received under the RNS rates. At December 31, 2005, this true-up has resulted in the recognition of a $2.1 million regulatory liability, including approximately $1.5 million due to NU’s electric distribution companies.

A significant portion of the NU transmission business revenue comes from ISO-NE charges to the distribution businesses of CL&P, PSNH and WMECO. The distribution businesses recover these costs through the retail rates that are charged to their retail customers. In July of 2005, CL&P began tracking its retail transmission revenues and expenses and will adjust its retail transmission rates on a regular basis, thereby recovering all of its retail transmission expenses on a timely basis. This new tracking mechanism resulted from the enactment of the new legislation passed by the Connecticut legislature in 2005. WMECO implemented its retail transmission tracker and rate adjustment mechanism in January of 2002 as part of its 2002 rate change filing. PSNH does not currently have a retail transmission rate tracking mechanism.

NU Enterprises’ revenues are recognized at different times for its different business lines. Wholesale marketing revenues were recognized when energy was delivered up to and including the first quarter of 2005. Subsequent to March 31, 2005, as a result of going to mark-to-market accounting, these revenues were still recognized when delivered, however, they were reclassified to fuel, purchased and net interchange power. Retail marketing revenues are recognized when energy is delivered. Service revenues are recognized as services are provided, often on a percentage of completion basis.

Revenues and expenses for derivative contracts that are entered into for trading purposes are recorded on a net basis in revenues when these transactions settle. The settlement of wholesale non-trading derivative contracts for the sale of energy or gas by the Utility Group that are related to customers’ needs are recorded net in operating expenses. For further information regarding the accounting for these contracts, see Note 1F, "Summary of Significant Accounting Policies – Derivative Accounting," to the consolidated financial statements.

Utility Group Unbilled Revenues: Unbilled revenues represent an estimate of electricity or gas delivered to customers that has not yet been billed. Unbilled revenues are included in revenue on the accompanying consolidated statements of (loss)/income and are assets on the accompanying consolidated balance sheets that are reclassified to accounts receivable in the following month as customers are billed.

The estimate of unbilled revenues is sensitive to numerous factors that can significantly impact the amount of revenues recorded. Estimating the impact of these factors is complex and requires management’s judgment. The estimate of unbilled revenues is important to NU’s consolidated financial statements as adjustments to that estimate could significantly impact operating revenues and earnings.

Through December 31, 2004, the Utility Group estimated unbilled revenues monthly using the requirements method. The requirements method utilized the total monthly volume of electricity or gas delivered to the system and applied a delivery efficiency (DE) factor to reduce the total monthly volume by an estimate of delivery losses in order to calculate total estimated monthly sales to customers. The total estimated monthly sales amount less the total monthly billed sales amount resulted in a monthly estimate of unbilled sales. Unbilled revenues were estimated by first allocating sales to the respective rate classes, then applying an average rate to the estimate of unbilled sales. The estimated DE factor had a significant impact on estimated unbilled revenue amounts.

In the first quarter of 2005, management adopted a new method to estimate unbilled revenues for CL&P, PSNH, WMECO, and Yankee Gas. The new method allocates billed sales to the current calendar month based on the daily load for each billing cycle (DLC method). The billed sales are subtracted from total calendar month sales to estimate unbilled sales. The impact of adopting the new method was not material. This new method replaces the requirements method described previously.

Derivative Accounting: Certain of the contracts comprising Select Energy’s wholesale marketing and competitive generation activities are derivatives, and certain Utility Group contracts for the purchase or sale of energy or energy-related products are derivatives. Most retail marketing contracts with retail customers are not derivatives, while virtually all contracts entered into to supply these customers are derivatives. The application of derivative accounting rules is complex and requires management judgment in the following respects: election and designation of the normal purchases and sales exception, identification of derivatives and embedded derivatives, identifying hedge relationships, assessing and measuring hedge ineffectiveness, and determining the fair value of derivatives. All of these judgments, depending upon their timing and effect, can have a significant impact on NU’s consolidated net income.

The fair value of derivatives is based upon the notional amount of a contract and the underlying market price or fair value per unit. When quantities are not specified in the contract, the company estimates notional amounts using amounts referenced in default provisions and other relevant sections of the contract. The notional amount is updated during the term of the contract, and updates can have a material impact on mark-to-market amounts.

The judgment applied in the election of the normal purchases and sales exception (and resulting accrual accounting) includes the conclusions that it is probable at the inception of the contract and throughout its term that it will result in physical delivery and that the quantities will be used or sold by the business over a reasonable period in the normal course of business. If facts and circumstances change and management can no longer support this conclusion, then the normal exception and accrual accounting would be terminated and fair value accounting would be applied. Cash flow hedge contracts that are designated as hedges for contracts for which the company has elected the normal purchases and sales exception can continue to be accounted for as cash flow hedges only if the normal exception for the hedged contract continues to be appropriate. If the normal exception is terminated because delivery is no longer probable of occurring, then the hedge designation would be terminated at the same time.

contracts in fuel, purchased and net interchange power. In addition, Select Energy reported the settlement of all derivative wholesale contracts, including full requirements sales contracts, in fuel, purchased and net interchange power as a result of applying mark-to-market accounting to those contracts. Certain generation-related derivative contracts that are marked-to-market were recorded in revenues.

Prior to April 1, 2005, Select Energy reported the settlement of long-term derivative contracts, including full requirements sales contracts that physically delivered and were not held for trading purposes on a gross basis, generally with sales in revenues and purchases in expenses. Retail sales contracts are physically delivered and recorded in revenues. Short-term sales and purchases represent power and natural gas that was purchased to serve contracts but was ultimately not needed based on the actual load of the customers. This excess power and natural gas was sold to the independent system operator or to other counterparties. For the years ended December 31, 2004 and 2003, settlements of these short-term derivative contracts that are not held for trading purposes, were reported on a net basis in fuel, purchased and net interchange power.

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

Regulatory Accounting: The accounting policies of NU’s regulated utility companies historically reflect the effects of the rate-making process in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." The transmission and distribution businesses of CL&P, PSNH and WMECO, along with PSNH’s generation business and Yankee Gas’ distribution business, continue to be cost-of-service rate regulated, and management believes the application of SFAS No. 71 to those businesses continues to be appropriate. Management must reaffirm this conclusion at each balance sheet date. If, as a result of a change in circumstances, it is determined that any portion of these companies no longer meets the criteria of regulatory accounting under SFAS No. 71, that portion of the company will have to discontinue regulatory accounting and write-off the respective regulatory assets and liabilities. Such a write-off could have a material impact on NU’s, CL&P’s, PSNH’s, WMECO’s and Yankee Gas’ financial statements.

The application of SFAS No. 71 results in recording regulatory assets and liabilities. Regulatory assets represent the deferral of incurred costs that are probable of future recovery in customer rates. In some cases, NU records regulatory assets before approval for recovery has been received from the applicable regulatory commission. Management must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery. Management bases its conclusion on certain factors, including changes in the regulatory environment, recent rate orders issued by the applicable regulatory agencies and the status of any potential new legislation. Regulatory liabilities represent revenues received from customers to fund expected costs that have not yet been incurred or are probable future refunds to customers.

Management uses its best judgment when recording regulatory assets and liabilities; however, regulatory commissions can reach different conclusions about the recovery of costs, and those conclusions could have a material impact on NU’s consolidated financial statements. Management believes it is probable that the Utility Group companies will recover the regulatory assets that have been recorded.

Presentation: In accordance with current accounting pronouncements, NU’s consolidated financial statements include all subsidiaries upon which control is maintained and all variable interest entities (VIE). Determining whether the company is the primary beneficiary of a VIE is subjective and requires management’s judgment. There are certain variables taken into consideration to determine whether the company is considered the primary beneficiary of the VIE. A change in any one of these variables could require the company to reconsider whether or not it is the primary beneficiary of the VIE. All intercompany transactions between these subsidiaries are eliminated as part of the consolidation process.

NU has less than 50 percent ownership interests in CYAPC, YAEC, MYAPC, and two companies that transmit electricity imported from the Hydro-Quebec system. NU does not control these companies and does not consolidate them in its financial statements. NU accounts for the investments in these companies using the equity method. Under the equity method, NU records its ownership share of the earnings or losses at these companies. Determining whether or not NU should apply the equity method of accounting for an investment requires management judgment.

NU had a preferred stock investment in R.M. Services, Inc. (RMS). Upon adoption of Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46, "Consolidation of Variable Interest Entities," management determined that NU was the primary beneficiary of RMS and subsequently consolidated RMS into its financial statements. The consolidation of RMS resulted in a negative $4.7 million after-tax cumulative effect of an accounting change in the third quarter of 2003. On June 30, 2004, the assets and liabilities of RMS were sold. For more information on RMS, see Note 1I, "Summary of Significant Accounting Policies – Accounting for R.M. Services, Inc." to the consolidated financial statements.

In December of 2003, the FASB issued a revised version of FIN 46 (FIN 46R). FIN 46R was effective for NU for the first quarter of 2004 and did not have an impact on NU’s consolidated financial statements.

Pension and Postretirement Benefits Other Than Pensions (PBOP): NU’s subsidiaries participate in a uniform noncontributory defined benefit retirement plan (Pension Plan) covering substantially all regular NU employees. NU also participates in a postretirement benefit plan (PBOP Plan) to provide certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired employees. For each of these plans, the development of the benefit obligation, fair value of plan assets, funded status and net periodic benefit credit or cost is based on several significant assumptions. If these assumptions were changed, the resulting change in benefit obligations, fair values of plan assets, funded status and net periodic benefit credits or costs could have a material impact on NU’s consolidated financial statements.

Pre-tax periodic pension expense/income for the Pension Plan totaled an expense of $42.5 million, an expense of $5.9 million and income of $31.8 million for the years ended December 31, 2005, 2004 and 2003, respectively. The pension expense/income amounts exclude one-time

items recorded under SFAS No. 88, "Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits."

The pre-tax net PBOP Plan cost, excluding curtailments and termination benefits, totaled $49.8 million, $41.7 million and $35.1 million for the years ended December 31, 2005, 2004 and 2003, respectively.

As a result of the decision to pursue a fundamentally different business strategy, and align the structure of the company to support this business strategy, NU recorded a $2.7 million pre-tax curtailment expense in 2005 for the Pension Plan. NU also accrued certain related termination benefits and recorded a $2.8 million pre-tax charge in 2005 for the Pension Plan. Additional termination benefits may be recorded in 2006.

On December 15, 2005, the NU Board of Trustees approved a benefit for new non-union employees hired on and after January 1, 2006 to receive retirement benefits under a new 401(k) benefit rather than under the Pension Plan. Non-union employees actively employed on December 31, 2005 will be given the choice in 2006 to elect to continue participation in the Pension Plan or instead receive a new employer contribution under the 401(k) Savings Plan effective January 1, 2007. If the new benefit is elected, their accrued pension liability in the Pension Plan will be frozen as of December 31, 2006. Non-union employees will make this election in the second half of 2006. This decision resulted in the recording of an estimated pre-tax curtailment expense of $6.2 million in 2005, as a certain number of employees are expected to elect the new 401(k) benefit, resulting in a reduction in aggregate estimated future years of service under the Pension Plan. Management estimated the amount of the curtailment expense associated with this change based upon actuarial calculations and certain assumptions, including the expected level of transfers to the new 401(k) benefit. Any adjustments to this estimate resulting from actual employee elections will be recorded in 2006.

In April of 2004, as a result of litigation with nineteen former employees, NU was ordered by the court to modify its Pension Plan to include special retirement benefits for fifteen of these former employees retroactive to the dates of their retirement and provide increased future monthly benefit payments. NU recorded $2.1 million in termination benefits related to this litigation in 2004 and made a lump sum benefit payment totaling $1.5 million to these former employees.

For the PBOP Plan, NU recorded an estimated $3.7 million pre-tax curtailment expense at December 31, 2005 relating to NU’s change in business strategy. NU also accrued a $0.5 million pre-tax termination benefit at December 31, 2005 relating to certain benefits provided under the terms of the PBOP Plan. Additional termination benefits may be recorded in 2006.

There were no curtailments or termination benefits recorded for the Pension Plan or PBOP Plan in 2003.

Long-Term Rate of Return Assumptions: In developing the expected long-term rate of return assumptions, NU evaluated input from actuaries and consultants, as well as long-term inflation assumptions and NU’s historical 20-year compounded return of approximately 11 percent. NU’s expected long-term rates of return on assets is based on certain target asset allocation assumptions and expected long-term rates of return. NU believes that 8.75 percent is a reasonable long-term rate of return on Pension Plan and PBOP Plan assets (life assets and non-taxable health assets) and 6.85 percent for PBOP health assets, net of tax for 2005. NU will continue to evaluate these actuarial assumptions, including the expected rate of return, at least annually, and will adjust the appropriate assumptions as necessary. The Pension Plan’s and PBOP Plan’s target asset allocation assumptions and expected long-term rates of return assumptions by asset category are as follows:


	At December 31,
	Pension Benefits		Postretirement Benefits
	2005 and 2004		2005 and 2004
	Target Asset Allocation	Assumed Rate of Return	Target Asset Allocation	Assumed Rate of Return
Equity securities:
United States	45%	9.25%	55%	9.25%
Non-United States	14%	9.25%	11%	9.25%
Emerging markets	3%	10.25%	2%	10.25%
Private	8%	14.25%	-	-
Debt Securities:
Fixed income	20%	5.50%	27%	5.50%
High yield fixed income	5%	7.50%	5%	7.50%
Real estate	5%	7.50%	-	-

The actual asset allocations at December 31, 2005 and 2004 approximated these target asset allocations. NU routinely reviews the actual asset allocations and periodically rebalances the investments to the targeted asset allocations when appropriate. For information regarding actual asset allocations, see Note 7, "Employee Benefits – Pension Benefits and Postretirement Benefits Other Than Pensions," to the consolidated financial statements.

Actuarial Determination of Income and Expense: NU bases the actuarial determination of Pension Plan and PBOP Plan income/expense on a market-related valuation of assets, which reduces year-to-year volatility. This market-related valuation calculation recognizes investment gains or losses over a four-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the fair value of assets. Since the market-related valuation calculation recognizes gains or losses over a four-year period, the future value of the market-related assets will be impacted

as previously deferred gains or losses are recognized. There will be no impact on the fair value of Pension Plan and PBOP Plan assets in the trust funds of these plans.

At December 31, 2005, the Pension Plan had cumulative unrecognized investment gains of $77.6 million, which will decrease pension expense over the next four years. At December 31, 2005, the Pension Plan had cumulative unrecognized actuarial losses of $498.7 million, which will increase pension expense over the expected future working lifetime of active Pension Plan participants, or approximately 13 years. The combined total of unrecognized investment gains and actuarial losses at December 31, 2005 is a net unrecognized loss of $421.1 million. These gains and losses impact the determination of pension expense and the actuarially determined prepaid pension amount recorded on the consolidated balance sheets but have no impact on expected Pension Plan funding.

At December 31, 2005, the PBOP Plan had cumulative unrecognized investment gains of $47.5 million, which will decrease PBOP Plan expense over the next four years. At December 31, 2005, the PBOP Plan also had cumulative unrecognized actuarial losses of $227.4 million, which will increase PBOP Plan expense over the expected future working lifetime of active PBOP Plan participants, or approximately 13 years. The combined total of unrecognized investment gains and actuarial losses at December 31, 2005 is a net unrecognized loss of $179.9 million. These gains and losses impact the determination of PBOP Plan cost and the actuarially determined accrued PBOP Plan cost recorded on the consolidated balance sheets.

Discount Rate: The discount rate that is utilized in determining future pension and PBOP obligations is based on a yield-curve approach where each cash flow related to the Pension Plan or PBOP Plan liability stream is discounted at an interest rate specifically applicable to the timing of the cash flow. The yield curve is developed from the top quartile of AA rated Moody’s and S&P’s bonds without callable features outstanding at December 31, 2005. This process calculates the present values of these cash flows and calculates the equivalent single discount rate that produces the same present value for future cash flows. The discount rates determined on this basis are 5.80 percent for the Pension Plan and 5.65 percent for the PBOP Plan at December 31, 2005. Discount rates used at December 31, 2004 were 6.00 percent for the Pension Plan and 5.50 percent for the PBOP Plan.

Expected Contributions and Forecasted Expense: Due to the effect of the unrecognized actuarial losses and based on an expected rate of return on Pension Plan assets of 8.75 percent, a discount rate of 6.00 percent and an expected rate of return on PBOP assets of 6.85 percent for health assets, net of tax and 8.75 percent for life assets and nontaxable health assets, a discount rate of 5.50 percent and various other assumptions, NU estimates that expected contributions to and forecasted expense for the Pension Plan and PBOP Plan will be as follows (in millions):


	Pension Plan		Postretirement Plan
Year	Expected Contributions	Forecasted Expense	Expected Contributions	Forecasted Expense
2006	$0	$51.6	$49.5	$49.5
2007	$0	$32.5	$41.7	$41.7
2008	$0	$28.1	$39.6	$39.6

Future actual pension and postretirement expense will depend on future investment performance, changes in future discount rates and various other factors related to the populations participating in the plans and amounts capitalized.

Sensitivity Analysis: The following represents the increase/(decrease) to the Pension Plan’s and PBOP Plan’s reported cost as a result of a change in the following assumptions by 50 basis points (in millions):


	At December 31,
	Pension Plan		Postretirement Plan
Assumption Change	2005	2004	2005	2004
Lower long-term rate of return	$10.0	$10.0	$0.9	$0.7
Lower discount rate	$15.6	$13.4	$1.1	$1.0
Lower compensation increase	$(7.3)	$(5.8)	N/A	N/A

Plan Assets: The market-related value of the Pension Plan assets has increased by $47.1 million to $2.1 billion at December 31, 2005. The projected benefit obligation (PBO) for the Pension Plan has also increased by $153 million to $2.3 billion at December 31, 2005. These changes have increased the underfunded status of the Pension Plan on a PBO basis from an underfunded position of $57.7 million at December 31, 2004 to an underfunded position of $163.6 million at December 31, 2005. The PBO includes expectations of future employee compensation increases. The accumulated benefit obligation (ABO) of the Pension Plan was approximately $62 million less than Pension Plan assets at December 31, 2005 and approximately $225 million less than Pension Plan assets at December 31, 2004. The ABO is the obligation for employee service and compensation provided through December 31, 2005. Under current accounting rules, if the ABO exceeds Pension Plan assets at a future plan measurement date, NU will record an additional minimum liability. NU has not made employer contributions to the Pension Plan since 1991.

The value of PBOP Plan assets has increased from $199.8 million at December 31, 2004 to $222.9 million at December 31, 2005. The benefit obligation for the PBOP Plan has also increased from $468.3 million at December 31, 2004 to $493.8 million at December 31, 2005. These changes have increased the underfunded status of the PBOP Plan on an accumulated projected benefit obligation basis from $268.5 million at December 31, 2004 to $270.9 million at December 31, 2005. NU has made a contribution each year equal to the PBOP Plan’s postretirement benefit cost, excluding curtailment and termination benefits.

Health Care Cost: The health care cost trend assumption used to project increases in medical costs was 7 percent for 2005 and 8 percent for 2004, decreasing one percentage point per year to an ultimate rate of 5 percent in 2007. For December 31, 2005 disclosure purposes, the health care cost trend assumption was reset for 2006 at 10 percent, decreasing one percentage point per year to an ultimate rate of 5 percent in 2011. The effect of increasing the health care cost trend by one percentage point would have increased service and interest cost components of the PBOP Plan cost by $0.9 million in 2005 and $1 million in 2004.

Income Taxes: Income tax expense is calculated each year in each of the jurisdictions in which NU operates. This process involves estimating NU’s actual current tax exposures as well as assessing temporary differences resulting from differing treatment of items, such as timing of the deduction and expenses for tax and book accounting purposes. These differences result in deferred tax assets and liabilities, which are included in NU’s consolidated balance sheets. The income tax estimation process impacts all of NU’s segments and adjustments made to income taxes could significantly affect NU’s consolidated financial statements. Management must also assess the likelihood that deferred tax assets will be recovered from future taxable income, and to the extent that recovery is not likely, a valuation allowance must be established. Significant management judgment is required in determining income tax expense, deferred tax assets and liabilities and valuation allowances.

NU accounts for deferred taxes under SFAS No. 109, "Accounting for Income Taxes." For temporary differences recorded as deferred tax liabilities that will be recovered in rates in the future, NU has established a regulatory asset. The regulatory asset amounted to $332.5 million and $316.3 million at December 31, 2005 and 2004, respectively. Regulatory agencies in certain jurisdictions in which NU’s Utility Group companies operate require the tax effect of specific temporary differences to be "flowed through" to utility customers. Flow through treatment means that deferred tax expense is not recorded on the consolidated statements of (loss)/income. Instead, the tax effect of the temporary difference impacts both amounts for income tax expense currently included in customers’ rates and the company’s net income. Flow through treatment can result in effective income tax rates that are significantly different than expected income tax rates. Recording deferred taxes on flow through items is required by SFAS No. 109, and the offset to the deferred tax amounts is the regulatory asset referred to above.

A reconciliation from expected tax expense at the statutory federal income tax rate to actual tax expense recorded is included in the accompanying footnotes to the consolidated financial statements. See Note 1H, "Summary of Significant Accounting Policies – Income Taxes," to the consolidated financial statements for further information.

The estimates that are made by management in order to record income tax expense, accrued taxes and deferred taxes are compared each year to the actual tax amounts filed on NU’s income tax returns. The income tax returns were filed in the fall of 2005 for the 2004 tax year, and NU recorded differences between income tax expense, accrued taxes and deferred taxes on its consolidated financial statements and the amounts that were on its income tax returns.

Depreciation: Depreciation expense is calculated based on an asset’s useful life, and judgment is involved when estimating the useful lives of certain assets. A change in the estimated useful lives of these assets could have a material impact on NU’s consolidated financial statements absent timely rate relief for Utility Group assets.

Accounting for Environmental Reserves: Environmental reserves are accrued using a probabilistic model approach when assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated. Adjustments made to environmental liabilities could have a significant effect on earnings. The probabilistic model approach estimates the liability based on the most likely action plan from a variety of available remediation options, ranging from no action to remedies ranging from establishing institutional controls to full site remediation and long-term monitoring. The probabilistic model approach estimates the liabilities associated with each possible action plan based on findings through various phases of site assessments.

These estimates are based on currently available information from presently enacted state and federal environmental laws and regulations and several cost estimates from outside engineering and remediation contractors. These amounts also take into consideration prior experience in remediating contaminated sites and data released by the United States Environmental Protection Agency and other organizations. These estimates are subjective in nature partly because there are usually several different remediation options from which to choose when working on a specific site. These estimates are subject to revisions in future periods based on actual costs or new information concerning either the level of contamination at the site or newly enacted laws and regulations. The amounts recorded as environmental liabilities on the consolidated balance sheets represent management’s best estimate of the liability for environmental costs based on current site information from site assessments and remediation estimates. These liabilities are estimated on an undiscounted basis.

PSNH and Yankee Gas have regulatory recovery mechanisms in place for environmental costs. Accordingly, regulatory assets have been recorded for certain of PSNH’s and Yankee Gas’ environmental liabilities. As of December 31, 2005 and 2004, $24.7 million and $28 million, respectively, have been recorded as regulatory assets on the accompanying consolidated balance sheets. CL&P recovers a certain level of environmental costs currently in rates but does not have an environmental cost recovery tracking mechanism. Accordingly, changes in CL&P’s environmental reserves impact CL&P’s earnings. WMECO does not have a regulatory mechanism to recover environmental costs from its customers, and changes in WMECO’s environmental reserves impact WMECO’s earnings.

Asset Retirement Obligations: On March 30, 2005, the FASB issued FIN 47, "Accounting for Conditional Asset Retirement Obligations – an Interpretation of FASB Statement No. 143." FIN 47 requires an entity to recognize a liability for the fair value of an ARO that is conditional on a future event if the liability’s fair value can be reasonably estimated. NU adopted FIN 47 on December 31, 2005. Upon adoption, management identified several conditional removal obligations that have been accounted for as AROs. A cumulative effect of an accounting change reflecting a $1 million after-tax loss related to the adoption of FIN 47 is related to NGC and Mt. Tom, which are included in discontinued operations on the accompanying consolidated statements of (loss)/income. For further information regarding the adoption of FIN 47, see Note 1P, "Summary of Significant Accounting Policies – Asset Retirement Obligations," to the consolidated financial statements.

Under SFAS No. 71, regulated utilities, including NU’s Utility Group companies, currently recover amounts in rates for future costs of removal of plant assets. At December 31, 2005 and 2004, these amounts totaling $305.5 million and $328.8 million, respectively, are classified as regulatory liabilities on the accompanying consolidated balance sheets.

Special Purpose Entities: In addition to SPEs that are described in the "Off-Balance Sheet Arrangements" section of this management’s discussion and analysis, during 2001 and 2002, to facilitate the issuance of rate reduction bonds and certificates intended to finance certain stranded costs, NU established four SPEs: CL&P Funding LLC, PSNH Funding LLC, PSNH Funding LLC 2, and WMECO Funding LLC (the funding companies). The funding companies were created as part of state-sponsored securitization programs. The funding companies are restricted from engaging in non-related activities and are required to operate in a manner intended to reduce the likelihood that they would be included in their respective parent company’s bankruptcy estate if they ever become involved in a bankruptcy proceeding. The funding companies and the securitization amounts are consolidated in the accompanying consolidated financial statements.

During 1999, SESI established an SPE, HEC/Tobyhanna, in connection with a federal energy savings performance project located at the United States Army Depot in Tobyhanna, Pennsylvania. HEC/Tobyhanna sold $26.5 million of Certificates related to the project and used the funds to repay SESI for the costs of the project. HEC/Tobyhanna’s activities and Certificates are included in NU’s consolidated financial statements. NU Enterprises is in the process of exiting SESI.

Other Matters

Commitments and Contingencies: For further information regarding other commitments and contingencies, see Note 9, "Commitments and Contingencies," to the consolidated financial statements.

Accounting Standards Issued But Not Yet Adopted:

Share-Based Payments: On December 16, 2004, the FASB issued SFAS No. 123 (Revised 2004), "Share-Based Payments," (SFAS No. 123R), which amended SFAS No. 123, "Accounting for Stock-Based Compensation." Under the provisions of SFAS No. 123R, NU will recognize compensation expense for the unvested portion of previously granted awards outstanding beginning on January 1, 2006, the effective date of SFAS No. 123R, and any new awards after that date. The adoption of SFAS No. 123R is not expected to have a material impact on NU’s consolidated financial statements. For information regarding current accounting for equity-based compensation, see Note 1N, "Summary of Significant Accounting Policies - Equity- Based Compensation," to the consolidated financial statements.

Accounting Changes and Error Corrections: In May of 2005, the FASB issued SFAS No. 154, "Accounting Changes and Error Corrections." SFAS No. 154 is effective beginning on January 1, 2006 for NU and requires retrospective application to prior periods’ financial statements of voluntary changes in accounting principles. It also applies to accounting changes required by a new accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. SFAS No. 154 does not change previous guidance for reporting the correction of an error in previously issued financial statements or a change in accounting estimate. Implementation of SFAS No. 154 on January 1, 2006 is not expected to affect NU’s consolidated financial statements until such time that its provisions are required to be applied as described above.

Contractual Obligations and Commercial Commitments: Information regarding NU’s contractual obligations and commercial commitments at December 31, 2005 is summarized through 2010 and thereafter as follows:


(Millions of Dollars)	2006	2007	2008	2009	2010	Thereafter
Notes payable to banks ^(a)	$ 32.0	$ -	$ -	$ -	$ -	$ -
Long-term debt ^{(a) (b)}	22.7	4.1	155.3	56.5	8.0	2,544.5
Estimated interest payments on existing debt	162.7	160.7	157.9	153.4	151.2	1,759.3
Capital leases ^(c)(d)	2.7	2.6	2.3	2.0	1.5	16.6
Operating leases ^(d)(e)	33.4	29.9	26.8	18.8	15.5	42.3
Required funding of other postretirement benefit obligations ^(e)	49.5	41.7	39.6	37.5	35.9	N/A
Estimated future annual Utility Group costs^(d)(e)	947.2	508.9	392.7	361.0	330.0	1,273.4
Estimated future annual NU Enterprises costs ^(d)(e)	2,255.0	698.2	323.1	22.6	18.2	5.0
Totals	$3,505.2	$1,446.1	$1,097.7	$651.8	$560.3	$5,641.1

(a)

Included in NU’s debt agreements are usual and customary positive, negative and financial covenants. Non-compliance with certain covenants, for example the timely payment of principal and interest, may constitute an event of default, which could cause an acceleration of principal in the absence of receipt by the company of a waiver or amendment. Such acceleration would change the obligations outlined in the table of contractual obligations and commercial commitments.

(b)

Long-term debt excludes $268 million of fees and interest due for spent nuclear fuel disposal costs, $5.2 million of net changes in fair value and $3.9 million of net unamortized discounts.

(c)

The capital lease obligations include imputed interest of $13.7 million.

(d)

NU has no provisions in its capital or operating lease agreements or agreements related to the estimated future annual Utility Group or NU Enterprises costs that could trigger a change in terms and conditions, such as acceleration of payment obligations.

(e)

Amounts are not included on NU’s consolidated balance sheets.

Rate reduction bond amounts are non-recourse to NU, have no required payments over the next five years and are not included in this table. The Utility Group’s standard offer service contracts and default service contracts also are not included in this table. The estimated payments under interest rate swap agreements are not included in this table as the estimated payment amounts are not determinable. For further information regarding NU’s contractual obligations and commercial commitments, see the consolidated statements of capitalization and Note 5, "Short-Term Debt," Note 9D, "Commitments and Contingencies – Long-Term Contractual Arrangements," Note 12, "Leases," and Note 13, "Long-Term Debt," to the consolidated financial statements.

Forward Looking Statements: This discussion and analysis includes statements concerning NU’s expectations, plans, objectives, future financial performance and other statements that are not historical facts. These statements are "forward looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. In some cases the reader can identify these forward looking statements by words such as "estimate," "expect," "anticipate," "intend," "plan," "believe," "forecast," "should," "could," and similar expressions. Forward looking statements involve risks and uncertainties that may cause actual results or outcomes to differ materially from those included in the forward looking statements. Factors that may cause actual results to differ materially from those included in the forward looking statements include, but are not limited to, actions by state and federal regulatory bodies, competition and industry restructuring, changes in economic conditions, changes in weather patterns, changes in laws, regulations or regulatory policy, expiration or initiation of significant energy supply contracts, changes in levels of capital expenditures, developments in legal or public policy doctrines, technological developments, volatility in electric and natural gas commodity markets, effectiveness of our risk management policies and procedures, changes in accounting standards and financial reporting regulations, fluctuations in the value of electricity positions, the methods, timing and results of disposition of competitive businesses, actions of rating agencies, terrorist attacks on domestic energy facilities and other presently unknown or unforeseen factors. Other risk factors are detailed from time to time in our reports to the SEC. Management undertakes no obligation to update the information contained in any forward looking statements to reflect developments or circumstances occurring after the statement is made.

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

RESULTS OF OPERATIONS

The components of significant income statement variances for the past two years are provided in the table below (millions of dollars).


Income Statement Variances	2005 over/(under) 2004			2004 over/(under) 2003
	Amount	Percent		Amount	Percent
Operating Revenues	$ 855	13	%	$599	10	%

Operating Expenses:
Fuel, purchased and net interchange power	702	16		511	13
Other operation	116	12		103	12
Wholesale contract market changes, net	425	100		-	-
Restructuring and impairment charges	44	100		-	-
Maintenance	15	9		5	3
Depreciation	10	5		20	10
Amortization	65	47		(54)	(28)
Amortization of rate reduction bonds	11	7		12	8
Taxes other than income taxes	17	7		10	5
Total operating expenses	1,405	22		607	11
Operating (loss)/income	(550)	(a)		(8)	(3)
Interest expense, net	24	11		8	4
Other income, net	28	(a)		10	(a)
(Loss)/income before income tax (benefit)/expense	(546)	(a)		(6)	(5)
Income tax (benefit)/expense	(210)	(a)		2	9
Preferred dividends of subsidiary	-	-		-	-
(Loss)/income from continuing operations	(336)	(a)		(8)	(10)
Income from discontinued operations	(33)	(70)		3	7
Cumulative effects of accounting changes, net of tax benefits	(1)	(100)		5	100
Net (loss)/income	$(370)	(a)	%	$ -	-	%

(a) Percent greater than 100.

2005 Compared to 2004

Operating Revenues

Operating revenues increased $855 million in 2005 primarily due to higher electric distribution revenues ($796 million), higher gas distribution revenues ($95 million), and higher regulated transmission business revenues ($24 million), partially offset by lower revenues from NU Enterprises ($59 million).

The electric distribution revenue increase of $796 million is primarily due to the components of CL&P, PSNH and WMECO retail revenues which are included in regulatory commission approved tracking mechanisms that track the recovery of certain incurred costs ($732 million). The tracking mechanisms allow for rates to be changed periodically with over collections refunded to customers or under collections collected from customers in future periods. The distribution revenue tracking components increase of $732 million is primarily due to the pass through of higher energy supply costs ($447 million), CL&P FMCC charges ($235 million) and higher wholesale revenues ($69 million). The distribution component of these companies and the retail transmission component of PSNH which flow through to earnings increased $65 million primarily due to an increase in retail rates and an increase in retail sales. Regulated retail sales increased 2.6 percent in 2005 compared with 2004, primarily due to an unseasonably hot third quarter. On a weather adjusted basis, retail sales were relatively flat.

The higher gas distribution revenue of $95 million is primarily due to the recovery of increased gas costs ($80 million) and the effect of the January 1, 2005 base rate increase ($14 million).

Transmission business revenues increased $24 million primarily due to the recovery of higher operating expenses in 2005 as allowed under FERC Tariff Schedule 21, a higher transmission investment base and the incremental recovery of 2004 expenses.

The NU Enterprises’ revenue decrease of $59 million is primarily due to lower revenues from the mark-to-market accounting for certain wholesale contracts related to the business to be exited. As a result of mark-to-market accounting, receipts under those contracts are netted with expenses to serve those contracts and recorded in fuel, purchased and net interchange power, resulting in reduced revenues by approximately $693 million. Additionally, revenues decreased primarily due to the wholesale marketing business ($385 million) and the services business ($26 million) as a result of lower sales volumes. These decreases are partially offset by the NU consolidating impact of eliminating lower intercompany revenues from CL&P and WMECO ($687 million) and higher revenues from the retail marketing business as a result of higher rates and volumes ($355 million).

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expense increased $702 million in 2005, primarily due to higher purchased power costs for the Utility Group ($1.34 billion), partially offset by lower costs at NU Enterprises ($642 million). The $1.34 billion increase for the Utility Group is due to the NU consolidating impact of eliminating lower intercompany TSO purchases from NU Enterprises ($687 million) and higher CL&P and WMECO standard offer supply costs and increased retail sales ($479 million). The increase is also due to higher PSNH expenses primarily due to higher energy costs and higher retail sales ($98 million) and higher Yankee Gas expenses primarily due to increased gas prices ($80 million).

NU Enterprises’ lower fuel costs of $642 million are primarily due to the mark-to-market accounting for certain wholesale contracts related to the business to be exited ($693 million) as a result of netting revenues with expenses. Additionally, fuel costs are lower due to the wholesale marketing business ($304 million) primarily due to lower sales volumes. These decreases are partially offset by higher fuel costs and volumes in the retail marketing business ($355 million).

Other Operation

Other operation expense increased $116 million in 2005, primarily due to higher RMR and other power pool related expenses ($78 million). In addition, administrative and general expenses increased primarily due to higher pension costs and other benefits ($33 million), employee termination and benefit plan curtailment costs ($27 million) of which $21 million relates to regulated distribution that impact earnings, higher uncollectible expenses ($7 million), and a 2005 environmental reserve for a manufactured gas plant site at HWP ($5 million). These increases are partially offset by lower expenses for NU Enterprises as a result of decreased cost of services primarily in the services business ($28 million).

Wholesale Contract Market Changes, Net

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

Restructuring and Impairment Charges

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

Maintenance

Maintenance expense increased $15 million in 2005, primarily due to increased electric distribution expenses, including higher overhead and underground line, substation and transformer maintenance expenses ($14 million) in part due to heat related and storm activity.

Depreciation

Depreciation increased $10 million in 2005 primarily due to higher Utility Group depreciation expense resulting from higher plant balances ($16 million), partially offset by lower Yankee Gas depreciation expense as allowed in the January 1, 2005 rate decision, due to adequate reserve levels for cost of removal ($6 million).

Amortization

Amortization increased $65 million in 2005 primarily due to acceleration in the recovery of PSNH’s non-securitized stranded costs as a result of the positive reconciliation of stranded cost revenues and expenses ($47 million). Amortization also increased due to higher amortization related to the CL&P’s recovery of transition charges as a result of higher wholesale revenues ($34 million). These increases are partially offset by lower WMECO recovery of stranded costs ($18 million) primarily due to the decrease in WMECO’s transition component of retail rates.

Amortization of Rate Reduction Bonds

Amortization of rate reduction bonds increased $11 million in 2005 due to the repayment of a higher principal amount as compared to 2004.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $17 million in 2005 primarily due to higher Connecticut gross earnings tax related to higher CL&P and Yankee Gas revenues.

Interest Expense, Net

Interest expense, net increased $24 million in 2005, primarily due to higher interest on long-term debt ($23 million) as a result of Utility Group issuance of new long-term debt in 2005. New long-term debt of $350 million includes the issuance of $200 million related to CL&P in April and the issuance of $50 million per company related to Yankee Gas, WMECO, and PSNH in July, August and October, respectively. See the liquidity section for a further description and explanation of the debt issued. Interest expense, net is also higher due to higher short-term debt levels primarily at NU Parent ($6 million). In addition, interest expense, net increased at CL&P due to higher other interest as a result of the final streetlight refund docket ($3 million). These increases are partially offset by lower rate reduction bond interest resulting from lower principal balances outstanding at CL&P, PSNH and WMECO ($11 million).

Other Income, Net

Other income, net increased $28 million in 2005 primarily due to higher allowance for funds used in construction ($8 million), higher investment income ($8 million), a net decrease in investment write-downs ($7 million), and a higher CL&P procurement fee ($6 million).

Income Tax (Benefit)/Expense

Included in the notes to the consolidated financial statements is a reconciliation of actual and expected tax expense. The tax effect of temporary differences is accounted for in accordance with the rate-making treatment of the applicable regulatory commissions. In past years, this rate-making treatment has required the company to provide the customers with a portion of the tax benefits associated with accelerated tax depreciation in the year it is generated (flow-through depreciation). As these flow-through differences turn around, higher tax expense is recorded.

Income tax expense decreased $210 million to a benefit of $188 million in 2005 from an expense of $22 million in 2004 primarily due to a loss before income tax expense and greater favorable flow through adjustments, offset by increases to the deferred state income tax valuation allowance. The increase in the state income tax valuation allowance was required due to the magnitude of the tax losses limiting the ability to utilize the state tax benefits within the applicable state tax carryforward period.

Income from Discontinued Operations

NU's consolidated statements of (loss)/income for the years ended December 31, 2005, 2004, and 2003 present the operations for NGC, Mt. Tom, SESI, Woods Electrical, SECI-NH, and Woods Network as discontinued operations as a result of meeting the criteria requiring this presentation. Under this presentation, revenues and expenses of these businesses are classified net of tax in income from discontinued operations on the accompanying consolidated statements of (loss)/income and all prior periods have been reclassified. See Note 4, "Assets Held for Sale and Discontinued Operations," to the consolidated financial statements for a description and explanation of the discontinued operations.

Cumulative Effects of Accounting Changes, Net of Tax Benefits

A cumulative effect of accounting change, net of tax benefit ($1 million) was recorded in the fourth quarter of 2005 in connection with the adoption of FIN 47, which required NU to recognize a liability for the fair value of an ARO.

2004 Compared to 2003

Operating Revenues

Operating revenues increased $599 million in 2004 due to higher revenues from NU Enterprises ($369 million), higher electric distribution revenues ($172 million), higher gas distribution revenues ($46 million) and higher regulated transmission revenues ($13 million).

The NU Enterprises’ revenue increase of $369 million is primarily due to higher revenues for the retail marketing business ($197 million), the 2003 revenue reduction recorded for the settlement of a wholesale power dispute associated with CL&P standard offer supply ($56 million), and an increased level of competitive energy services business ($24 million). Higher revenues for the retail marketing business resulted from higher electric volumes ($119 million), higher gas prices ($48 million), higher electric prices ($28 million), and higher gas volumes ($2 million). The competitive energy services business revenue increase resulted from higher revenues from a cogeneration project and higher volumes in the mechanical contracting group.

The electric distribution revenue increase of $172 million is primarily due to non-earnings components of CL&P, PSNH and WMECO retail rates ($141 million). The distribution component of these companies and the retail transmission component of CL&P and PSNH that flow through to earnings increased $33 million, primarily due to the CL&P retail transmission rate increase effective in January of 2004. The non-earnings components increase of $141 million is primarily due to the pass through of energy supply costs ($269 million) and CL&P FMCC ($151 million), partially offset by the resolution of SMD cost recovery which was being collected from CL&P customers in 2003 and early 2004 and subsequently refunded beginning in late 2004 ($71 million), lower CL&P EAC revenue as a result of the end of EAC billings in 2003 ($44 million), lower transition cost recoveries for CL&P and WMECO ($44 million) and lower CL&P system benefit cost recoveries ($31 million). Regulated retail sales increased 0.9 percent in 2004 compared with 2003. On a weather adjusted basis, retail sales increased 1.9 percent as a result of improved economic conditions and increasing use per customer. In addition, electric wholesale revenues decreased $72 million, primarily due to lower Utility Group sales related to IPP contracts and the expiration of long-term contracts.

The higher gas distribution revenue of $46 million is primarily due to the recovery of increased gas costs ($17 million) and the absence of the 2003 unbilled revenue adjustment ($28 million).

Transmission revenues were higher primarily due to the October 2003 implementation of the transmission rate case approved at the FERC.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expense increased $511 million in 2004, primarily due to higher wholesale costs at NU Enterprises ($239 million) and higher purchased power costs for the Utility Group ($272 million). The increase for the Utility Group is primarily due to an increase in the standard offer supply costs for CL&P ($152 million) and WMECO ($16 million), higher Yankee Gas expenses ($33 million) primarily due to increased gas prices, higher expenses for PSNH ($10 million) primarily due to higher energy and capacity purchases, partially offset by the 2003 CL&P recovery of certain fuel costs ($44 million).

Other Operation

Other operation expenses increased $103 million in 2004, primarily due to higher expenses for NU Enterprises resulting from the increased volume in the contracting business ($43 million), higher CL&P RMR costs and other power pool related expenses ($71 million), higher PSNH fossil production expense ($6 million), and higher distribution expenses ($4 million), partially offset by lower Conservation and Load Management (C&LM) expense ($20 million).

Maintenance

Maintenance expense increased $5 million in 2004, primarily due to the absence of the 2003 positive resolution of the Millstone use of proceeds docket ($5 million) and higher electric distribution expenses ($5 million), partially offset by lower expenses for NU Enterprises ($3 million).

Depreciation

Depreciation increased $20 million in 2004 due to higher Utility Group plant balances and higher depreciation rates at CL&P resulting from the distribution rate case decision effective in January of 2004.

Amortization

Amortization decreased $54 million in 2004 primarily due to lower Utility Group recovery of stranded costs and a decrease in amortization expense resulting from the amortization of GSC over-recoveries allowed in the CL&P distribution rate case effective in January of 2004 ($29 million).

Amortization of Rate Reduction Bonds

Amortization of rate reduction bonds increased $12 million in 2004 due to the repayment of a higher principal amount as compared to 2003.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $10 million in 2004 primarily due to higher payroll taxes ($4 million), higher sales tax ($3 million) and higher local property taxes ($2 million).

Interest Expense, Net

Interest expense, net increased $8 million in 2004 primarily due to the issuance of $75 million of ten-year notes at Yankee Gas in January of 2004, the issuance of $50 million of thirty-year senior notes at WMECO in September of 2004, and the issuance of $150 million of five-year notes at NU Parent in June of 2003.

Other Income, Net

Other income, net increased $10 million in 2004 primarily due to the recognition, beginning in 2004, of a CL&P procurement fee approved in the TSO docket decision ($12 million).

Income Tax (Benefit)/Expense

Income tax expense increased by $2 million in 2004 due to higher reversal of prior flow-through depreciation and lower favorable adjustments to tax expense, partially offset by lower state income tax expense, due to increased state tax credits and favorable unitary apportionment.

Income from Discontinued Operations

The operations of NGC, Mt. Tom, SESI, SECI-NH, Woods Network and Woods Electrical were presented as discontinued operations as a result of meeting the criteria requiring this presentation. Under this presentation, revenues and expenses of these businesses are included in the income from discontinued operations on the consolidated statements of (loss)/income. See Note 4, "Assets Held for Sale and Discontinued Operations," to the consolidated financial statements for a description and explanation of the discontinued operations.

Cumulative Effects of Accounting Changes, Net of Tax Benefits

A cumulative effect of accounting change, net of tax benefit ($5 million) was recorded in the third quarter of 2003 in connection with the adoption of FIN 46, which required NU to consolidate RMS into NU’s financial statements and adjust its equity interest as a cumulative effect of an accounting change.

Item 8.

Financial Statements and Supplementary Data

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Trustees and Shareholders of Northeast Utilities:

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Northeast Utilities and subsidiaries (a Massachusetts Trust) (the “Company”) as of December 31, 2005 and 2004, and the related consolidated statements of (loss)/income, comprehensive (loss)/income, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2005. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Northeast Utilities and subsidiaries as of December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Notes 2, and 3, the Company recorded significant charges in the year ended December 31, 2005 in connection with its decision to exit certain business lines and, as discussed in Notes 4 and 18, certain components of the Company’s energy services businesses and its generation business are reported as discontinued operations.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company's internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 7, 2006 expressed an unqualified opinion on management's assessment of the effectiveness of the Company's internal control over financial reporting and an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.


/s/	Deloitte and Touche
	Deloitte and Touche

Hartford, Connecticut

March 7, 2006 (June 7, 2006 as to Notes 1B, 1H, 1P, 1V, 2, 4, 12, 16, 17, and 18)

CONSOLIDATED BALANCE SHEETS


At December 31,	2005	2004
	(Thousands of Dollars)
Assets

Current Assets:
Cash and cash equivalents	$ 45,782	$ 46,989
Special deposits	103,789	82,584
Investments in securitizable assets	252,801	139,391
Receivables, less provision for uncollectible accounts
of $24,444 in 2005 and $25,325 in 2004	901,516	771,257
Unbilled revenues	175,853	144,438
Taxes receivable	-	61,420
Fuel, materials and supplies	206,557	185,180
Marketable securities	56,012	52,498
Derivative assets – current	403,507	81,567
Prepayments and other	129,242	154,395
Assets held for sale	101,784	-
	2,376,843	1,719,719

Property, Plant and Equipment:
Electric utility	6,378,838	5,918,539
Gas utility	825,872	786,545
Competitive energy	908,776	918,183
Other	254,659	241,190
	8,368,145	7,864,457
Less: Accumulated depreciation	2,551,322	2,382,927
	5,816,823	5,481,530
Construction work in progress	600,407	382,631
	6,417,230	5,864,161

Deferred Debits and Other Assets:
Regulatory assets	2,483,851	2,746,219
Goodwill	287,591	319,986
Prepaid pension	298,545	352,750
Marketable securities	56,527	51,924
Derivative assets - long-term	425,049	198,769
Other	223,439	384,868
	3,775,002	4,054,516












Total Assets	$ 12,569,075	$ 11,638,396



The accompanying notes are an integral part of these consolidated financial statements.

CONSOLIDATED BALANCE SHEETS


At December 31,	2005	2004
	(Thousands of Dollars)
Liabilities and Capitalization

Current Liabilities:
Notes payable to banks	$ 32,000	$ 180,000
Long-term debt - current portion	22,673	90,759
Accounts payable	972,368	825,247
Accrued taxes	95,210	-
Accrued interest	47,742	49,449
Derivative liabilities – current	402,530	130,275
Counterparty deposits	28,944	57,650
Other	272,252	212,239
Liabilities of assets held for sale	101,511	-
	1,975,230	1,545,619

Rate Reduction Bonds	1,350,502	1,546,490

Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	1,306,340	1,434,403
Accumulated deferred investment tax credits	95,444	99,124
Deferred contractual obligations	358,174	413,056
Regulatory liabilities	1,273,501	1,070,187
Derivative liabilities - long-term	272,995	58,737
Other	364,157	267,895
	3,670,611	3,343,402
Capitalization:
Long-Term Debt	3,027,288	2,789,974

Preferred Stock of Subsidiary - Non-Redeemable	116,200	116,200

Common Shareholders' Equity:
Common shares, $5 par value - authorized 225,000,000
shares; 174,897,704 shares issued and 153,225,892
shares outstanding in 2005 and 151,230,981 shares
issued and 129,034,442 shares outstanding in 2004	874,489	756,155
Capital surplus, paid in	1,437,561	1,116,106
Deferred contribution plan - employee stock
ownership plan	(46,884)	(60,547)
Retained earnings	504,301	845,343
Accumulated other comprehensive income/(loss)	19,987	(1,220)
Treasury stock, 19,645,511 shares in 2005
and 19,580,065 shares in 2004	(360,210)	(359,126)
Common Shareholders' Equity	2,429,244	2,296,711
Total Capitalization	5,572,732	5,202,885


Commitments and Contingencies (Note 9)

Total Liabilities and Capitalization	$ 12,569,075	$ 11,638,396


The accompanying notes are an integral part of these consolidated financial statements.


CONSOLIDATED STATEMENTS OF (LOSS)/INCOME

For the Years Ended December 31,	2005	2004	2003
	(Thousands of Dollars, except share information)

Operating Revenues	$ 7,397,743	$ 6,542,038	$ 5,943,358

Operating Expenses:
Operation -
Fuel, purchased and net interchange power	5,103,161	4,401,175	3,890,185
Other	1,054,057	938,088	835,381
Wholesale contract market changes, net	425,446	-	-
Restructuring and impairment charges	44,143	-	-
Maintenance	178,521	163,626	158,323
Depreciation	223,036	213,012	193,115
Amortization	202,949	138,271	191,805
Amortization of rate reduction bonds	176,356	164,915	153,172
Taxes other than income taxes	247,555	230,793	220,801
Total operating expenses	7,655,224	6,249,880	5,642,782
Operating (Loss)/Income	(257,481)	292,158	300,576

Interest Expense:
Interest on long-term debt	131,870	107,365	88,700
Interest on rate reduction bonds	87,439	98,899	108,359
Other interest	19,755	8,762	10,398
Interest expense, net	239,064	215,026	207,457
Other Income, Net	47,732	19,968	9,585
(Loss)/Income from Continuing Operations Before
Income Tax (Benefit)/Expense	(448,813)	97,100	102,704
Income Tax (Benefit)/Expense	(187,796)	21,765	19,879
(Loss)/Income from Continuing Operations Before
Preferred Dividends of Subsidiary	(261,017)	75,335	82,825
Preferred Dividends of Subsidiary	5,559	5,559	5,559
(Loss)/Income from Continuing Operations	(266,576)	69,776	77,266
Discontinued Operations (Note 4):
Income from Discontinued Operations Before Income Taxes	24,327	76,803	74,739
Loss from Sale of Discontinued Operations	(1,123)	-	-
Income Tax Expense	(9,111)	(29,991)	(30,853)
Income from Discontinued Operations	14,093	46,812	43,886
(Loss)/Income Before Cumulative Effects of Accounting Changes, Net of Tax Benefits	(252,483)	116,588	121,152
Cumulative effects of accounting changes,
net of tax benefits of $689 in 2005 and $2,553 in 2003	(1,005)	-	(4,741)
Net (Loss)/Income	$ (253,488)	$ 116,588	$ 116,411

Basic and Fully Diluted (Loss)/Earnings Per Common Share:
(Loss)/Income from Continuing Operations	$ (2.03)	$ 0.54	$ 0.61
Income from Discontinued Operations	0.11	0.37	0.34
Cumulative Effects of Accounting Changes,
Net of Tax Benefits	(0.01)	-	(0.04)
Basic and Fully Diluted (Loss)/Earnings Per Common Share	$ (1.93)	$ 0.91	$ 0.91
Basic Common Shares Outstanding (weighted average)	131,638,953	128,245,860	127,114,743
Fully Diluted Common Shares Outstanding (weighted average)	131,638,953	128,396,076	127,240,724

The accompanying notes are an integral part of these consolidated financial statements.


CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS)/INCOME


For the Years Ended December 31,	2005	2004	2003
	(Thousands of Dollars)

Net (Loss)/Income	$ (253,488)	$ 116,588	$ 116,411
Other comprehensive income/(loss), net of tax:
Qualified cash flow hedging instruments	21,688	(28,246)	9,274
Unrealized (losses)/gains on securities	(899)	1,191	2,093
Minimum supplemental executive retirement
pension liability adjustments	418	(156)	(303)
Other comprehensive income/(loss), net of tax	21,207	(27,211)	11,064
Comprehensive (Loss)/Income	$ (232,281)	$ 89,377	$ 127,475


The accompanying notes are an integral part of these consolidated financial statements.


CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY

	Common Shares		Capital Surplus,	Deferred Contribution Plan -	Retained	Accumulated Other Comprehensive Income/	Treasury
	Shares	Amount	Paid In	ESOP	Earnings	(Loss)	Stock	Total
	(Thousands of Dollars, except share information)

Balance as of January 1, 2003	127,562,031	$ 746,879	$1,108,338	$ (87,746)	$ 765,611	$ 14,927	$(337,488)	$ 2,210,521
Net income for 2003					116,411			116,411
Cash dividends on common
shares - $0.575 per share					(73,090)			(73,090)
Issuance of common shares, $5 par value	1,022,556	5,113	8,541					13,654
Allocation of benefits - ESOP	607,020		(4,030)	14,052				10,022
Restricted shares, net	(7,508)		(4,110)				(99)	(4,209)
Repurchase of common shares	(1,638,100)						(23,210)	(23,210)
Issuance of treasury shares	150,000						2,772	2,772
Capital stock expenses, net			185					185
Other comprehensive income						11,064		11,064
Balance as of
December 31, 2003	127,695,999	751,992	1,108,924	(73,694)	808,932	25,991	(358,025)	2,264,120
Net income for 2004					116,588			116,588
Cash dividends on common
shares - $0.625 per share					(80,177)			(80,177)
Issuance of common shares, $5 par value	832,578	4,163	6,774					10,937
Allocation of benefits - ESOP	567,907		(2,384)	13,147				10,763
Restricted shares, net	(62,042)		1,250				(1,101)	149
Tax deduction for stock options exercised and Employee
Stock Purchase Plan disqualifying dispositions			1,356					1,356
Capital stock expenses, net			186					186
Other comprehensive loss						(27,211)		(27,211)
Balance as of
December 31, 2004	129,034,442	756,155	1,116,106	(60,547)	845,343	(1,220)	(359,126)	2,296,711
Net loss for 2005					(253,488)			(253,488)
Cash dividends on common
shares - $0.675 per share					(87,554)			(87,554)
Issuance of common shares, $5 par value	23,666,723	118,334	332,493					450,827
Allocation of benefits – ESOP	590,173		(2,161)	13,663				11,502
Restricted shares, net	(65,446)		5,295				(1,084)	4,211
Tax deduction for stock options exercised and
Employee Stock Purchase Plan disqualifying dispositions			368					368
Capital stock expenses, net			(14,540)					(14,540)
Other comprehensive income						21,207		21,207
Balance as of
December 31, 2005	153,225,892	$ 874,489	$1,437,561	$ (46,884)	$ 504,301	$ 19,987	$(360,210)	$ 2,429,244


The accompanying notes are an integral part of these consolidated financial statements.


CONSOLIDATED STATEMENTS OF CASH FLOWS


For the Years Ended December 31,	2005	2004	2003
Operating Activities:	(Thousands of Dollars)
Net (loss)/income	$ (253,488)	$ 116,588	$ 116,411
Adjustments to reconcile to net cash flows
provided by operating activities:
Wholesale contract market changes, net	440,946	-	-
Restructuring and impairment charges	67,181	-	-
Bad debt expense	27,528	19,062	23,229
Depreciation	235,221	224,855	204,388
Deferred income taxes	(202,789)	111,710	(129,733)
Amortization	202,949	138,271	191,805
Amortization of rate reduction bonds	176,356	164,915	153,172
Amortization/(deferral) of recoverable energy costs	39,914	(22,751)	20,486
Pension expense/(income)	42,662	10,636	(16,416)
Wholesale contract buyout payments	(186,531)	-	-
Regulatory (refunds)/overrecoveries	(65,236)	(150,119)	287,974
Derivative assets and liabilities - changes in fair value	2,405	85,592	(12,175)
Deferred contractual obligations	(89,464)	(56,161)	(52,961)
Other non-cash adjustments	48,477	(30,053)	(60,719)
Other sources of cash	5,528	26,596	5,950
Other uses of cash	-	(10,189)	(51,386)
Changes in current assets and liabilities:
Receivables and unbilled revenues, net	(208,519)	(103,983)	39,322
Fuel, materials and supplies	(17,848)	(31,104)	(34,223)
Investments in securitizable assets	(113,410)	27,074	12,443
Other current assets	(11,061)	(38,648)	121,249
Accounts payable	131,043	124,437	(36,380)
Counterparty deposits	(28,706)	11,154	46,496
Accrued taxes	156,630	(112,300)	(83,625)
Other current liabilities	41,416	(44,935)	(56,357)
Net cash flows provided by operating activities	441,204	460,647	688,950

Investing Activities:
Investments in property and plant:
Electric, gas and other utility plant	(752,124)	(653,948)	(539,424)
Competitive energy assets	(23,231)	(17,527)	(18,686)
Cash flows used for investments in property and plant	(775,355)	(671,475)	(558,110)
Net proceeds from sale of property	31,456	-	-
Proceeds from sales of investment securities	137,099	106,217	34,147
Purchases of investment securities	(142,260)	(171,511)	(49,729)
Restricted cash - LMP costs	-	93,630	(93,630)
CVEC acquisition special deposit	-	-	(30,104)
Other investing activities	49,515	7,721	3,864
Net cash flows used in investing activities	(699,545)	(635,418)	(693,562)

Financing Activities:
Issuance of common shares	450,827	10,937	13,654
Repurchase of common shares	-	-	(20,537)
Issuance of long-term debt	350,355	512,762	268,368
Retirement of rate reduction bonds	(195,988)	(183,470)	(169,352)
(Decrease)/increase in short-term debt	(148,000)	75,000	49,000
Reacquisitions and retirements of long-term debt	(98,056)	(155,532)	(65,600)
Cash dividends on common shares	(87,554)	(80,177)	(73,090)
Other financing activities	(14,450)	(1,132)	(4,792)
Net cash flows provided by/(used in) financing activities	257,134	178,388	(2,349)
Net (decrease)/increase in cash and cash equivalents	(1,207)	3,617	(6,961)
Cash and cash equivalents - beginning of year	46,989	43,372	50,333
Cash and cash equivalents - end of year	$ 45,782	$ 46,989	$ 43,372





The accompanying notes are an integral part of these consolidated financial statements.


CONSOLIDATED STATEMENTS OF CAPITALIZATION
		At December 31,
(Thousands of Dollars)		2005	2004
Common Shareholders’ Equity		$2,429,244	$2,296,711
Preferred Stock:
CL&P Preferred Stock Not Subject to Mandatory Redemption - $50 par value – authorized 9,000,000 shares in 2005 and 2004; 2,324,000 shares outstanding in 2005 and 2004; Dividend rates of $1.90 to $3.28; Current redemption prices of $50.50 to $54.00		116,200	116,200
Long-Term Debt: First Mortgage Bonds:
Final Maturity	Interest Rates
2005	5.00% to 6.75%	-	57,500
2009-2012	6.20% to 7.19%	80,000	80,000
2014-2015	4.80% to 5.25%	375,000	275,000
2019-2024	5.26% to 8.48%	209,845	209,845
2026-2035	5.35% to 8.81%	650,000	450,000
Total First Mortgage Bonds		1,314,845	1,072,345
Other Long-Term Debt: Pollution Control Notes:
2016-2018	5.90%	25,400	25,400
2021-2022	Variable Rate and 5.45% to 6.00%	428,285	428,285
2028	5.85% to 5.95%	369,300	369,300
2031	3.35% until 2008	62,000	62,000
Other:
2005-2008	3.30% to 8.81%	173,263	200,795
2012-2015	5.00% to 9.24%	368,000	328,694
2018-2026	6.00% to 7.69%	-	88,262
2034	5.90%	50,000	50,000
Total Pollution Control Notes and Other		1,476,248	1,552,736
Total First Mortgage Bonds, Pollution Control Notes and Other		2,791,093	2,625,081
Fees and interest due for spent nuclear fuel disposal costs		268,008	259,707
Change in Fair Value		(5,211)	91
Unamortized premium and discount, net		(3,929)	(4,146)
Total Long-Term Debt		3,049,961	2,880,733
Less: Amounts due within one year		22,673	90,759
Long-Term Debt, Net		3,027,288	2,789,974
Total Capitalization		$5,572,732	$5,202,885

The accompanying notes are an integral part of these consolidated financial statements.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Summary of Significant Accounting Policies

About Northeast Utilities

Consolidated: Northeast Utilities (NU or the company) is the parent company of the companies comprising the Utility Group and NU Enterprises. Until February 8, 2006, NU was registered with the Securities and Exchange Commission (SEC) as a holding company under the Public Utility Holding Company Act of 1935 (PUHCA). On February 8, 2006, PUHCA was repealed. Arrangements among the Utility Group, NU Enterprises and other NU companies, outside agencies and other utilities covering interconnections, interchange of electric power and sales of utility property are subject to regulation by the Federal Energy Regulatory Commission (FERC) and/or the SEC. The Utility Group is subject to further regulation for rates, accounting and other matters by the FERC and/or applicable state regulatory commissions.

Several wholly owned subsidiaries of NU provide support services for NU’s companies. Northeast Utilities Service Company (NUSCO) provides centralized accounting, administrative, engineering, financial, information technology, legal, operational, planning, purchasing, and other services to NU’s companies. Three other subsidiaries construct, acquire or lease some of the property and facilities used by NU’s companies.

Utility Group: The Utility Group furnishes franchised retail electric service in Connecticut, New Hampshire and Massachusetts through three companies: The Connecticut Light and Power Company (CL&P), Public Service Company of New Hampshire (PSNH) and Western Massachusetts Electric Company (WMECO). Another Utility Group company is Yankee Gas Services Company (Yankee Gas), which owns and operates Connecticut’s largest natural gas distribution system. The Utility Group includes three reportable business segments: the regulated electric utility distribution segment, the regulated gas utility distribution segment and the regulated electric utility transmission segment.

Effective January 1, 2004, PSNH completed the purchase of the electric system and retail franchise of Connecticut Valley Electric Company (CVEC), a subsidiary of Central Vermont Public Service Corporation (CVPS), for $30.1 million. CVEC’s 11,000 customers in western New Hampshire have been added to PSNH’s customer base. The purchase price included the book value of CVEC’s plant assets of approximately $9 million and an additional $21 million to terminate an above-market wholesale power purchase agreement CVEC had with CVPS. The $21 million payment is being recovered from PSNH’s customers.

NU Enterprises: NU Enterprises, Inc. is the parent company of Select Energy, Inc. (Select Energy), Select Energy Services, Inc. (SESI) and their respective subsidiaries, Northeast Generation Company (NGC), Northeast Generation Services Company (NGS) and its subsidiaries E. S. Boulos Company (Boulos) and Woods Electrical Co., Inc. (Woods Electrical), Select Energy Contracting, Inc. (SECI), Reeds Ferry Supply Co., Inc. (Reeds Ferry) and Woods Network Services, Inc. (Woods Network), all of which are collectively referred to as NU Enterprises. The generation operations of Holyoke Water Power Company (HWP), a direct subsidiary of NU, are also included in the results of NU Enterprises. The companies included in the NU Enterprises segment are grouped into two business segments: the merchant energy business segment and the energy services business segment. The merchant energy business segment is currently comprised of Select Energy’s wholesale marketing business, which includes 1,296 megawatts (MW) of pumped storage and hydroelectric generation assets owned by NGC, 146 MW of coal-fired generation assets owned by HWP (Mt. Tom), Select Energy’s retail marketing business and NGS. On March 9, 2005, NU announced its decision to exit the wholesale marketing portion of the merchant energy business segment as well as the energy services businesses. On November 7, 2005, NU announced it would exit the remainder of the merchant energy business segment, which includes the retail marketing business and the competitive generation business. For information regarding the decisions to exit these businesses, see Note 2, "Wholesale Contract Market Changes," and Note 3, "Restructuring and Impairment Charges," to the consolidated financial statements.

The energy services business segment includes the operations of SESI, Boulos, Woods Electrical, SECI, Reeds Ferry, and Woods Network. SESI performs energy management services for large commercial customers, institutional facilities and the United States government and energy-related construction services. Boulos and Woods Electrical provide third-party electrical services. SECI provides mechanical and electrical contracting services for new construction and service contracts. Reeds Ferry purchases equipment on behalf of SECI. Woods Network is a network design, products and services company.

On November 8, 2005, certain assets of SECI-New Hampshire (SECI-NH), a division of SECI, and 100 percent of the common stock of Reeds Ferry were sold to an unrelated third party. On November 22, 2005, 100 percent of the common stock of Woods Network was sold to an unrelated third party. The proceeds from these two sales totaled $6.5 million. In January of 2006, the Massachusetts service location of Select Energy Contracting - Connecticut (SECI-CT) was sold for approximately $2 million. See Note 4, "Assets Held for Sale and Discontinued Operations," to the consolidated financial statements for further information regarding the status of the sale of the energy services businesses. For information regarding NU’s business segments, see Note 17, "Segment Information," to the consolidated financial statements.

Presentation

The consolidated financial statements of NU and of its subsidiaries, as applicable, include the accounts of all their respective subsidiaries. Intercompany transactions have been eliminated in consolidation.

The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Certain reclassifications of prior period data included in the accompanying consolidated financial statements have been made to conform with the current years’ presentation.

In the company’s consolidated balance sheet at December 31, 2004, the company changed the classification of certain deposit amounts totaling $17.8 million related to its rate reduction bonds. The company previously presented these amounts on a gross basis in deferred debits and other assets – other with an equal and offsetting amount in other current liabilities. For the current year presentation, these amounts are presented on a net basis in the company’s accompanying consolidated balance sheet.

In NU's consolidated statements of (loss)/income for the years ended December 31, 2004 and 2003, the classification of certain expense amounts previously included in other income, net was changed. These expense amounts which were reclassified to other operation expense for the years ended December 31, 2004 and 2003 to provide a more preferable presentation of these expenses, totaled $11.7 million and $16.2 million, respectively.

In the company’s consolidated statements of cash flows for the years ended December 31, 2004 and 2003, the company changed the classification of the change in restricted cash – locational marginal pricing (LMP) costs balances to present that change as an investing activity. The company previously presented that change as an operating activity which resulted in a $93.6 million decrease in net cash flows used in investing activities and a corresponding decrease in operating cash flows from the amounts previously reported for the year ended December 31, 2004 and a $93.6 million increase in net cash flows used in investing activities and a corresponding increase in operating cash flows from amounts previously reported for the year ended December 31, 2003.

The consolidated statements of cash flows for the years ended December 31, 2004 and 2003 have also been reclassified to exclude from cash flows from operations the change in accounts payable related to capital projects as well as excluding these amounts from investments in property and plant in investing activities. These amounts totaled uses of cash of $27.7 million and $5.5 million for the years ended December 31, 2004 and 2003, respectively.

NU’s consolidated statements of (loss)/income for the years ended December 31, 2005, 2004 and 2003 present the operations for the following companies as discontinued operations as a result of meeting the criteria requiring this presentation:

NGC;

The Mt. Tom generating plant (Mt. Tom) owned by HWP;

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

SECI-NH (including Reeds Ferry), a division of SECI;

Woods Network; and

Woods Electrical.

At December 31, 2005, the assets and liabilities of SESI and Woods Electrical have been reclassified to assets held for sale and liabilities of assets held for sale on the accompanying consolidated balance sheet. SECI-NH and Woods Network were sold in November of 2005. For further information regarding these companies, see Note 4, "Assets held for Sale and Discontinued Operations" to the consolidated financial statements.

In the company’s consolidated statements of (loss)/income for the year ended December 31, 2004, the company has reclassified a $5.8 million loss associated with a construction contract from discontinued operations to continuing operations. The company had previously included this loss in discontinued operations in its Form 8-K dated November 22, 2005.

For further information regarding these companies, see Note 4, "Assets Held for Sale and Discontinued Operations," and Note 18, "Subsequent Events," to the consolidated financial statements.

Accounting Standards Issued But Not Yet Adopted

Share-Based Payments: On December 16, 2004, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 123 (Revised 2004), "Share-Based Payments," (SFAS No. 123R), which amended SFAS No. 123, "Accounting for Stock-Based Compensation." Under the provisions of SFAS No. 123R, NU will recognize compensation expense for the unvested portion of previously granted awards outstanding beginning on January 1, 2006, the effective date of SFAS No. 123R, and any new awards after that date. The adoption of SFAS No. 123R is not expected to have a material impact on NU’s consolidated financial statements. For information regarding current accounting for equity-based compensation, see Note 1N, "Summary of Significant Accounting Policies – Equity-Based Compensation," to the consolidated financial statements.

Guarantees

NU provides credit assurances on behalf of subsidiaries in the form of guarantees and letters of credit (LOCs) in the normal course of business. NU would be required to perform under these guarantees in the event of non-performance by NU Enterprises, primarily Select Energy. At December 31, 2005, the maximum level of exposure in accordance with FASB Interpretation No. (FIN) 45, "Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others," under guarantees by NU, primarily on behalf of NU Enterprises, totaled $989.7 million. A majority of these guarantees do not have established expiration dates, and some guarantees have unlimited exposure to commodity price movements. Additionally, NU had $253 million of LOCs issued, the majority of which were issued for the benefit of NU Enterprises at December 31, 2005. NU has no guarantees of the performance of third parties.

At December 31, 2005, NU had outstanding guarantees on behalf of the Utility Group and Rocky River Realty (RRR) of $11 million and $10.7 million, respectively. These amounts are included in the total outstanding NU guarantee exposure amount of $989.7 million. The guarantee amount of $968 million for NU Enterprises includes $670 million for Select Energy and $298 million for the energy services businesses. The $298 million in guarantees related to the energy services businesses is comprised of $97 million and $14.1 million for SESI’s and NGC’s obligations, respectively, under certain financing arrangements and $186.9 million for performance obligations of the energy services businesses.

Several underlying contracts that NU guarantees, as well as certain surety bonds, contain credit ratings triggers that would require NU to post collateral in the event that NU’s credit ratings are downgraded below investment grade.

Until the repeal of PUHCA on February 8, 2006, NU was authorized by the SEC to provide up to $750 million of guarantees for its non-utility subsidiaries through June 30, 2007. The $11 million in outstanding guarantees on behalf of the Utility Group was subject to a separate PUHCA limitation of $50 million. The amount of guarantees outstanding for compliance with this limit for NU Enterprises at December 31, 2005 is $567.5 million. The amount of guarantees outstanding for compliance with the limit for the Utility Group at December 31, 2005 is $0.2 million. These amounts are calculated using different, more probabilistic and fair-value based criteria than the maximum level of exposure required to be disclosed under FIN 45. FIN 45 includes all exposures even though they are not reasonably likely to result in exposure to NU.

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

With the repeal of PUHCA, there are no regulatory limits on NU’s ability to guarantee the obligation of its subsidiaries.

Revenues

Utility Group: Utility Group retail revenues are based on rates approved by the state regulatory commissions. These regulated rates are applied to customers’ use of energy to calculate a bill. In general, rates can only be changed through formal proceedings with the state regulatory commissions. However, certain Utility Group companies utilize regulatory commission-approved tracking mechanisms to track the recovery of certain incurred costs. The tracking mechanisms allow for rates to be changed periodically, with overcollections refunded to customers or undercollections collected from customers in future periods.

Utility Group Unbilled Revenues: Unbilled revenues represent an estimate of electricity or gas delivered to customers that has not yet been billed. Unbilled revenues are included in revenue on the statement of (loss)/income and are assets on the balance sheet that are reclassified to accounts receivable in the following month as customers are billed. Such estimates are subject to adjustment when actual meter readings become available, when changes in estimating methodology occur and under other circumstances.

Utility Group Transmission Revenues – Wholesale Rates: Wholesale transmission revenues are based on rates and formulas that are approved by the FERC. Most of NU’s wholesale transmission revenues are collected through a combination of the New England Regional Network Service (RNS) tariff and NU’s Local Network Service (LNS) tariff. The RNS tariff, which is administered by the New England Independent System Operator (ISO-NE), recovers the revenue requirements associated with transmission facilities that are deemed by the FERC to be regional facilities. This regional rate is reset on June 1 of each year. The LNS tariff provides for the recovery of NU’s total transmission revenue requirements, net of revenues received from other sources, including those revenues received under RNS rates. NU’s LNS tariff is reset on January 1 and June 1 of each year. Additionally, NU’s LNS tariff provides for a true-up to actual costs, which ensures that NU recovers its total transmission revenue requirements, including an allowed return on equity (ROE). At December 31, 2005, this true-up has resulted in the recognition of a $2.1 million regulatory liability, including approximately $1.5 million due to NU’s electric distribution companies.

Utility Group Transmission Revenues – Retail Rates: A significant portion of the NU transmission business revenue comes from ISO-NE charges to the distribution businesses of CL&P, PSNH and WMECO. The distribution businesses recover these costs through the retail rates that are charged to their retail customers. For CL&P, any difference between the revenues received from retail customers and the retail transmission expenses charged to the distribution business has historically impacted the distribution business earnings. In July of 2005, CL&P began a process of tracking its retail transmission revenues and expenses and adjusting its retail transmission rates on a regular basis, thereby recovering all of its retail transmission expenses on a timely basis. This ratemaking change resulted from the enactment of the legislation passed by the Connecticut legislature in 2005. WMECO implemented its retail transmission tracker and rate adjustment mechanism in January of 2002 as part of its 2002 rate change filing. PSNH does not currently have a retail transmission rate tracking mechanism.

NU Enterprises: NU Enterprises’ revenues are recognized at different times for its different business lines. Wholesale marketing revenues were recognized when energy was delivered up to and including the first quarter of 2005. Subsequent to March 31, 2005, as a result of going to mark-to-market accounting, these revenues were still recognized when delivered, however, they were reclassified to fuel, purchased and net interchange power. Retail marketing revenues are recognized when energy is delivered. Service revenues are recognized as services are provided, often on a percentage of completion basis.

For further information regarding the recognition of revenue, see Note 1F "Derivative Accounting" to the consolidated financial statements.

Derivative Accounting

SFAS Nos. 133 and 149: In April of 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities," which amended SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 149 incorporated interpretations that were included in previous Derivative Implementation Group guidance, clarified certain conditions, and amended other existing pronouncements. It was effective for contracts entered into or modified after June 30, 2003. Management determined that the adoption of SFAS No. 149 did not change NU’s accounting for wholesale and retail marketing contracts, or the ability of NU Enterprises to elect the normal purchases and sales exception. Certain Utility Group derivative contracts are recorded at fair value as derivative assets and liabilities with offsetting amounts recorded as regulatory liabilities and assets because the contracts are part of providing regulated electric or gas service and because management believes that these amounts will be recovered or refunded in rates.

EITF Issue No. 03-11: In 2003, the FASB ratified the consensus reached by its Emerging Issues Task Force (EITF) in EITF Issue No. 03-11, "Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ as Defined in Issue No. 02-3." The consensus stated that determining whether realized gains and losses on contracts that physically deliver and are not held for trading purposes should be reported on a net or gross basis was a matter of judgment that depended on the relevant facts and circumstances. NU Enterprises and the Utility Group have derivative sales contracts, and though these contracts may result in physical delivery, management has determined, based on the relevant facts and circumstances, that because these transactions are part of the respective companies’ procurement activities, inclusion in operating expenses better depicts these sales activities. For the years ended December 31, 2005, 2004 and 2003, the settlement of these derivative contracts that are not held for trading purposes are reported on a net basis in operating expenses.

For the period April 1, 2005 to December 31, 2005, Select Energy reported the settlement of derivative and non-derivative retail sales and certain other derivative contracts that physically deliver in revenues and the associated derivative and non-derivative contracts to supply these contracts in fuel, purchased and net interchange power. In addition, Select Energy reported the settlement of all derivative wholesale contracts, including full requirements sales contracts in fuel, purchased and net interchange power as a result of applying mark-to-market accounting to those contracts. Certain competitive generation related derivative contracts that are marked-to-market beginning in the fourth quarter of 2005 continue to be recorded in revenues.

Prior to April 1, 2005, Select Energy reported the settlement of long-term derivative contracts, including full requirements sales contracts were physically delivered and were not held for trading purposes on a gross basis, generally with sales in revenues and purchases in expenses. Retail sales contracts were physically delivered and recorded in revenues. Short-term sales and purchases represented power and natural gas that was purchased to serve full requirements contracts but was ultimately not needed based on the actual load of the customers. This excess power and natural gas was sold to the independent system operator or to other counterparties. For the three months ended March 31, 2005 and for the years ended December 31, 2004 and 2003, settlements of these short-term derivative contracts that were not held for trading purposes, were reported on a net basis in fuel, purchased and net interchange power.

Accounting for Energy Contracts: The accounting treatment for energy contracts entered into varies and depends on the intended use of the particular contract and on whether or not the contract is a derivative. Non-derivative contracts such as certain retail sales contracts are recorded at the time of delivery or settlement. Most of the contracts comprising Select Energy’s wholesale marketing and competitive generation activities are derivatives, and certain Utility Group contracts for the purchase or sale of energy or energy-related products are derivatives. Certain retail marketing contracts with retail customers are not derivatives, while virtually all contracts entered into to supply these customers are derivatives. The application of derivative accounting under SFAS No. 133, as amended, is complex and requires management judgment in the following respects: election and designation of the normal purchases and sales exception, identification of derivatives and embedded derivatives, identifying hedge relationships, assessing and measuring hedge ineffectiveness, and determining the fair value of derivatives. All of these judgments, depending upon their timing and effect, can have a significant impact on NU’s consolidated net income.

The judgment applied in the election of the normal purchases and sales exception (and resulting accrual accounting) includes the conclusions that it is probable at the inception of the contract and throughout its term that it will result in physical delivery and that the quantities will be used or sold by the business over a reasonable period in the normal course of business. If facts and circumstances change and management can no longer support this conclusion, then the normal exception and accrual accounting is terminated and fair value accounting is applied. Cash flow hedge contracts that are designated as hedges for contracts for which the company has elected the normal purchases and sales exception can continue to be accounted for as cash flow hedges only if the normal exception for the hedged contract continues to be appropriate. If the normal exception is terminated, then the hedge designation would be terminated at the same time.

Derivative contracts that are entered into for trading purposes are recorded on the consolidated balance sheets at fair value, and changes in fair value are recorded in earnings. Revenues and expenses for these contracts are recorded on a net basis in revenues.

Contracts that are hedging an underlying transaction and that qualify as derivatives that hedge exposure to the variable cash flows of a forecasted transaction (cash flow hedges) are recorded on the consolidated balance sheets at fair value with changes in fair value generally reflected in accumulated other comprehensive income. Cash flow hedges impact earnings when the forecasted transaction being hedged occurs, when hedge ineffectiveness is measured and recorded, when the forecasted transaction being hedged is no longer probable of occurring, or when there is an accumulated other comprehensive loss and when the hedge and the forecasted transaction being hedged are in a loss position on a combined basis. The settlements of cash flow hedges are recorded in the same income statement line item as the forecasted transaction, typically fuel, purchased and net interchange power.

For further information regarding these contracts and their accounting, see Note 6, "Derivative Instruments," to the consolidated financial statements.

Utility Group Regulatory Accounting

The accounting policies of the Utility Group conform to accounting principles generally accepted in the United States of America applicable to rate-regulated enterprises and historically reflect the effects of the rate-making process in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation."

The transmission and distribution businesses of CL&P, PSNH and WMECO, along with PSNH’s generation business and Yankee Gas’ distribution business, continue to be cost-of-service rate regulated, and management believes that the application of SFAS No. 71 to those businesses continues to be appropriate. Management also believes it is probable that NU’s Utility Group companies will recover their investments in long-lived assets, including regulatory assets. In addition, all material net regulatory assets are earning an equity return, except for securitized regulatory assets, which are not supported by equity and substantial portions of the unrecovered contractual obligations regulatory assets. New Hampshire’s electric utility industry restructuring laws have been modified to delay the sale of PSNH’s fossil and hydroelectric generation assets until at least April of 2006. There has been no regulatory action to the contrary, and management currently has no plans to divest these generation assets. As the New Hampshire Public Utilities Commission (NHPUC) has allowed and is expected to continue to allow rate recovery of a return on and recovery of these assets, as well as all operating expenses, PSNH meets the criteria for the application of SFAS No. 71. Generation costs that are not currently recovered in rates are deferred for future recovery. Stranded costs related to generation assets are deferred for recovery as stranded costs under the "Agreement to Settle PSNH Restructuring" (Restructuring Settlement). Part 3 stranded costs are non-securitized regulatory assets that must be recovered by a recovery end date determined in accordance with the Restructuring Settlement or be written off. Based on current projections, PSNH expects to fully recover its Part 3 costs by the middle of 2006.

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


	At December 31,
(Millions of Dollars)	2005	2004
Recoverable nuclear costs	$ 44.1	$ 52.0
Securitized assets	1,340.9	1,537.4
Income taxes, net	332.5	316.3
Unrecovered contractual obligations	327.5	354.7
Recoverable energy costs	193.0	255.0
Other	245.9	230.8
Totals	$2,483.9	$2,746.2

Included in other regulatory assets above of $245.9 million at December 31, 2005 are the regulatory assets recorded associated with the implementation of FIN 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143," totaling $47.3 million. A portion of these regulatory assets totaling $17.3 million has been approved for deferred accounting treatment. At this time, management believes that the remaining regulatory assets are probable of recovery.

Additionally, the Utility Group had $11.2 million and $11.6 million of regulatory costs at December 31, 2005 and 2004, respectively, that are included in deferred debits and other assets – other on the accompanying consolidated balance sheets. These amounts represent regulatory costs that have not yet been approved by the applicable regulatory agency. Management believes these costs are recoverable in future regulated rates.

Recoverable Nuclear Costs: PSNH recorded a regulatory asset in conjunction with the sale of its share of Millstone 3 in March of 2001 with an unamortized balance of $26.1 million and $29.7 million at December 31, 2005 and 2004, respectively, which is included in recoverable nuclear costs. Also included in recoverable nuclear costs at December 31, 2005 and 2004 are $18 million and $22.3 million, respectively, primarily

related to WMECO’s share of Millstone 1 recoverable nuclear costs associated with the undepreciated plant and related assets at the time Millstone 1 was shutdown.

Securitized Assets: In March of 2001, CL&P issued $1.4 billion in rate reduction certificates. CL&P used $1.1 billion of the proceeds from that issuance to buyout or buydown certain contracts with independent power producers (IPP). The unamortized CL&P securitized asset balance is $731.4 million and $850 million at December 31, 2005 and 2004, respectively. CL&P used the remaining proceeds from the issuance of the rate reduction certificates to securitize a portion of its SFAS No. 109, "Accounting for Income Taxes," regulatory asset. The securitized SFAS No. 109 regulatory asset had an unamortized balance of $124.2 million and $144.3 million at December 31, 2005 and 2004, respectively.

In April of 2001, PSNH issued rate reduction bonds in the amount of $525 million. PSNH used the majority of the proceeds from that issuance to buydown its affiliated power contracts with North Atlantic Energy Corporation (NAEC). The unamortized PSNH securitized asset balance is $354.5 million and $392.2 million at December 31, 2005 and 2004, respectively. In January of 2002, PSNH issued an additional $50 million in rate reduction bonds and used the proceeds from that issuance to repay short-term debt that was incurred to buyout a purchased-power contract in December of 2001. The unamortized PSNH securitized asset balance for the January of 2002 issuance is $20.5 million and $29.4 million at December 31, 2005 and 2004, respectively.

In May of 2001, WMECO issued $155 million in rate reduction certificates and used the majority of the proceeds from that issuance to buyout an IPP contract. The unamortized WMECO securitized asset balance is $110.3 million and $121.5 million at December 31, 2005 and 2004, respectively.

Securitized assets are being recovered over the amortization period of their associated rate reduction certificates and bonds. All outstanding CL&P rate reduction certificates are scheduled to fully amortize by December 30, 2010, while PSNH rate reduction bonds are scheduled to fully amortize by May 1, 2013, and WMECO rate reduction certificates are scheduled to fully amortize by June 1, 2013.

Income Taxes, Net: The tax effect of temporary differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of taxable income) is accounted for in accordance with the rate-making treatment of the applicable regulatory commissions and SFAS No. 109. Differences in income taxes between SFAS No. 109 and the rate-making treatment of the applicable regulatory commissions are recorded as regulatory assets which totaled $332.5 million and $316.3 million at December 31, 2005 and 2004, respectively. For further information regarding income taxes, see Note 1H, "Summary of Significant Accounting Policies – Income Taxes," to the consolidated financial statements.

Unrecovered Contractual Obligations: Under the terms of contracts with the Yankee Companies, CL&P, PSNH, and WMECO are responsible for their proportionate share of the remaining costs of the units, including decommissioning. These amounts which totaled $327.5 million and $354.7 million at December 31, 2005 and 2004, respectively, are recorded as unrecovered contractual obligations. A portion of these obligations for CL&P was securitized in 2001 and is included in securitized regulatory assets. Amounts for PSNH and WMECO are being recovered along with other stranded costs. As discussed in Note 9E, "Commitments and Contingencies – Deferred Contractual Obligations," substantial portions of the unrecovered contractual obligations regulatory assets have not yet been approved for recovery. At this time management believes that these regulatory assets are probable of recovery.

Recoverable Energy Costs: Under the Energy Policy Act of 1992 (Energy Act), CL&P, PSNH, WMECO, and NAEC were assessed for their proportionate shares of the costs of decontaminating and decommissioning uranium enrichment plants owned by the United States Department of Energy (DOE) (D&D Assessment). The Energy Act requires that regulators treat D&D Assessments as a reasonable and necessary current cost of fuel, to be fully recovered in rates like any other fuel cost. CL&P, PSNH and WMECO no longer own nuclear generation assets but continue to recover these costs through rates. At December 31, 2005 and 2004, NU’s total D&D Assessment deferrals were $9.8 million and $13.9 million, respectively, and have been recorded as recoverable energy costs. Also included in recoverable energy costs at December 31, 2004 is $32.5 million related to federally mandated congestion charges (FMCC).

In conjunction with the implementation of restructuring under the Restructuring Settlement on May 1, 2001, PSNH’s fuel and purchased power adjustment clause (FPPAC) was discontinued. At December 31, 2005 and 2004, PSNH had $127.5 million and $144.8 million, respectively, of recoverable energy costs deferred under the FPPAC. Under the Restructuring Settlement, the FPPAC deferrals are recovered as a Part 3 stranded cost through a stranded cost recovery charge. Also included in PSNH’s recoverable energy costs are deferred costs associated with certain contractual purchases from IPPs. These costs are also treated as Part 3 stranded costs and amounted to $44 million and $50.1 million at December 31, 2005 and 2004, respectively.

The regulated rates of Yankee Gas include a purchased gas adjustment clause under which gas costs above or below base rate levels are charged to or credited to customers. Differences between the actual purchased gas costs and the current rate recovery are deferred and recovered or refunded in future periods. These amounts are recorded as recoverable energy costs of $11.7 million and $13.7 million at December 31, 2005 and 2004, respectively.

The majority of the recoverable energy costs are currently recovered in rates from the customers of CL&P, PSNH, WMECO, and Yankee Gas. PSNH’s recoverable energy costs are Part 3 stranded costs.

Regulatory Liabilities: The Utility Group had $1.3 billion and $1.1 billion of regulatory liabilities at December 31, 2005 and 2004, respectively, including revenues subject to refund. These amounts are comprised of the following:


	At December 31,
(Millions of Dollars)	2005	2004
Cost of removal	$ 305.5	$ 328.8
CL&P CTA, GSC and SBC overcollections	154.0	200.0
PSNH cumulative deferrals – SCRC	303.3	208.6
Regulatory liabilities offsetting
Utility Group derivative assets	391.2	191.4
Other regulatory liabilities	119.5	141.4
Totals	$1,273.5	$1,070.2

Cost of Removal: Under SFAS No. 71, regulated utilities, including NU’s Utility Group companies, currently recover amounts in rates for future costs of removal of plant assets. These amounts which totaled $305.5 million and $328.8 million at December 31, 2005 and 2004, respectively, are classified as regulatory liabilities on the accompanying consolidated balance sheets.

CL&P CTA, GSC and SBC Overcollections and PSNH Cumulative Deferrals - SCRC: The Competitive Transition Assessment (CTA) allows CL&P to recover stranded costs, such as securitization costs associated with the rate reduction bonds, amortization of regulatory assets, and IPP over market costs. The Generation Service Charge (GSC) allows CL&P to recover the costs of the procurement of energy for standard offer service. The System Benefits Charge (SBC) allows CL&P to recover certain regulatory and energy public policy costs, such as public education outreach costs, hardship protection costs, transition period property taxes, and displaced workers protection costs. CL&P CTA, GSC and SBC overcollections totaled $154 million and $200 million at December 31, 2005 and 2004, respectively. The cumulative e deferrals accrued under the Stranded Cost Recovery Charge (SCRC) totaled $303.3 million and $208.6 million at December 31, 2005 and 2004, respectively, and will decrease the amount of non-securitized stranded costs to be recovered from PSNH’s customers in the future.

Regulatory Liabilities Offsetting Utility Group Derivative Assets: The regulatory liabilities offsetting derivative assets relate to the fair value of CL&P IPP contracts used to purchase power that will benefit ratepayers in the future. These amounts totaled $391.2 million and $191.4 million at December 31, 2005 and 2004, respectively.

Income Taxes

The tax effect of temporary differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of taxable income) is accounted for in accordance with the rate-making treatment of the applicable regulatory commissions and SFAS No. 109.

Details of income tax (benefit)/expense are as follows:


	For the Years Ended December 31,
(Millions of Dollars)	2005	2004	2003
The components of the federal and state income tax provisions are:
Current income taxes:
Federal	$ 15.0	$ (53.5)	$143.3
State	9.1	(6.5)	37.1
Total current	24.1	(60.0)	180.4
Deferred income taxes, net
Federal	(152.6)	120.3	(90.0)
State	(46.5)	(4.8)	(35.9)
Total deferred	(199.1)	115.5	(125.9)
Investment tax credits, net	(3.7)	(3.7)	(3.8)
Income tax expense related to discontinued operations	9.1	30.0	30.8
Income tax (benefit)/expense	$(187.8)	$ 21.8	$ 19.9
A reconciliation between income tax (benefit)/expense and the expected tax (benefit)/expense at the statutory rate is as follows:
Expected federal income tax (benefit)/expense	$(149.0)	$ 60.9	$ 62.1
Tax effect of differences:
Depreciation	(3.5)	5.8	4.0
Amortization of regulatory assets	1.8	1.8	1.8
Investment tax credit amortization	(3.7)	(3.8)	(3.8)
State income taxes, net of federal benefit	(43.4)	(5.4)	0.8
Medicare subsidy	(6.0)	(1.0)	-
Dividends received deduction	(0.3)	(1.2)	(1.4)
Tax asset valuation allowance/reserve adjustments	18.5	1.9	(5.4)
Other, net	6.9	(7.2)	(7.4)
	(178.7)	51.8	50.7
Income tax expense related to discontinued operations	9.1	30.0	30.8
Income tax (benefit)/expense	$(187.8)	$ 21.8	$ 19.9

NU and its subsidiaries file a consolidated federal income tax return. NU and its subsidiaries file state income tax returns, with some filing in more than one state. NU and its subsidiaries are parties to a tax allocation agreement under which taxable subsidiaries pay no more taxes than they would have otherwise paid had they filed a stand-alone tax return and subsidiaries generating tax losses are paid for their losses when utilized.

The tax effects of temporary differences that give rise to the current and long-term net accumulated deferred tax obligations are as follows:


	At December 31,
(Millions of Dollars)	2005	2004
Deferred tax liabilities – current:
Change in fair value of energy contracts	$ 7.3	$ 74.7
Other	35.6	33.0
Total deferred tax liabilities - current	42.9	107.7
Deferred tax assets – current:
Change in fair value of energy contracts	50.7	76.3
Other	15.9	14.7
Total deferred tax assets - current	66.6	91.0
Net deferred tax (assets)/liabilities - current	(23.7)	16.7
Deferred tax liabilities – long-term:
Accelerated depreciation and other plant-related differences	1,120.7	1,105.5
Employee benefits	165.0	169.2
Regulatory amounts:
Securitized contract termination costs and other	223.6	252.1
Income tax gross-up	215.1	215.1
Other	239.3	227.2
Total deferred tax liabilities - long-term	1,963.7	1,969.1
Deferred tax assets – long-term:
Regulatory deferrals	365.8	365.0
Employee benefits	112.0	86.7
Income tax gross-up	34.0	32.6
Other	175.4	63.0
Total deferred tax assets - long-term	687.2	547.3
Less: valuation allowance	29.8	12.6
Net deferred tax assets - long-term	657.4	534.7
Net deferred tax liabilities - long-term	1,306.3	1,434.4
Net deferred tax liabilities	$1,282.6	$1,451.1

At December 31, 2005, NU had state net operating loss carry forwards of $371.6 million that expire between December 31, 2007 and December 31, 2025. At December 31, 2005, NU also had state credit carry forwards of $21.2 million that expire on December 31, 2010.

At December 31, 2004, NU had state net operating loss carry forwards of $206.2 million that expire between December 31, 2006 and December 31, 2024. At December 31, 2004, NU also had state credit carry forwards of $9.3 million that expire on December 31, 2009.

In 2000, NU requested from the Internal Revenue Service (IRS) a Private Letter Ruling (PLR) regarding the treatment of unamortized investment tax credits (ITC) and excess deferred income taxes (EDIT) related to generation assets that have been sold. EDIT are temporary differences between book and taxable income that were recorded when the federal statutory tax rate was higher than it is now or when those differences were expected to be resolved. The PLR addresses whether or not EDIT and ITC can be returned to customers, which without a PLR management believes would represent a violation of current tax law. The IRS declared a moratorium on issuing PLRs until final regulations on the return of EDIT and ITC to regulated customers are issued by the Treasury Department. Proposed regulations were issued in December of 2005 withdrawing proposed regulations issued in March of 2003. The new proposed regulations would generally allow EDIT and ITC generated by property that is no longer regulated to be returned to regulated customers without violating the tax law.

The new proposed regulations would only apply to property that ceases to be regulated public utility property after December of 2005. As such, the EDIT and ITC cannot be used to reduce customer rates. The ultimate results of this contingency could have a positive impact on CL&P’s earnings.

Accounting for R.M. Services, Inc.

NU had an investment in R.M. Services, Inc. (RMS), a provider of consumer collection services. In January of 2003, the FASB issued FIN 46, "Consolidation of Variable Interest Entities," which was effective for NU on July 1, 2003. RMS is a variable interest entity (VIE), as defined. FIN 46, as revised, required that the party to a VIE that absorbs the majority of the VIE’s losses, defined as the "primary beneficiary," consolidate the VIE. Upon adoption of FIN 46 on July 1, 2003, management determined that NU was the "primary beneficiary" of RMS under FIN 46 and that NU was now required to consolidate RMS into its financial statements. To consolidate RMS, NU eliminated the carrying value of its preferred stock investment in RMS and recorded the assets and liabilities of RMS. This adjustment resulted in a negative $4.7 million after-tax cumulative effect of an accounting change in the third quarter of 2003, and the assets and liabilities recorded are summarized as follows (millions of dollars):


Current assets		$ 0.6
Net property, plant and equipment		1.7
Other noncurrent assets		1.5
Current liabilities		(0.6)
		3.2
Elimination of investment at July 1, 2003		(10.5)
Pre-tax cumulative effect of accounting change		(7.3)
Income tax benefit		2.6
Cumulative effect of accounting change		$(4.7)

Prior to the consolidation of RMS on July 1, 2003, NU recorded $1.4 million of pre-tax investment write-downs in 2003. After RMS was consolidated on July 1, 2003, $1.9 million of after-tax operating losses were included in earnings.

On June 30, 2004, NU sold virtually all of the assets and liabilities of RMS for $3 million and recorded a gain on the sale totaling $0.8 million. Prior to the sale, RMS had after-tax operating losses totaling $1 million in 2004. These charges and gains are included in Note 1V, "Summary of Significant Accounting Policies – Other Income, Net," and in the other segment in Note 17, "Segment Information," to the consolidated financial statements.

NU has no other VIE’s for which it is defined as the "primary beneficiary."

Other Investments

NU maintains certain other investments. These investments include Acumentrics Corporation (Acumentrics), a developer of fuel cell and power quality equipment, and BMC Energy LLC (BMC), an operator of renewable energy projects.

Acumentrics: Management determined that the value of NU’s investment in Acumentrics declined in 2004 and that the decline was other than temporary. Total pre-tax investment write-downs of $9.1 million were recorded in 2004 to reduce the carrying value of the investment. During 2004, NU also invested an additional $0.2 million in Acumentrics debt securities. NU’s investment in Acumentrics, which is included in receivables on the accompanying consolidated balance sheets, totaled $0.6 million in debt securities at both December 31, 2005 and 2004.

BMC: In the first quarter of 2004, based on revised information that negatively impacted undiscounted cash flow projections and fair value estimates, management determined that the fair value of the note receivable from BMC had declined and that the note was impaired. As a result, management recorded a pre-tax investment write-down of $2.5 million in the first quarter of 2004. In the second quarter of 2005, based on additional revised information that negatively impacted the fair value of the BMC note receivable, management recorded an additional pre-tax investment write-down of $0.8 million. The remaining note receivable from BMC, which is included in deferred debits and other assets – other on the accompanying consolidated balance sheets, totaled $0.5 million and $1.3 million at December 31, 2005 and 2004, respectively.

The Acumentrics and BMC investment write-downs are included in other income, net on the accompanying consolidated statements of (loss)/income. For further information, see Note 1V, "Summary of Significant Accounting Policies – Other Income, Net," to the consolidated financial statements.

Depreciation

The provision for depreciation on utility assets is calculated using the straight-line method based on the estimated remaining useful lives of depreciable plant-in-service, which range primarily from 3 years to 75 years, adjusted for salvage value and removal costs, as approved by the appropriate regulatory agency where applicable. Depreciation rates are applied to plant-in-service from the time it is placed in service. When plant is retired from service, the original cost of the plant, including costs of removal less salvage, is charged to the accumulated provision for depreciation. Cost of removal is classified as a regulatory liability. The depreciation rates for the several classes of electric utility plant-in-service are equivalent to a composite rate of 3.2 percent in 2005, 3.3 percent in 2004, and 3.4 percent in 2003.

NU also maintains other non-utility plant which is being depreciated using the straight-line method based on their estimated remaining useful lives, which range primarily from 15 years to 120 years.

Jointly Owned Electric Utility Plant

Regional Nuclear Companies: At December 31, 2005, CL&P, PSNH and WMECO own common stock in three regional nuclear companies (Yankee Companies). Each of the Yankee Companies owns a single nuclear generating plant which is being decommissioned. NU’s ownership interests in the Yankee Companies at December 31, 2005, which are accounted for on the equity method, are 49 percent of the Connecticut Yankee Atomic Power Company (CYAPC), 38.5 percent of the Yankee Atomic Electric Company (YAEC), and 20 percent of the Maine Yankee Atomic Power Company (MYAPC). The total carrying value of CYAPC, MYAPC and YAEC, which is included in deferred debits and other assets – other on the accompanying consolidated balance sheets and the Utility Group – electric distribution reportable segment, totaled $28.6 million at both December 31, 2005 and 2004. Earnings related to these equity investments are included in other income, net on the accompanying consolidated statements of (loss)/income. For further information, see Note 1V, "Summary of Significant Accounting Policies – Other Income, Net," to the consolidated financial statements.

CYAPC filed with the FERC to recover the increased estimate of decommissioning and plant closure costs. The FERC proceeding is ongoing. Management believes that the FERC proceeding has not impaired the value of its investment in CYAPC totaling $22.7 million at December 31,

2005 but will continue to evaluate the impacts that the FERC proceeding has on NU’s investment. For further information, see Note 9E, "Commitments and Contingencies – Deferred Contractual Obligations," to the consolidated financial statements.

Hydro-Quebec: NU parent has a 22.7 percent equity ownership interest in two companies that transmit electricity imported from the Hydro-Quebec system in Canada. NU’s investment, which is included in deferred debits and other assets – other on the accompanying consolidated balance sheets, totaled $8.5 million and $9.5 million at December 31, 2005 and 2004, respectively.

Allowance for Funds Used During Construction

The allowance for funds used during construction (AFUDC) is a non-cash item that is included in the cost of Utility Group utility plant and represents the cost of borrowed and equity funds used to finance construction. The portion of AFUDC attributable to borrowed funds is recorded as a reduction of other interest expense and the cost of equity funds is recorded as other income on the accompanying consolidated statements of (loss)/income as follows:


	For the Years Ended December 31,
(Millions of Dollars, except percentages)	2005		2004		2003
Borrowed funds	$10.1		$3.9		$ 3.9
Equity funds	12.3		3.8		6.5
Totals	$22.4		$7.7		$10.4
Average AFUDC rate	5.8	%	3.9	%	4.0	%

The average Utility Group AFUDC rate is based on a FERC-prescribed formula that develops an average rate using the cost of the company’s short-term financings as well as the company’s capitalization (preferred stock, long-term debt and common equity). The average rate is applied to eligible construction work in progress amounts to calculate AFUDC. The increase in the average AFUDC rate during 2005 is primarily due to increases in short-term and long-term debt interest rates.

Equity-Based Compensation

NU maintains an Employee Stock Purchase Plan and other long-term, equity-based incentive plans under the Northeast Utilities Incentive Plan (Incentive Plan). NU accounts for these plans under the recognition and measurement principles of Accounting Principles Board Opinion (APB) No. 25, "Accounting for Stock Issued to Employees," and related interpretations. Equity-based employee compensation cost for stock options is not reflected in net income, as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the date of grant. During the years ended December 31, 2005, 2004 and 2003, no stock options were awarded. The following table illustrates the effect on net income and earnings per share (EPS) if NU had applied the fair value recognition provisions of SFAS No. 123 to equity-based employee compensation:


	For the Years Ended December 31,
(Millions of Dollars, except per share amounts)	2005	2004	2003
Net (loss)/income as reported	$(253.5)	$116.6	$116.4
Add: Equity-based employee compensation expense included in the reported net (loss)/income, net of related tax effects	2.6	2.3	1.2
Net (loss)/income before equity-based compensation	(250.9)	118.9	117.6
Deduct: Total equity-based employee compensation expense determined under the fair value-based method for all awards, net of related tax effects	(1.2)	(2.7)	(2.5)
Pro forma net (loss)/income	$(252.1)	$116.2	$115.1
EPS:
Basic and diluted - as reported	$ (1.93)	$ 0.91	$ 0.91
Basic and diluted - pro forma	$ (1.92)	$ 0.91	$ 0.90

In 2005, NU disclosed the final pro forma expense for stock options granted in 2002 as all stock options were fully vested. The total equity-based employee compensation expense of $1.2 million, $2.7 million, and $2.5 million above includes offsetting amounts of $2.2 million, $0.7 million, and $0.6 million, related to forfeitures of stock options made for the years ended December 31, 2005, 2004, and 2003, respectively.

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

NU accounts for restricted stock and restricted stock units in accordance with APB No. 25 and amortizes the intrinsic value of the stock at the award date over the related service period.

For information regarding new accounting standards issued but not yet adopted associated with equity-based compensation, see Note 1C, "Summary of Significant Accounting Policies – Accounting Standards Issued But Not Yet Adopted," to the consolidated financial statements.

Sale of Receivables

Utility Group: At December 31, 2005 and 2004, CL&P had sold an undivided interest in its accounts receivable of $80 million and $90 million, respectively, to a financial institution with limited recourse through CL&P Receivables Corporation (CRC), a wholly owned subsidiary of CL&P. CRC can sell up to $100 million of an undivided interest in its accounts receivable and unbilled revenues. At December 31, 2005 and 2004, the reserve requirements calculated in accordance with the Receivables Purchase and Sale Agreement were $21 million and $18.8 million, respectively. These reserve amounts are deducted from the amount of receivables eligible for sale. At their present levels, these reserve amounts do not limit CL&P’s ability to access the full amount of the facility. Concentrations of credit risk to the purchaser under this agreement with respect to the receivables are limited due to CL&P’s diverse customer base.

At December 31, 2005 and 2004, amounts sold to CRC by CL&P but not sold to the financial institution totaling $252.8 million and $139.4 million, respectively, are included as investments in securitizable assets on the accompanying consolidated balance sheets. These amounts would be excluded from CL&P’s assets in the event of CL&P’s bankruptcy. On July 6, 2005, CRC renewed its Receivables Purchase and Sale Agreement with CL&P and the financial institution through July 5, 2006. CL&P’s continuing involvement with the receivables that are sold to CRC and the financial institution is limited to the servicing of those receivables.

The transfer of receivables to the financial institution under this arrangement qualifies for sale treatment under SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities – A Replacement of SFAS No. 125."

NU Enterprises: SESI has a master purchase agreement with an unaffiliated third party under which SESI may sell certain monies due or which will become due under delivery orders issued pursuant to United States federal government energy savings performance contracts (energy savings contracts). The sale of a portion of the future cash flows from the energy savings contracts is used to reimburse the costs to construct the energy savings projects. SESI continues to provide performance period services under its contract with the government for the remaining term. The portion of future government payments for performance period services is not sold to the unaffiliated third party or recorded as a receivable until such services are rendered.

At December 31, 2005 and 2004, SESI had sold $38.6 million and $30 million, respectively, of accounts receivable related to the installation of the energy savings projects, with limited recourse, under this master purchase agreement. Under its delivery orders with the government, SESI is responsible for ongoing maintenance and other services related to the energy savings project installation and receives payment for those services in addition to the amounts sold under the master purchase agreement. NU has provided a guarantee that SESI will perform its obligations under the master purchase agreement and subsequent individual assignment agreements. The sale of the receivables to the unaffiliated third party qualifies for sales treatment under SFAS No. 140, and therefore these receivables are not included in NU’s consolidated financial statements.

SESI has entered into assignment agreements to sell an additional $17.9 million of receivables upon completion of the installation of certain savings projects. Until the projects are completed, the receivables are recorded under the percentage of completion method and included in the consolidated financial statements and the advances under the master purchase agreement are recorded as debt.

Asset Retirement Obligations

On January 1, 2003, NU implemented SFAS No. 143, "Accounting for Asset Retirement Obligations," requiring legal obligations associated with the retirement of property, plant and equipment to be recognized as a liability at fair value when incurred and when a reasonable estimate of the fair value of the liability can be made. Management concluded that there were no asset retirement obligations (AROs) to be recorded upon implementation of SFAS No. 143.

In March of 2005, the FASB issued FIN 47, required to be implemented by December 31, 2005. FIN 47 requires an entity to recognize a liability for the fair value of an ARO even if it is conditional on a future event and the liability’s fair value can be reasonably estimated. FIN 47 provides that settlement dates and future costs should be reasonably estimated when sufficient information becomes available, and provides guidance on the definition and timing of sufficient information in determining expected cash flows and fair values. Management has completed its identification of conditional AROs and has identified various categories of AROs, primarily certain assets containing asbestos and hazardous contamination. A fair value calculation, reflecting expected probabilities for settlement scenarios, and a data consistency review across operating companies have been performed.

The earnings impact of this implementation has been reported as a negative cumulative effect of accounting change, net of tax benefit, of $1 million related to NGC and Mt. Tom, which are included in discontinued operations. The Utility Group companies utilized regulatory accounting in accordance with SFAS No. 71 and the amounts are included in other regulatory assets at December 31, 2005. The fair value of the AROs is included in property, plant and equipment and related accretion is recorded as a regulatory asset, with corresponding credits reflecting the ARO liabilities in deferred credits and other liabilities – other, on the accompanying consolidated balance sheet at December 31, 2005. Depreciation of the ARO asset is also included as a regulatory asset with an offsetting amount in accumulated depreciation. The following table presents the fair value of the ARO, the related accumulated depreciation, the regulatory asset, and the ARO liabilities.


	At December 31, 2005
(Millions of Dollars)	Fair Value of ARO Asset	Accumulated Depreciation of ARO Asset	Regulatory Asset	ARO Liabilities
Asbestos	$ 3.9	$(2.1)	$21.0	$(22.8)
Hazardous contamination	7.1	(1.7)	17.4	(22.8)
Other AROs	9.6	(3.9)	8.9	(14.6)
Total Utility Group AROs	$20.6	$(7.7)	$47.3	$(60.2)


A summary of the Utility Group AROs by company is as follows:

	At December 31, 2005
(Millions of Dollars)	Fair Value	Accumulated Depreciation of ARO Asset	Regulatory Asset	ARO Liability
CL&P	$16.8	$(6.0)	$25.1	$(35.9)
PSNH	2.3	(1.2)	17.3	(18.4)
WMECO	1.1	(0.3)	2.4	(3.2)
Yankee Gas	0.4	(0.2)	2.5	(2.7)
Total Utility Group AROs	$20.6	$(7.7)	$47.3	$(60.2)

The following table presents the ARO liabilities as of the dates indicated, as if FIN 47 has been applied for all periods affected (millions of dollars):


	At December 31, 2005	At December 31, 2004	At January 1, 2004
Utility Group	$(60.2)	$(53.5)	$(52.7)
NU Enterprises	(1.7)	(1.7)	(1.6)

The net negative effect on earnings, as if FIN 47 had been applied for all periods affected, is as follows for the years ended December 31, 2005, 2004 and 2003 (millions of dollars):


	2005	2004	2003
Net (loss)/income as reported before cumulative effect of accounting change related to FIN 47	$(252.5)	$116.6	$116.4
Effect of application of FIN 47	(0.1)	(0.1)	(0.1)
Pro forma net (loss)/income before cumulative effect of accounting change related to FIN 47	$(252.6)	$116.5	$116.3
EPS:
Basic and diluted – as reported	$(1.92)	$0.91	$0.91
Basic and diluted – pro forma	$(1.92)	$0.91	$0.91

Materials and Supplies

Materials and supplies include materials purchased primarily for construction, operation and maintenance (O&M) purposes. Materials and supplies are valued at the lower of average cost or market.

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand and short-term cash investments that are highly liquid in nature and have original maturities of three months or less. At the end of each reporting period, overdraft amounts are reclassified from cash and cash equivalents to accounts payable.

Special Deposits

Special deposits represent amounts Select Energy has on deposit with unaffiliated counterparties and brokerage firms in the amounts of $103.8 million and $46.3 million at December 31, 2005 and 2004, respectively. SESI special deposits totaling $10.2 million are included in assets held for sale on the accompanying consolidated balance sheet at December 31, 2005. Special deposits at December 31, 2004 also included $20 million in escrow for SESI that had not been spent on construction projects and $16.3 million in escrow for Yankee Gas, which represented payment for Yankee Gas’ first mortgage bonds that were paid on June 1, 2005.

Restricted Cash – LMP Costs

Restricted cash – LMP costs represents incremental LMP cost amounts that were collected by CL&P and deposited into an escrow account.

Excise Taxes

Certain excise taxes levied by state or local governments are collected by NU from its customers. These excise taxes are accounted for on a gross basis with collections in revenues and payments in expenses. For the years ended December 31, 2005, 2004 and 2003, gross receipts

taxes, franchise taxes and other excise taxes of $112.7 million, $97 million, and $96.8 million, respectively, are included in operating revenues and taxes other than income taxes on the accompanying consolidated statements of (loss)/ income.

Other Income, Net

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


	For the Years Ended December 31,
(Millions of Dollars)	2005	2004	2003
Other Income:
Investment income	$ 19.1	$ 12.2	$ 5.4
CL&P procurement fee	17.8	11.7	-
AFUDC - equity funds	12.3	3.8	6.5
Gain on disposition of property	2.7	3.3	2.6
Return on regulatory deferrals	1.4	1.8	5.8
Conservation and load management incentive	7.7	6.7	2.3
Equity in earnings of regional nuclear generating and transmission companies	3.3	2.6	4.5
Gain on sale of RMS	-	0.8	-
Other	5.9	5.1	3.8
Total Other Income	70.2	48.0	30.9
Other Loss:
Charitable contributions	(4.7)	(4.6)	(9.2)
Investment write-downs	(6.9)	(13.8)	(1.4)
Other	(10.9)	(9.6)	(10.7)
Total Other Loss	(22.5)	(28.0)	(21.3)
Total Other Income, Net	$ 47.7	$20.0	$ 9.6

None of the amounts in either other income – other or other loss – other are individually significant as defined by the SEC.

Supplemental Cash Flow Information


	For the Years Ended December 31,
(Millions of Dollars)	2005	2004	2003
Cash (received)/paid during the year for: Interest, net of amounts capitalized	$276.7	$244.6	$241.3
Income taxes	$(56.1)	$ 74.3	$248.3

In 2005, NU Enterprises sold certain assets of SECI-NH. The sales price included a note receivable of $0.3 million with interest only payments due on the note for the first two years and the principle amount due at the end of two years.

Marketable Securities

SERP and Prior Spent Nuclear Fuel Trusts: NU’s marketable securities are classified as available-for-sale, as defined by SFAS No. 115, "Accounting for Certain Investments and Debt and Equity Securities." Unrealized gains and losses are reported as a component of accumulated other comprehensive income on the consolidated statements of shareholders’ equity. NU currently maintains two trusts that hold marketable securities. The trusts are used to fund NU’s Supplemental Executive Retirement Plan (SERP) and WMECO’s prior spent nuclear fuel liability. Realized gains and losses related to the SERP assets are included in other income, net, on the consolidated statements of (loss)/income. Realized gains/ (losses) associated with the WMECO spent nuclear fuel trust are included in fuel, purchased and net interchange power on the consolidated statements of (loss)/income.

Globix: On July 19, 2004, NEON Communications, Inc. (NEON) and Globix Corporation (Globix) announced a definitive merger agreement in which Globix, an unaffiliated publicly owned entity, would acquire NEON for shares of Globix common stock. Prior to the merger announcement, NU invested $2.1 million in 2004 in exchange for an additional 341,000 shares of NEON common stock. Management calculated the estimated fair value of its investment in NEON based on the Globix share price at December 31, 2004 and the conversion factor. Results of the calculation indicated that the fair value of NU’s investment in NEON was below the carrying value at December 31, 2004 and was impaired. As a result, NU recorded a pre-tax write-down of $2.2 million in 2004.

The merger closed on March 8, 2005, and NU received 1.2748 shares of Globix common stock for each of the 2.1 million shares of NEON stock it owned. In connection with the merger, NU recorded a pre-tax write-down of $0.2 million. After the Globix merger, NU recognized unrealized losses on its Globix investment in accumulated other comprehensive income. During 2005, the value of Globix common stock declined and management reviewed NU’s investment in Globix, considering the length and severity of its decline in value, other factors about the company, and management’s intentions with respect to holding this investment. Based on these factors, management recorded an

additional pre-tax impairment charge in 2005 of $5.9 million to reflect an other-than-temporary impairment. This amount is included in the negative $0.9 million after-tax amount which was reclassified from accumulated other comprehensive income and recognized in earnings in 2005.

NU’s investment in Globix totaled $3.7 million and $9.8 million at December 31, 2005 and 2004, respectively.

For information regarding marketable securities which also includes NU’s investment in Globix, see Note 11, "Marketable Securities," to the consolidated financial statements.

Counterparty Deposits

Balances collected from counterparties resulting from Select Energy’s credit management activities totaled $28.9 million at December 31, 2005 and $57.7 million at December 31, 2004. These amounts are recorded as current liabilities and included as counterparty deposits on the accompanying consolidated balance sheets. To the extent Select Energy requires collateral from counterparties, cash is received as a part of the total collateral required. The right to receive such cash collateral in an unrestricted manner is determined by the terms of Select Energy’s agreements. Key factors affecting the unrestricted status of a portion of this cash collateral include the financial standing of Select Energy and of NU as its credit supporter.

Provision for Uncollectible Accounts

NU maintains a provision for uncollectible accounts to record its receivables at an estimated net realizable value. This provision is determined based upon a variety of factors, including applying an estimated uncollectible account percentage to each receivables aging category, historical collection and write-off experience and management’s assessment of collectibility from individual customers. Management reviews at least quarterly the collectibility of the receivables, and if circumstances change, collectibility estimates are adjusted accordingly. Receivable balances are written-off against the provision for uncollectible accounts when these balances are deemed to be uncollectible.

Wholesale Contract Market Changes

NU recorded $425.4 million of pre-tax wholesale contract market changes for the year ended December 31, 2005, related to the changes in the fair value of wholesale contracts that the company is in the process of exiting. These amounts are reported as wholesale contract market changes, net on the consolidated statements of (loss)/income. These changes are comprised of the following items:

A charge of $406.9 million related to the mark-to-market of certain long-dated wholesale electricity contracts in New England and New York with municipal and other customers. The charge reflects negative mark-to-market movements on these contracts through December 31, 2005 as a result of rising energy prices, partially offset by positive effects of buying out certain obligations in 2005 at prices less than their marks at the time;

A charge of approximately $80 million related to purchases of additional electricity for an increase in the load forecasts related to a full requirements contract with a customer in the Pennsylvania-New Jersey-Maryland (PJM) power pool;

A benefit of approximately $38 million related to mark-to-market gains on certain generation related contracts which the company is in the process of exiting;

A benefit of $59.9 million for mark-to-market gains primarily related to retail supply contracts, by the wholesale business that were previously held to serve certain retail electric load which the company has exited or settled. Included in the $59.9 million is $30 million related to retail supply contracts marked-to-market as a result of the March 9, 2005 decision to exit the wholesale marketing business.

A charge of $36.4 million for mark-to-market contract asset write-offs related to long-term wholesale electricity contracts and a contract termination payment in March of 2005.

A charge of $15.5 million was also recorded in the fourth quarter of 2005 in connection with the decision to exit the competitive generation business related to marking-to-market two contracts to sell the output of its generation in 2007 and 2008 and is included in discontinued operations. NU Enterprises is in the process of exiting these contracts. These two generation sales contracts were formerly accounted for under accrual accounting; however, accrual accounting was terminated in the fourth quarter of 2005 due to the high probability that these contracts would be net settled instead of physically delivered.

For further information regarding these derivative assets and liabilities that are being exited, see Note 6, "Derivative Instruments," to the consolidated financial statements.

Restructuring and Impairment Charges

The company evaluates long-lived assets such as property, plant and equipment to determine if these assets are impaired when events or changes in circumstances occur such as the 2005 announced decisions to exit all of the NU Enterprises businesses.

NU Enterprises recorded $69.2 million of pre-tax restructuring and impairment charges for the year ended December 31, 2005 related to the decision to exit the merchant energy businesses and its energy services businesses. The amounts related to continuing operations are included as restructuring and impairment charges on the consolidated statements of (loss)/income with the remainder included in discontinued operations. These charges are included as part of the NU Enterprises reportable segment in Note 17, "Segment Information," to the consolidated financial statements. A summary of those 2005 pre-tax charges is as follows:


(Millions of Dollars)		Year Ended December 31, 2005
Merchant Energy:
Wholesale Marketing:
Impairment charges		$ 9.7
Restructuring charges		6.7
Subtotal		16.4
Retail Marketing:
Impairment charges		9.2
Competitive Generation:
Impairment charges		1.5
Subtotal - Merchant Energy		27.1

Energy Services and Other:
Impairment charges		39.1
Restructuring charges		3.0
Subtotal - Energy Services and Other		42.1
Total restructuring and impairment charges		69.2
Restructuring and impairment charges included in discontinued operations		25.1
Total restructuring and impairment charges included in continuing operations		$44.1

On March 9, 2005, NU concluded that NU Enterprises’ energy services businesses are not central to NU’s long-term strategy and do not meet the company’s expectations of profitability and as a result, the company concluded that it would explore ways to exit those businesses in a manner that maximizes their value. On November 7, 2005, NU announced its decision to exit the remainder of its merchant energy business segment, which includes the retail marketing and competitive generation business. During 2005, as a result of impairment analyses performed, assets of $9.7 million, $9.2 million and $1.5 million relating to wholesale marketing, retail marketing, and competitive generation businesses, respectively, including goodwill and intangible assets totaling $12.4 million, were determined to be impaired and were written off.

In 2005, NU Enterprises hired an outside firm to assist in valuing its energy services businesses and their exit. Based in part on that firm’s work, the company concluded that $29.1 million of goodwill associated with those businesses and $9.2 million of intangible assets were impaired. Also in 2005, the energy services businesses and NU Enterprises parent recorded an impairment charge of $0.8 million due to the impairment of certain fixed assets.

In 2005, pre-tax restructuring charges totaling $9.7 million of which $6.7 million and $3 million relate to the wholesale marketing and energy services businesses, respectively, were recorded for employee termination costs, consulting fees and other costs. Additional restructuring charges will be recognized as incurred and may include professional fees and employee-related and other costs.

At December 31, 2005, NU determined that no additional impairment existed for the competitive generation business assets based on NU’s evaluation using cash flow methodologies and an analysis of comparable companies or transactions.

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


(Millions of Dollars)	Employee Termination Costs	Consulting Fees	Total
Restructuring liability as of January 1, 2005	$ -	$ -	$ -
Costs incurred	2.3	7.4	9.7
Cash payments	(0.5)	(2.1)	(2.6)
Restructuring liability as of December 31, 2005	$ 1.8	$ 5.3	$ 7.1

Assets Held for Sale and Discontinued Operations

Assets Held for Sale: On March 9, 2005, NU announced the decision to exit NU Enterprises’ energy services businesses. During the third quarter of 2005, management determined that it expected to sell four of its energy services within one year. Two of these businesses, SECI-NH (including Reeds Ferry) and Woods Network, were sold on November 8, 2005 and November 22, 2005, respectively.

Certain assets and liabilities of the energy services businesses are being accounted for as held for sale. These businesses, which are valued at the lower of their carrying amount or fair value less cost to sell, are as follows: SESI, a performance contracting subsidiary that specializes in upgrading the energy efficiency of large governmental and institutional facilities, and Woods Electrical, a subsidiary of NGS which provides third-party electrical services. These businesses are included as part of the NU Enterprises reportable segment in Note 17, "Segment Information," to the consolidated financial statements. The major classes of assets and liabilities that are held for sale at December 31, 2005 are as follows:


(Millions of Dollars)
Special deposits		$ 10.2
Accounts and notes receivable		8.6
Other current assets		1.3
Other assets		2.2
Long-term contract receivables		79.5
Total assets		101.8
Accounts and notes payable		3.0
Other current liabilities		3.2
Long-term debt		86.3
Other liabilities		9.0
Total liabilities		101.5
Net assets		$ 0.3

Discontinued Operations: NU’s consolidated statements of (loss)/income for the years ended December 31, 2005, 2004, and 2003 present the operations for NGC, Mt. Tom, SESI, Woods Electrical, SECI-NH, and Woods Network as discontinued operations as a result of meeting the criteria requiring this presentation. Under this presentation, revenues and expenses of these businesses are classified net of tax in income from discontinued operations on the accompanying consolidated statements of (loss)/ income and all prior periods have been reclassified. These businesses are included as part of the NU Enterprises reportable segment in Note 17, "Segment Information," to the consolidated financial statements. Summarized financial information for the discontinued operations is as follows:


	For the Years Ended December 31,
(Millions of Dollars)	2005	2004	2003
Operating revenue	$326.4	$366.7	$315.3
Income before income tax expense	24.3	76.8	74.7
Loss from sale	(1.1)	-	-
Income tax expense	9.1	30.0	30.8
Income from discontinued operations	$ 14.1	$ 46.8	$ 43.9

On November 8, 2005, NU Enterprises completed the sale of certain assets of SECI-NH (including 100 percent of the common stock of Reeds Ferry) and recognized a pre-tax loss on disposal of $0.3 million. On November 22, 2005, NU Enterprises completed the sale of Woods Network and recognized a pre-tax loss on disposal of $0.8 million. The proceeds from these two sales totaled $6.5 million. The pre-tax losses on disposal associated with the sales of these businesses are included as losses from dispositions in discontinued operations on the accompanying consolidated statement of (loss)/income for the year ended December 31, 2005.

Included in discontinued operations for the years ended December 31, 2005, 2004, and 2003 is $222.2 million, $222 million, and $189.5 million, respectively, of intercompany revenues that are not eliminated in consolidation due to the separate presentation of discontinued operations. At December 31, 2005, NU does not expect that after the disposal it will have significant ongoing involvement or continuing cash flows with the entities presented in discontinued operations.

For further information, see Note 18, "Subsequent Events" to the consolidated financial statements.

Short-Term Debt

Limits: The amount of short-term borrowings that may be incurred by NU and its operating companies is subject to periodic approval by either the SEC, the FERC, or by their respective state regulators. On October 28, 2005 the SEC amended its June 30, 2004 order, granting authorization to allow NU, CL&P, WMECO, and Yankee Gas to incur total short-term borrowings up to a maximum of $700 million, $450 million, $200 million, and $150 million, respectively, through June 30, 2007. The SEC also granted authorization for borrowing through the NU Money Pool (Pool) until June 30, 2007. Although PUHCA was repealed on February 8, 2006, under FERC’s transition rules, all of the existing orders under PUHCA relevant to FERC authority will continue to be in effect until December 31, 2007, except for those related to NU and Yankee Gas, which will have no borrowing limitations after February 8, 2006. CL&P and WMECO will be subject to FERC jurisdiction as to issuing short-term debt after February 8, 2006 and must renew any short-term authority after the PUHCA order expires on December 31, 2007.

PSNH is authorized by the NHPUC to incur short-term borrowings up to a maximum of $100 million. As a result of this NHPUC authorization, PSNH is not required to obtain SEC or FERC approval for its short-term debt borrowings.

The charter of CL&P contains preferred stock provisions restricting the amount of unsecured debt that CL&P may incur. In November of 2003, CL&P obtained authorization from its stockholders to issue unsecured indebtedness with a maturity of less than 10 years in excess of the 10 percent of total capitalization limitation in CL&P’s charter, provided that all unsecured indebtedness would not exceed 20 percent of total capitalization for a ten-year period expiring in March of 2014. On March 18, 2004, the SEC approved this change in CL&P’s charter. As of December 31, 2005, CL&P is permitted to incur $531.9 million of additional unsecured debt.

Utility Group Credit Agreement: On December 9, 2005, CL&P, PSNH, WMECO, and Yankee Gas amended their 5-year unsecured revolving credit facility for $400 million by extending the expiration date by one year to November 6, 2010. CL&P may draw up to $200 million, with PSNH, WMECO and Yankee Gas able to draw up to $100 million each, subject to the $400 million maximum borrowing limit. This total commitment may be increased to $500 million, subject to approval, at the request of the borrower. Under this facility, each company may borrow on a short-term basis or on a long-term basis, subject to regulatory approval. At December 31, 2005, there were no borrowings outstanding under this facility. At December 31, 2004, there were $80 million in borrowings under this credit facility.

NU Parent Credit Agreement: On December 9, 2005, NU amended and restated its 5-year unsecured revolving credit and LOC facility of $500 million to a maximum borrowing limit of $700 million and extended the expiration date by one year to November 6, 2010. The amended facility provides a total commitment of $700 million which is available for advances, subject to an LOC sub-limit. Subject to the advances outstanding, LOCs may be issued in notional amounts up to $550 million for periods up to 364 days. The agreement provides for LOCs to be issued in the name of NU or any of its subsidiaries. This total commitment may be increased to $800 million, subject to approval, at the request of the borrower. Under this facility, NU can borrow either on a short-term or a long-term basis. At December 31, 2005 and 2004, there were $32 million and $100 million, respectively, in borrowings under this credit facility. In addition, there were $253 million and $48.9 million in LOCs outstanding at December 31, 2005 and 2004, respectively.

Under these credit agreements, NU and its subsidiaries may borrow at variable rates plus an applicable margin based upon certain debt ratings, as rated by the higher of Standard and Poor’s (S&P) or Moody’s Investors Service (Moody’s). The weighted average interest rates on NU’s notes payable to banks outstanding on December 31, 2005 and 2004, were 7.25 percent and 4.53 percent, respectively.

Under these credit agreements, NU and its subsidiaries must comply with certain financial and non-financial covenants, including but not limited to consolidated debt ratios. The parties to the credit agreements currently are and expect to remain in compliance with these covenants.

Amounts outstanding under these credit facilities are classified as current liabilities as notes payable to banks on the accompanying consolidated balance sheets as management anticipates that all borrowings under these credit facilities will be outstanding for no more than 364 days at one time.

Other Credit Facility: On June 30, 2005, Boulos, a subsidiary of NGS, renewed its $6 million line of credit. This credit facility replaced a similar credit facility that expired on June 30, 2005 and unless extended, will expire on June 30, 2006. This credit facility limits Boulos’ ability to pay dividends if borrowings are outstanding and limits access to the Pool for additional borrowings. At December 31, 2005 and 2004, there were no borrowings under this credit facility.

Derivative Instruments

Contracts that are derivatives and do not meet the definition of a cash flow hedge and are not elected as normal purchases or normal sales are recorded at fair value with changes in fair value included in earnings. For those contracts that meet the definition of a derivative and meet the cash flow hedge requirements, the changes in the fair value of the effective portion of those contracts are generally recognized in accumulated other comprehensive income until the underlying transactions occur. The ineffective portion of contracts that meet the cash flow hedge requirements is recognized currently in earnings. Derivative contracts designated as fair value hedges and the item they are hedging are both recorded at fair value with changes in fair value of both items recognized currently in earnings. Derivative contracts that are elected and meet the requirements of a normal purchase or sale are recognized in revenues or expenses, as applicable, when the quantity of the contract is delivered.

For the year ended December 31, 2005, $3.2 million, net of tax, was reclassified to expense from accumulated other comprehensive income in connection with the consummation of the underlying hedged transactions and recognized in earnings, and a $2.4 million, net of tax, was reclassified to expense from accumulated other comprehensive income related to the mark-to-market changes for wholesale contracts that NU Enterprises is in the process of exiting. During 2005, new cash flow hedge transactions were entered into that hedge cash flows through 2010. As a result of the consummation of the above transactions and market value changes since January 1, 2005, and new transactions entered into during the year, accumulated other comprehensive income increased by $21.7 million, net of tax. Accumulated other comprehensive income at December 31, 2005 was a positive $18.2 million, net of tax (increase to equity), relating to hedged transactions and it is estimated that a positive $19.6 million included in this net of tax balance will be reclassified as an increase to earnings in the next twelve months. Cash flows from hedge contracts are reported in the same category as cash flows from the underlying hedged transaction.

A negative pre-tax $3.4 million was recognized in earnings in 2005 for the ineffective portion of fair value hedges; at the same time a positive $1.2 million was recorded in earnings for the change in fair value of the hedged natural gas inventory. The changes in the fair value of both the fair value hedges and the natural gas inventory being hedged totaling a negative pre-tax $2.2 million was recorded in fuel, purchased, and net interchange power on the accompanying consolidated statements of (loss)/income.

The table below summarizes current and long-term derivative assets and liabilities at December 31, 2005. At December 31, 2005, derivative assets and liabilities have been segregated between wholesale, retail, generation and hedging amounts. As a result of the March 9, 2005 and November 7, 2005 combined decisions to exit these businesses, the fair value of these contracts may not represent amounts that will be realized.


	At December 31, 2005
(Millions of Dollars)	Assets		Liabilities
	Current	Long- Term	Current	Long- Term	Net Total
NU Enterprises:
Wholesale	$256.6	$103.5	$(369.3)	$(220.9)	$(230.1)
Retail	35.3	-	(18.3)	-	17.0
Generation	9.2	-	(5.1)	(15.5)	(11.4)
Hedging	19.7	12.9	(8.9)	0.4	24.1
Utility Group – Gas:
Non-trading	0.1	-	(0.4)	-	(0.3)
Utility Group – Electric:
Non-trading	82.6	308.6	(0.5)	(31.8)	358.9
NU Parent:
Hedging	-	-	-	(5.2)	(5.2)
Totals	$403.5	$425.0	$(402.5)	$(273.0)	$ 153.0

The business activities of NU Enterprises that result in the recognition of derivative assets include exposures to credit risk to energy marketing and trading counterparties. At December 31, 2005, Select Energy had $437.2 million of derivative assets from wholesale, retail, generation, and hedging activities that are exposed to counterparty credit risk. However, a significant portion of these assets is contracted with investment grade rated counterparties or collateralized with cash.

The table below summarizes current and long-term derivative assets and liabilities at December 31, 2004. Prior to the decision to exit the wholesale and retail marketing businesses and the competitive generation business, these current and long-term derivative assets and liabilities were classified as trading, non-trading and hedging derivative assets and liabilities. For NU Enterprises, current and long-term derivative assets totaled $55.6 million and $31.7 million, respectively, while current and long-term derivative liabilities totaled $125.8 million and $15.9 million, respectively, at December 31, 2004.


	At December 31, 2004
(Millions of Dollars)	Assets		Liabilities
	Current	Long- Term	Current	Long- Term	Net Total
NU Enterprises:
Trading	$49.6	$ 31.7	$ (46.2)	$ (5.5)	$ 29.6
Non-trading	1.5	-	(70.5)	(9.6)	(78.6)
Hedging	4.5	-	(9.1)	(0.8)	(5.4)
Utility Group – Gas:
Non-trading	0.2	-	(0.1)	-	0.1
Hedging	1.5	-	-	-	1.5
Utility Group – Electric
Non-trading	24.2	167.1	(4.4)	(42.8)	144.1
NU Parent:
Hedging	0.1	-	-	-	0.1
Totals	$81.6	$198.8	$(130.3)	$(58.7)	$ 91.4

The amounts above do not include option premiums paid, which are recorded as prepayments and amounted to $29.3 million related to wholesale activities at December 31, 2004. These amounts also do not include option premiums received, which are recorded as other current liabilities and amounted to $27.1 million related to wholesale activities at December 31, 2004.

NU Enterprises – Wholesale: Certain electricity and natural gas derivative contracts are part of Select Energy’s wholesale marketing business that the company is in the process of exiting. These contracts also include other wholesale short-term and long-term electricity supply and sales contracts, which include contracts to sell electricity to utilities under full requirements contracts and contracts to sell electricity to municipalities with terms up to eight remaining years. The fair value of electricity contracts was determined by prices from external sources for years through 2009 and by models based on natural gas prices and a heat-rate conversion factor to electricity for subsequent periods. The fair value of the natural gas contracts was primarily determined by prices provided by external sources and actively quoted markets. In addition, to gather market intelligence and utilize this information in risk management activities for the wholesale marketing activities, Select Energy conducted limited energy trading activities in electricity, natural gas, and oil. Select Energy manages open trading positions with strict policies that limit its exposure to market risk and require daily reporting to management of potential financial exposures.

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

(loss)/income in the period of change. The net fair value position of the wholesale portfolio at December 31, 2005 was a liability of $230.1 million.

NU Enterprises – Retail: Select Energy is in the process of exiting its retail business. Select Energy generally acquires retail customers in smaller increments than it acquired wholesale customers, which while requiring careful sourcing, allows energy purchases to be acquired in smaller increments with lower risk. However, fluctuations in prices, fuel costs, competitive conditions, regulations, weather, transmission costs, lack of market liquidity, plant outages and other factors can all impact the retail marketing business adversely from time to time. The retail sales contracts are generally executory contracts where revenues are recorded when the electricity or gas is delivered.

From time to time, the retail marketing business enters into contracts that do not immediately meet the criteria for the normal election and accrual accounting. Therefore, changes in fair value are required to be marked-to-market in earnings and included in the consolidated balance sheets as derivative assets or liabilities. Changes in fair value are recognized in fuel, purchased and net interchange power in the consolidated statements of (loss)/income in the period of change. The net fair value position of the retail portfolio at December 31, 2005 was an asset of $17 million.

Select Energy’s retail portfolio also includes New York Mercantile Exchange (NYMEX) futures, financial swaps, and physical power transactions, the fair value of which is based on closing exchange prices; over-the-counter forwards, and financial swaps, the fair value of which is based on the mid-point of bid and ask market prices; bilateral contracts for the purchase or sale of electricity or natural gas, the fair value of which is determined using available information from external sources; and financial transmission rights and transmission congestion contracts, the fair value of which is based on historical settlement prices as well as external sources.

NU Enterprises – Generation: Select Energy is in the process of exiting these generation contracts. These derivative contracts include generation asset-specific sales and forward sales of electricity at hub trading points. The fair value of generation contracts was determined by prices from external sources for years through 2009 and by models based on natural gas prices and a heat-rate conversion factor to electricity for subsequent periods. The fair value of the natural gas contracts was primarily determined by prices provided by external sources and actively quoted markets. As a result of NU’s decision to exit the competitive generation business in the fourth quarter of 2005, Select Energy began to record all derivatives related to generation activities, with the exception of intercompany transactions, at fair value which are included in the consolidated balance sheets as derivative assets or liabilities as the company could no longer assert probability of physical delivery. Changes in fair value are recognized in revenues in the consolidated statements of (loss)/income in the period of change for the contacts that were recorded at fair value beginning in the first quarter of 2005, while changes in fair value of contracts formerly accounted for on an accrual basis are included in discontinued operations. The net fair value position of the generation derivative contract portfolio at December 31, 2005 was a liability of $11.4 million.

NU Enterprises – Hedging: Select Energy utilizes derivative financial and commodity instruments, including futures and forward contracts, to reduce market risk associated with fluctuations in the price of electricity and natural gas purchased to meet firm sales and purchase commitments to certain retail customers. Select Energy also utilizes derivatives, including price swap agreements, call and put option contracts, and futures and forward contracts to manage the market risk associated with a portion of its anticipated supply and delivery requirements. These derivatives have been designated as cash flow hedging instruments and are used to reduce the market risk associated with fluctuations in the price of electricity or natural gas. A derivative that hedges exposure to the variable cash flows of a forecasted transaction (a cash flow hedge) is initially recorded at fair value with changes in fair value recorded in accumulated 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.

Select Energy maintains natural gas service agreements with certain retail customers to supply gas at fixed prices for terms extending through 2010. Select Energy has hedged its gas supply risk under these agreements through NYMEX futures contracts. Under these contracts, which also extend through 2010, the purchase price of a specified quantity of gas is effectively fixed over the term of the gas service agreements. At December 31, 2005 the NYMEX futures contracts had notional values of $210.5 million and were recorded at fair value as derivative assets totaling $8.2 million and derivative liabilities of $0.3 million.

Select Energy also maintains various physical and financial instruments to hedge its electric and gas purchases and sales through April of 2008. These instruments include forwards, futures and swaps. These hedging contracts, which are valued at the mid-point of bid and ask market prices, were recorded as derivative assets of $24.4 million and derivative liabilities of $4.8 million at December 31, 2005.

Select Energy hedges certain amounts of natural gas inventory with gas futures which are accounted for as fair value hedges. Changes in the fair value of hedging instruments and natural gas inventory are recorded in earnings. The change in fair value of the futures were included in derivative liabilities and amounted to $3.4 million at December 31, 2005. The change in fair value of the hedged natural gas inventory was recorded as an increase to fuel, materials and supplies of $1.2 million at December 31, 2005.

Utility Group – Gas – Non-Trading: Yankee Gas’ non-trading derivatives consist of peaking supply arrangements to serve winter load obligations and firm retail sales contracts with options to curtail delivery. These contracts are subject to fair value accounting because these contracts are derivatives that cannot be designated as normal purchases or sales, because of the optionality in the contract terms. Non-trading derivatives at December 31, 2005 included assets of $0.1 million and liabilities of $0.4 million. At December 31, 2004, non-trading derivatives included assets of $0.2 million and liabilities of $0.1 million.

Utility Group – Electric – Non-Trading: CL&P has two IPP contracts to purchase power that contain pricing provisions that are not clearly and closely related to the price of power and therefore do not qualify for the normal purchases and sales exception. The fair values of these IPP

non-trading derivatives at December 31, 2005 include a derivative asset with a fair value of $391.2 million and a derivative liability with a fair value of $32.3 million. An offsetting regulatory liability and an offsetting regulatory asset were recorded, as these contracts are part of the stranded costs, and management believes that these costs will continue to be recovered or refunded in rates. At December 31, 2004, the fair values of these IPP non-trading derivatives included a derivative asset with a fair value of $191.3 million and a derivative liability with a fair value of $47.2 million.

NU Parent – Hedging: In March of 2003, NU parent entered into a fixed to floating interest rate swap on its $263 million, 7.25 percent fixed rate note that matures on April 1, 2012. As a matched-terms fair value hedge, the changes in fair value of the swap and the hedged debt instrument are recorded on the consolidated balance sheets but are equal and offsetting in the consolidated statements of (loss)/income. The cumulative change in the fair value of the hedged debt of $5.2 million is included as a decrease to long-term debt on the consolidated balance sheets. The hedge is recorded as a derivative liability of $5.2 million at December 31, 2005, and as a derivative asset of $0.1 million at December 31, 2004. The resulting changes in interest payments made are recorded as adjustments to interest expense.

Employee Benefits

Pension Benefits and Postretirement Benefits Other Than Pensions

Pension Benefits: NU’s subsidiaries participate in a uniform noncontributory defined benefit retirement plan (Pension Plan) covering substantially all regular NU employees. Benefits are based on years of service and the employees’ highest eligible compensation during 60 consecutive months of employment. NU uses a December 31st measurement date for the Pension Plan. Pension (income)/expense attributable to earnings is as follows:


	For the Years Ended December 31,
(Millions of Dollars)	2005	2004	2003
Total pension expense/(income)	$54.2	$ 8.0	$(31.8)
Amount capitalized as utility plant	(11.5)	2.6	15.4
Total pension expense/(income), net of amounts capitalized	$42.7	$10.6	$(16.4)

Amounts above include pension curtailments and termination benefits expense of $11.7 million in 2005 and $2.1 million in 2004.

Pension Curtailments and Termination Benefits: As a result of the decision to pursue a fundamentally different business strategy, and align the structure of the company to support this business strategy, NU recorded a $2.7 million pre-tax curtailment expense in 2005. NU also accrued certain related termination benefits and recorded a $2.8 million pre-tax charge in 2005.

There were no curtailments or termination benefits in 2003 that impacted earnings.

Market-Related Value of Pension Plan Assets: NU bases the actuarial determination of pension plan expense or income on a market-related valuation of assets, which reduces year-to-year volatility. This market-related valuation calculation recognizes investment gains or losses over a four-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the fair value of assets. Since the market-related valuation calculation recognizes gains or losses over a four-year period, the future value of the market-related assets will be impacted as previously deferred gains or losses are recognized.

Postretirement Benefits Other Than Pensions: NU’s subsidiaries also provide certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired employees (PBOP Plan). These benefits are available for employees retiring from NU who have met specified service requirements. For current employees and certain retirees, the total benefit is limited to two times the 1993 per retiree health care cost. These costs are charged to expense over the estimated work life of the employee. NU uses a December 31^st measurement date for the PBOP Plan.

NU annually funds postretirement costs through external trusts with amounts that have been and will continue to be recovered in rates and which also are tax deductible. Currently, there are no pending regulatory actions regarding postretirement benefit costs and there are no postretirement benefit costs that are deferred as regulatory assets.

Impact of New Medicare Changes on PBOP: On December 8, 2003, the President signed into law a bill that expands Medicare, primarily by adding a prescription drug benefit starting in 2006 for Medicare-eligible retirees as well as a federal subsidy to plan sponsors of retiree health care benefit plans who provide a prescription drug benefit at least actuarially equivalent to the new Medicare benefit.

Based on the current PBOP Plan provisions, NU qualifies for this federal subsidy because the actuarial value of NU’s PBOP Plan exceeds the threshold required for the subsidy. The Medicare changes decreased the PBOP benefit obligation by $27 million. The total $27 million decrease is currently being amortized as a reduction to PBOP expense over approximately 13 years. For the years ended December 31, 2005 and 2004, this reduction in PBOP expense totaled approximately $3.6 million, including amortization of the actuarial gain of $2 million and a reduction in interest cost and service cost based on a lower PBOP benefit obligation of $1.6 million.

PBOP Curtailments and Termination Benefits: NU recorded an estimated $3.7 million pre-tax curtailment expense at December 31, 2005 relating to NU’s change in business strategy. NU also accrued a $0.5 million pre-tax termination benefit at December 31, 2005 relating to certain benefits provided under the terms of the PBOP Plan. There were no curtailments or termination benefits in 2004 or 2003.

The following table represents information on the plans’ benefit obligation, fair value of plan assets, and the respective plans’ funded status:


	At December 31,
	Pension Benefits		Postretirement Benefits
(Millions of Dollars)	2005	2004	2005	2004
Change in benefit obligation
Benefit obligation at beginning of year	$(2,133.2)	$(1,941.3)	$(468.3)	$(405.0)
Service cost	(48.7)	(40.7)	(8.0)	(6.0)
Interest cost	(125.6)	(118.9)	(25.2)	(25.3)
Actuarial loss	(148.7)	(136.7)	(32.7)	(68.7)
Benefits paid - excluding lump sum payments	109.1	105.0	38.9	36.7
Benefits paid - lump sum payments	0.1	1.5	-	-
Curtailment/impact of plan changes	63.6	-	2.0	-
Termination benefits	(2.8)	(2.1)	(0.5)	-
Benefit obligation at end of year	$(2,286.2)	$(2,133.2)	$(493.8)	$(468.3)
Change in plan assets
Fair value of plan assets at beginning of year	$ 2,075.5	$ 1,945.1	$ 199.8	$ 178.0
Actual return on plan assets	156.3	236.9	12.1	16.8
Employer contribution	-	-	49.9	41.7
Benefits paid - excluding lump sum payments	(109.1)	(105.0)	(38.9)	(36.7)
Benefits paid - lump sum payments	(0.1)	(1.5)	-	-
Fair value of plan assets at end of year	$ 2,122.6	$ 2,075.5	$ 222.9	$ 199.8
Funded status at December 31^st	$ (163.6)	$ (57.7)	$(270.9)	$(268.5)
Unrecognized transition obligation	0.5	0.4	78.6	94.8
Unrecognized prior service cost	40.5	56.3	(4.1)	(5.2)
Unrecognized net loss	421.1	353.7	179.9	166.5
Prepaid/(accrued) benefit cost	$ 298.5	$ 352.7	$ (16.5)	$ (12.4)

The $63.6 million reduction in the plan’s obligation that is included in the curtailment/impact of plan changes relates to the reduction in the future years of service expected to be rendered by plan participants. This reduction is the result of the transition of employees into the new 401(k) benefit and the company’s decision to pursue a fundamentally different business strategy, and align the structure of the company to support this business strategy. This overall reduction in plan obligation serves to reduce the previously unrecognized actuarial losses.

The company amortizes its unrecognized transition obligation over the remaining service lives of its employees as calculated on an individual operating company basis. The company amortizes the unrecognized prior service cost and unrecognized net loss over the remaining service lives of its employees as calculated on a company-wide basis.

The accumulated benefit obligation for the Pension Plan was $2.061 billion and $1.850 billion at December 31, 2005 and 2004, respectively.

The following actuarial assumptions were used in calculating the plans’ year end funded status:


	At December 31,
	Pension Benefits				Postretirement Benefits
Balance Sheets	2005		2004		2005		2004
Discount rate	5.80	%	6.00	%	5.65	%	5.50	%
Compensation/progression rate	4.00	%	4.00	%	N/A		N/A
Health care cost trend rate	N/A		N/A		7.00	%	8.00	%

The components of net periodic expense/(income) are as follows:


	For the Years Ended December 31,
	Pension Benefits			Postretirement Benefits
(Millions of Dollars)	2005	2004	2003	2005	2004	2003
Service cost	$ 48.7	$ 40.7	$ 35.1	$ 8.0	$ 6.0	$ 5.3
Interest cost	125.6	118.9	117.0	25.2	25.3	26.8
Expected return on plan assets	(172.0)	(175.1)	(182.5)	(12.3)	(12.5)	(14.9)
Amortization of unrecognized net transition (asset)/obligation	(0.3)	(1.5)	(1.5)	11.8	11.9	11.9
Amortization of prior service cost	7.1	7.2	7.2	(0.4)	(0.4)	(0.4)
Amortization of actuarial loss/(gain)	33.4	15.7	(7.1)	-	-	-
Other amortization, net	-	-	-	17.5	11.4	6.4
Net periodic expense/(income) – before curtailments and termination benefits	42.5	5.9	(31.8)	49.8	41.7	35.1
Curtailment expense	8.9	-	-	3.7	-	-
Termination benefits expense	2.8	2.1	-	0.5	-	-
Total curtailments and termination benefits	11.7	2.1	-	4.2	-	-
Total - net periodic expense/(income)	$ 54.2	$ 8.0	$(31.8)	$54.0	$ 41.7	$ 35.1

For calculating pension and postretirement benefit expense and income amounts, the following assumptions were used:


	For the Years Ended December 31,
Statements of Income	Pension Benefits						Postretirement Benefits
	2005		2004		2003		2005		2004		2003
Discount rate	6.00	%	6.25	%	6.75	%	5.50	%	6.25	%	6.75	%
Expected long-term rate of return	8.75	%	8.75	%	8.75	%	N/A		N/A		N/A
Compensation/progression rate	4.00	%	3.75	%	4.00	%	N/A		N/A		N/A
Expected long-term rate of return -
Health assets, net of tax	N/A		N/A		N/A		6.85	%	6.85	%	6.85	%
Life assets and non-taxable health assets	N/A		N/A		N/A		8.75	%	8.75	%	8.75	%

The following table represents the PBOP assumed health care cost trend rate for the next year and the assumed ultimate trend rate:


	Year Following December 31,
	2005		2004
Health care cost trend rate assumed for next year	10.00	%	7.00	%
Rate to which health care cost trend rate is assumed to decline (the ultimate trend rate)	5.00	%	5.00	%
Year that the rate reaches the ultimate trend rate	2011		2007

At December 31, 2004, the health care cost trend assumption was assumed to decrease by one percentage point each year through 2007. For December 31, 2005 disclosure purposes, the health care cost trend assumption was reset for 2006 at 10 percent, decreasing one percentage point per year to an ultimate rate of 5 percent in 2011.

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. The effect of changing the assumed health care cost trend rate by one percentage point in each year would have the following effects:


(Millions of Dollars)	One Percentage Point Increase	One Percentage Point Decrease
Effect on total service and interest cost components	$ 0.9	$ (0.8)
Effect on postretirement benefit obligation	$18.0	$(15.6)

NU’s investment strategy for its Pension Plan and PBOP Plan is to maximize the long-term rate of return on those plans’ assets within an acceptable level of risk. The investment strategy establishes target allocations, which are routinely reviewed and periodically rebalanced.

NU’s expected long-term rates of return on Pension Plan assets and PBOP Plan assets are based on these target asset allocation assumptions and related expected long-term rates of return. In developing its expected long-term rate of return assumptions for the Pension Plan and the PBOP Plan, NU also evaluated input from actuaries and consultants, as well as long-term inflation assumptions and NU’s historical 20-year compounded return of approximately 11 percent. The Pension Plan’s and PBOP Plan’s target asset allocation assumptions and expected long-term rate of return assumptions by asset category are as follows:


	At December 31,
	Pension Benefits		Postretirement Benefits
	2005 and 2004		2005 and 2004
Asset Category	Target Asset Allocation	Assumed Rate of Return	Target Asset Allocation	Assumed Rate of Return
Equity securities:
United States	45%	9.25%	55%	9.25%
Non-United States	14%	9.25%	11%	9.25%
Emerging markets	3%	10.25%	2%	10.25%
Private	8%	14.25%	-	-
Debt Securities:
Fixed income	20%	5.50%	27%	5.50%
High yield fixed income	5%	7.50%	5%	7.50%
Real estate	5%	7.50%	-	-

The actual asset allocations at December 31, 2005 and 2004 approximated these target asset allocations. The plans’ actual weighted-average asset allocations by asset category are as follows:


	At December 31,
	Pension Benefits		Postretirement Benefits
Asset Category	2005	2004	2005	2004
Equity securities:
United States	46%	47%	54%	55%
Non-United States	16%	17%	14%	14%
Emerging markets	4%	3%	1%	1%
Private	5%	4%	-	-
Debt Securities:
Fixed income	19%	19%	29%	28%
High yield fixed income	5%	5%	2%	2%
Real estate	5%	5%	-	-
Totals	100%	100%	100%	100%

Estimated Future Benefit Payments: The following benefit payments, which reflect expected future service, are expected to be paid for the Pension and PBOP Plans:


(Millions of Dollars)
Year	Pension Benefits	Postretirement Benefits	Government Subsidy
2006	$111.1	$ 44.1	$ 4.3
2007	114.2	45.0	4.6
2008	117.3	44.7	4.9
2009	120.6	44.4	5.2
2010	124.3	44.2	5.5
2011-2015	690.4	217.0	33.1

Government subsidy represents amounts expected to be received from the federal government for the new Medicare prescription drug benefit under the PBOP Plan.

Contributions: NU does not expect to make any contributions to the Pension Plan in 2006 and expects to make $49.5 million in contributions to the PBOP Plan in 2006.

Currently, NU’s policy is to annually fund an amount at least equal to that which will satisfy the requirements of the Employee Retirement Income Security Act and Internal Revenue Code.

Postretirement health plan assets for non-union employees are subject to federal income taxes.

401(k) Savings Plan

NU maintains a 401(k) Savings Plan for substantially all NU employees. This savings plan provides for employee contributions up to specified limits. NU matches employee contributions up to a maximum of three percent of eligible compensation with one percent cash and two percent NU common shares. The 401(k) matching contributions of cash and NU common shares made by NU were $10.7 million in 2005, $10.5 million in 2004 and $9.9 million in 2003.

Employee Stock Ownership Plan

NU maintains an Employee Stock Ownership Plan (ESOP) for purposes of allocating shares to employees participating in NU’s 401(k) Savings Plan. Under this arrangement, NU issued unsecured notes during 1991 and 1992 totaling $250 million, the proceeds of which were loaned to

the ESOP trust (ESOP Notes) for the purchase of 10.8 million newly issued NU common shares (ESOP shares). The ESOP trust is obligated to make principal and interest payments to NU on the ESOP Notes at the same rate that ESOP shares are allocated to employees. NU makes annual contributions to the ESOP trust equal to the ESOP’s debt service, less dividends received by the ESOP. NU’s contributions to the ESOP trust totaled $11.2 million in 2005, $12 million in 2004 and $14.7 million in 2003. Interest expense on the unsecured notes was $3.3 million, $5.7 million and $7.6 million in 2005, 2004 and 2003, respectively. For the years ended December 31, 2005, 2004 and 2003, NU recognized $7.7 million, $7.3 million and $6.9 million, respectively, of expense related to the ESOP, excluding the interest expense on the unsecured notes.

All dividends received by the ESOP on unallocated shares are used to pay debt service and are not considered dividends for financial reporting purposes. During the first and second quarters of 2004, NU paid a $0.15 per share quarterly dividend. During the third quarter of 2004 through the second quarter of 2005, NU paid a $0.1625 per share quarterly dividend. NU paid a $0.175 per share dividend during the third and fourth quarters of 2005.

In 2005 and 2004, the ESOP trust issued 590,173 and 567,907 of NU common shares, respectively, to satisfy 401(k) Savings Plan obligations to employees. At December 31, 2005 and 2004, total allocated ESOP shares were 8,773,884 and 8,183,711, respectively, and total unallocated ESOP shares were 2,026,301 and 2,616,474, respectively. The fair market value of the unallocated ESOP shares at December 31, 2005 and 2004, was $39.9 and $49.3 million, respectively.

Equity-Based Compensation

Impact of SFAS No. 123R: See Note 1C, "Summary of Significant Accounting Policies – Accounting Standards Issued But Not Yet Adopted," for information on the implementation of SFAS No. 123R.

Employee Share Purchase Plan (ESPP): NU maintains an ESPP for all eligible employees. Under the ESPP, NU common shares were purchased at six-month intervals at 85 percent of the lower of the price on the first or last day of each six-month period. Employees may purchase shares having a value not exceeding 25 percent of their compensation as of the beginning of the purchase period. During 2005 and 2004, employees purchased 209,184 and 194,838 shares, respectively, at discounted prices of $15.85 and $15.90 in 2005 and $14.17 and $15.90 in 2004. At December 31, 2005 and 2004, 1,181,219 shares and 1,390,403 shares remained registered for future issuance under the ESPP, respectively.

Effective February 1, 2006, the ESPP was amended to change the discount rate to five percent of the market price and the pricing date was changed to the last day of the purchase period. As a result, the ESPP will qualify as a non-compensatory plan under SFAS No. 123R, which is effective on January 1, 2006 for NU. This amendment may also reduce the number of shares purchased under the ESPP.

Incentive Plans: Under the Incentive Plan, NU is authorized to grant various types of awards, including restricted stock, performance units, restricted stock units, and stock options to eligible employees and board members. The number of shares that may be utilized for grants and awards during a given calendar year may not exceed the aggregate of one percent of the total number of NU common shares outstanding as of the first day of that calendar year and the shares not utilized in previous years. At December 31, 2005 and 2004, NU had 906,154 and 1 1,361,528 shares of common stock, respectively, registered for issuance under the Incentive Plan.

Restricted Stock and Restricted Stock Units: NU granted 304,724 restricted stock units during 2005 and 25,000 restricted shares and 382,395 restricted stock units during 2004. The restricted stock units granted had a fair value of $5.8 million and $7.4 million in 2005 and 2004, respectively. The restricted stock granted in 2004 had a fair value of $0.4 million. NU currently accounts for restricted stock and restricted stock units in accordance with APB No. 25 and amortizes the intrinsic value of the stock at the award date over the related service period using the straight-line method. Awards granted in 2005, 2004, and 2003 were subject to three and four-year graded vesting periods. During 2005, 2004 and 2003, $4.3 million, $3.8 million and $2 million, respectively, was expensed related to restricted stock and restricted stock units.

Performance Units: Under the Incentive Plan, NU also granted 38,996, 30,122, and 35,303 performance units during 2005, 2004 and 2003, respectively. The performance units are valued at $100 at target and vest ratably over three years and will be paid in cash at the end of the vesting period. NU records a liability for the performance units based on the achievement of the performance unit goals. A liability of $2.9 million and $3.2 million, which is included in other current liabilities on the accompanying consolidated balance sheets, was recorded at December 31, 2005 and 2004, respectively, for these performance units. During 2005, 2004 and 2003, $0.3 million, $1.7 million and $0.2 million, respectively, was recorded as an expense related to these performance units.

Stock Options: Prior to 2003, NU granted stock options to certain employees. The exercise price of stock options, as set at the time of grant, was equal to the fair market value per share at the date of grant, and therefore no equity-based compensation cost was reflected in net income. A summary of stock option transactions is as follows:


		Exercise Price Per Share
	Options	Range			Weighted Average
Outstanding - December 31, 2002	3,837,309	$ 9.6250	-	$22.2500	$16.8738
Exercised	(562,982)	$ 9.6250	-	$19.5000	$14.6223
Forfeited and cancelled	(151,005)	$14.9375	-	$21.0300	$19.0227
Outstanding – December 31, 2003	3,123,322	$ 9.6250	-	$22.2500	$17.1270
Exercised	(612,666)	$ 9.6250	-	$19.5000	$12.3181
Forfeited and cancelled	(516,914)	$16.5500	-	$19.5000	$16.6139
Outstanding - December 31, 2004	1,993,742	$14.9375	-	$22.2500	$18.7370
Exercised	(368,192)	$14.9375	-	$20.0600	$12.7262
Forfeited and cancelled	(503,009)	$18.4375	-	$21.0300	$18.1703
Outstanding - December 31, 2005	1,122,541	$14.9375	-	$22.2500	$18.4484
Exercisable - December 31, 2003	2,027,413	$ 9.6250	-	$22.2500	$16.6969
Exercisable - December 31, 2004	1,877,595	$14.9375	-	$22.2500	$18.7778
Exercisable - December 31, 2005	1,122,541	$14.9375	-	$22.2500	$18.4484

For certain options that were granted in 2002, the vesting schedule for these options is ratably over three years from the date of grant. Additionally, certain options granted in 2002 vest 50 percent at the date of grant and 50 percent one year from the date of grant, while other options granted in 2002 vest 100 percent after five years.

The fair value of each stock option grant has been estimated on the date of grant using the Black-Scholes option pricing model and is used to calculate the pro forma net (loss)/income and EPS over the service period, as disclosed in Note 1N, "Summary of Significant Accounting Policies - Equity-Based Compensation," to the consolidated financial statements. No stock options were granted during 2005, 2004 or 2003. The weighted average remaining contractual lives for the options outstanding at December 31, 2005 is 4.89 years.

For information regarding the adoption of SFAS No. 123R on January 1, 2006, equity-based compensation, see Note 1C, "Summary of Significant Accounting Policies - Accounting Standards Issued But Not Yet Adopted," to the consolidated financial statements.

Supplemental Executive Retirement and Other Plans

NU has maintained a SERP since 1987. The SERP provides its participants, who are executives of NU, with benefits that would have been provided to them under NU’s retirement plan if certain Internal Revenue Code and other limitations were not imposed. The SERP liability of $26 million and $24.2 million at December 31, 2005 and 2004, respectively, which is included in deferred credits and other liabilities – other on the accompanying consolidated balance sheets, represents NU’s actuarially determined obligation under the SERP. During 2005, 2004 and 2003, $3.7 million, $4 million, and $3.9 million, respectively, was expensed related to the SERP.

The SERP is the only NU retirement plan for which a minimum pension liability has been recorded. Recording this minimum pension liability resulted in a negative $0.4 million in accumulated other comprehensive income at December 31, 2005.

NU maintains a plan for retirement and other benefits for certain current and past company officers. The actuarially-determined liability for this plan which is included in deferred credits and other liabilities – other on the accompanying consolidated balance sheets, was $37.4 million and $36.7 million at December 31, 2005 and 2004, respectively. During 2005, 2004 and 2003, $4.5 million, $4.5 million and $6.3 million, respectively, was expensed related to this plan.

For information regarding SERP investments that are used to fund the SERP liability, see Note 11, "Marketable Securities," to the consolidated financial statements.

Severance Benefits

The restructuring charges and liabilities described in Note 3, "Restructuring and Impairment Charges," do not include severance costs related to employee terminations as a result of the decision to pursue a fundamentally different business strategy and align the structure of the company to support this business strategy. These charges, totaling $16.9 million were recorded as other operating expenses on the accompanying consolidated statement of (loss)/income for the year ended December 31, 2005.

Goodwill and Other Intangible Assets

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

NU’s reporting units that maintained goodwill are generally consistent with the operating segments underlying the reportable segments identified in Note 17, "Segment Information," to the consolidated financial statements. Consistent with the way management reviews the operating results of its reporting units, NU’s reporting unit under the NU Enterprises reportable segment that maintains goodwill is the merchant energy reporting unit. The merchant energy reporting unit is comprised of the operations of Select Energy, NGC and the generation operations of HWP (Mt. Tom) and NGS. The other reporting unit that maintains goodwill is the Yankee Gas reporting unit, which was classified under the Utility Group – gas reportable segment. The goodwill recorded related to the acquisition of Yankee Gas is not being recovered from the

customers of Yankee Gas. A summary of NU’s goodwill balances at December 31, 2005 and 2004 by reportable segment and reporting units is as follows:


	At December 31,
(Millions of Dollars)	2005	2004
Utility Group – Gas:
Yankee Gas	$287.6	$287.6
NU Enterprises:
Merchant Energy	-	3.2
Energy Services	-	29.1
Totals	$287.6	$319.9

As a result of NU’s 2005 announcements to exit the competitive wholesale and retail marketing businesses, the competitive generation business and the energy services businesses, certain goodwill balances and intangible assets were deemed to be impaired. The goodwill balances in the NU Enterprises merchant energy and energy services businesses were determined to be impaired in their entirety, and $3.2 million and $29.1 million, respectively, in write-offs were recorded.

The retail marketing business had an exclusivity agreement with an unamortized balance of $7.2 million and a customer list asset with an unamortized balance of $2 million that were also deemed to be impaired and were written off. Additionally, the energy services businesses intangible assets not subject to amortization were also impaired, and an $8.5 million pre-tax write-off was recorded, while an additional pre-tax $0.7 million of other intangible assets were also impaired. These charges related to continuing operations are included in restructuring and impairment charges on the accompanying consolidated statements of (loss)/income and in the NU Enterprises reportable segment in Note 17, "Segment Information," to the consolidated financial statements, with the remainder included in discontinued operations.

NU recorded amortization expenses of $1.7 million, $3.6 million and $3.7 million for the years ended December 31, 2005, 2004 and 2003, respectively, related to these intangible assets prior to these write-offs.

NU completed its impairment analysis of the Yankee Gas goodwill balance as of October 1, 2005, and has determined that no impairment exists. In completing this analysis, the fair value of the reporting unit was estimated using both discounted cash flow methodologies and an analysis of comparable companies or transactions.

At December 31, 2005, NU Enterprises’ remaining intangible assets totaled $0.1 million and relate to the energy services businesses which are expected to be sold.

Commitments and Contingencies

Regulatory Developments and Rate Matters

Connecticut:

A final decision in the 2004 CTA and SBC docket was issued on December 19, 2005 by the DPUC. That decision ordered a refund to customers of $100.8 million over the twelve-month period beginning with January 2006 consumption. In a subsequent decision in CL&P’s docket to establish the 2006 transitional standard offer (TSO) rates dated December 28, 2005, the DPUC ordered CL&P to issue a revised CTA refund of $108 million over the twelve-month period beginning with January 2006 consumption and an additional CTA refund of $40 million for the months of January, February and March of 2006.

Purchased Gas Adjustment: On September 9, 2005 the DPUC issued a draft decision regarding Yankee Gas Purchased Gas Adjustment (PGA) clause charges for the period of September 1, 2003 through August 31, 2004. The draft decision disallowed approximately $9 million in previously recovered PGA revenues associated with two separate Yankee Gas unbilled sales and revenue adjustments. At the request of Yankee Gas, the DPUC reopened the PGA hearings on September 20, 2005 and requested that Yankee Gas file supplemental information regarding the two adjustments. Yankee Gas complied with this request. The remaining schedule for the proceeding has not yet been established. If upheld, this disallowance would result in a $9 million pre-tax write-off. Management believes the unbilled sales and revenue adjustments and resultant charges to customers through the PGA clause were appropriate. Based on the facts of the case and the

supplemental information provided to the DPUC, management believes the appropriateness of the PGA charges to customers for the time period under review will be approved.

New Hampshire:

SCRC Reconciliation Filing: The SCRC allows PSNH to recover its stranded costs. On an annual basis, PSNH files with the NHPUC a SCRC reconciliation filing for the preceding calendar year. This filing includes the reconciliation of stranded cost revenues and costs and Transition Energy Service Rate and Default Energy Service Rate, collectively referred to as Energy Service Rate (ES) revenues and costs. The NHPUC reviews the filing, including a prudence review of the operations within PSNH’s generation business segment. The cumulative deferral of SCRC revenues in excess of costs was $303.3 million at December 31, 2005. This cumulative deferral will decrease the amount of non-securitized stranded costs to be recovered from PSNH’s customers in the future from $368 million to $64.7 million.

The 2004 SCRC reconciliation filing was filed with the NHPUC on May 2, 2005. In October of 2005, PSNH, the NHPUC staff and the New Hampshire Office of Consumer Advocate (OCA) reached a settlement agreement in this case. The major provisions of this settlement agreement include the following: 1) PSNH will be allowed to recover its 2004 ES costs and stranded costs without disallowances, 2) PSNH will be allowed to include its cumulative unbilled revenues in its ES and stranded cost reconciliations and 3) the NHPUC will defer any action regarding PSNH’s coal supply and transportation procedures until it completes a review using an outside expert. The NHPUC issued its order on December 22, 2005, approving the settlement agreement as filed. While management believes its coal procurement and transportation policies and procedures are prudent and consistent with industry practice, it is unable to determine the impact, if any, of the expected NHPUC review on PSNH’s net income or financial position.

Litigation with IPPs: Two wood-fired IPPs that sell their output to PSNH under long-term rate orders issued by the NHPUC brought suit against PSNH in state superior court. The IPPs and PSNH dispute the end dates of the above-market long-term rates set forth in the respective rate orders. Subsequent to the IPP’s court filing, PSNH petitioned the NHPUC to decide this matter, and requested that the court stay its proceeding pending the NHPUC’s decision. By court order dated October 20, 2005, the court granted PSNH’s motion to stay indicating that the NHPUC had primary jurisdiction over this matter.

Massachusetts:

Transition Cost Reconciliation: On March 31, 2005, WMECO filed its 2004 transition cost reconciliation with the Massachusetts Department of Telecommunications and Energy (DTE). The DTE has combined the 2003 transition cost reconciliation filing, standard offer service and default service reconciliation, the transmission cost adjustment filing, and the 2004 transition cost reconciliation filing into a single proceeding. The timing of a decision in the combined proceeding is uncertain, but management does not expect the outcome to have a material adverse impact on WMECO’s net income or financial position.

Environmental Matters

General: NU is subject to environmental laws and regulations intended to mitigate or remove the effect of past operations and improve or maintain the quality of the environment. These laws and regulations require the removal or the remedy of the effect on the environment of the disposal or release of certain specified hazardous substances at current and former operating sites. As such, NU has an active environmental auditing and training program and believes that it is substantially in compliance with all enacted laws and regulations.

Environmental reserves are accrued using a probabilistic model approach when assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated. The probabilistic model approach estimates the liability based on the most likely action plan from a variety of available remediation options, including, no action is required or several different remedies ranging from establishing institutional controls to full site remediation and monitoring.

These estimates are subjective in nature as they take into consideration several different remediation options at each specific site. The reliability and precision of these estimates can be affected by several factors including new information concerning either the level of contamination at the site, recently enacted laws and regulations or a change in cost estimates due to certain economic factors.

The amounts recorded as environmental liabilities on the consolidated balance sheets represent management’s best estimate of the liability for environmental costs and takes into consideration site assessment and remediation costs. Based on currently available information for estimated site assessment and remediation costs at December 31, 2005 and 2004, NU had $30.7 million and $38.7 million, respectively, recorded as environmental reserves. A reconciliation of the activity in these reserves at December 31, 2005 and 2004 is as follows:


	For the Years Ended December 31,
(Millions of Dollars)	2005	2004
Balance at beginning of year	$38.7	$40.8
Additions and adjustments	4.2	6.4
Payments	(12.2)	(8.5)
Balance at end of year	$30.7	$38.7

Of the 52 sites NU has currently included in the environmental reserve, 26 sites are in the remediation or long-term monitoring phase, 20 sites have had some level of site assessments completed and the remaining 6 sites are in the preliminary stages of site assessment.

For 9 sites that are included in the company’s liability for environmental costs, the information known and nature of the remediation options at those sites allows for an estimate of the range of losses to be made. These sites primarily relate to manufactured gas plant (MGP) sites. At December 31, 2005, $7 million has been accrued as a liability for these sites, which represents management’s best estimate of the liability for environmental costs. This amount differs from an estimated range of loss from $0.3 million to $23.4 million as management utilizes the probabilistic model approach to make its estimate of the liability for environmental costs. For the 43 remaining sites for which an estimate is based on the probabilistic model approach, determining an estimated range of loss is not possible.

These liabilities are estimated on an undiscounted basis and do not assume that any amounts are recoverable from insurance companies or other third parties. The environmental reserve includes sites at different stages of discovery and remediation and does not include any unasserted claims.

At December 31, 2005, there are 11 sites for which there are unasserted claims; however, any related remediation costs are not probable or estimable at this time. NU’s environmental liability also takes into account recurring costs of managing hazardous substances and pollutants, mandated expenditures to remediate previously contaminated sites and any other infrequent and non-recurring clean up costs.

It is possible that new information or future developments could require a reassessment of the potential exposure to related environmental matters. As this information becomes available, management will continue to assess the potential exposure and adjust the reserves accordingly.

MGP Sites: MGP sites comprise the largest portion of NU’s environmental liability. MGPs are sites that manufactured gas from coal which produced certain byproducts that may pose a risk to human health and the environment. At December 31, 2005 and 2004, $25.3 million and $33.2 million, respectively, represents amounts for the site assessment and remediation of MGPs. At December 31, 2005 and 2004, the five largest MGP sites comprise approximately 64 percent and 58 percent, respectively, of the total MGP environmental liability.

On January 19, 2005, the DPUC issued a final decision approving the sale proceeding of a former MGP site that was held for sale at December 31, 2004. The final decision approved the price of $24 million for the sale of the land and also approved the deferral of the gain in the amount of $14 million ($8.4 million net of tax). At December 31, 2004, NU had $7.9 million related to remediation efforts at the property and other sale costs recorded in other deferred debits and other assets – other on the accompanying consolidated balance sheets. During 2005, the former MGP site was sold to an independent third party.

CERCLA Matters: The Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA) and its amendments or state equivalents impose joint and several strict liabilities, regardless of fault, upon generators of hazardous substances resulting in removal and remediation costs and environmental damages. Liabilities under these laws can be material and in some instances may be imposed without regard to fault or for past acts that may have been lawful at the time they occurred. NU has four superfund sites under CERCLA for which it has been notified that it is a potentially responsible party (PRP). For sites where there are other PRPs and NU’s subsidiaries are not managing the site assessment and remediation, the liability accrued represents NU’s estimate of what it will pay to settle its obligations with respect to the site.

It is possible that new information or future developments could require a reassessment of the potential exposure to related environmental matters. As this information becomes available management will continue to assess the potential exposure and adjust the reserves accordingly.

Rate Recovery: PSNH and Yankee Gas have rate recovery mechanisms for environmental costs. CL&P recovers a certain level of environmental costs currently in rates but does not have an environmental cost recovery tracking mechanism. Accordingly, changes in CL&P’s environmental reserves impact CL&P’s earnings. WMECO does not have a regulatory mechanism to recover environmental costs from its customers, and changes in WMECO’s environmental reserves also impact WMECO’s earnings.

Spent Nuclear Fuel Disposal Costs

Under the Nuclear Waste Policy Act of 1982 (the Act), CL&P, PSNH, WMECO, and NAEC must pay the DOE for the disposal of spent nuclear fuel and high-level radioactive waste. The DOE is responsible for the selection and development of repositories for, and the disposal of, spent nuclear fuel and high-level radioactive waste. For nuclear fuel used to generate electricity prior to April 7, 1983 (Prior Period Fuel) for CL&P and WMECO, an accrual has been recorded for the full liability, and payment must be made prior to the first delivery of spent fuel to the DOE.

Until such payment is made, the outstanding balance will continue to accrue interest at the 3-month treasury bill yield rate. At December 31, 2005 and 2004, fees due to the DOE for the disposal of Prior Period Fuel were $267.8 million and $259.7 million, respectively, including interest costs of $185.7 million and $177.6 million, respectively.

During 2004, WMECO established a trust, which holds marketable securities to fund amounts due to the DOE for the disposal of WMECO’s Prior Period Fuel. For further information on this trust, see Note 11, "Marketable Securities," to the consolidated financial statements.

Long-Term Contractual Arrangements

Utility Group:

Vermont Yankee Nuclear Power Corporation (VYNPC): Previously under the terms of their agreements, NU’s companies paid their ownership (or entitlement) shares of costs, which included depreciation, O&M expenses, taxes, the estimated cost of decommissioning, and a return on invested capital to VYNPC and recorded these costs as purchased-power expenses. On July 31, 2002, VYNPC consummated the sale of its nuclear generating unit to a subsidiary of Entergy Corporation for approximately $180 million. CL&P, PSNH and WMECO have commitments to buy approximately 16 percent of the VYNPC plant’s output through March of 2012 at a range of fixed prices. The total cost of purchases under contracts with VYNPC amounted to $25.7 million in 2005, $26.8 million in 2004 and $29.9 million in 2003.

Electricity Procurement Contracts: CL&P, PSNH and WMECO have entered into various arrangements for the purchase of electricity. The total cost of purchases under these arrangements amounted to $275.3 million in 2005, $323.3 million in 2004 and $283.4 million in 2003. These amounts relate to IPP contracts and do not include contractual commitments related to CL&P’s transitional standard offer or standard offer, PSNH’s short-term power supply management or WMECO’s basic and default service.

Natural Gas Procurement Contracts: Yankee Gas has entered into long-term contracts for the purchase of a specified quantity of natural gas in the normal course of business as part of its portfolio to meet its actual sales commitments. The majority of these contracts have expiration dates in 2006 and 2007. The total cost of Yankee Gas’ procurement portfolio, including these contracts, amounted to $321.2 million in 2005, $250.5 million in 2004 and $218.6 million in 2003.

Portland Natural Gas Transmission System (PNGTS) Pipeline Commitments: PSNH has a contract for capacity on the PNGTS pipeline which extends through 2018. The total cost under this contract amounted to $1.6 million in 2005, $2 million in 2004 and $1.9 million in 2003. These costs are not recovered from PSNH’s retail customers.

Hydro-Quebec: Along with other New England utilities, CL&P, PSNH, WMECO, and HWP have entered into agreements to support transmission and terminal facilities to import electricity from the Hydro-Quebec system in Canada. CL&P, PSNH, WMECO, and HWP are obligated to pay, over a 30-year period ending in 2020, their proportionate shares of the annual O&M expenses and capital costs of those facilities The total cost of these agreements amounted to $21.2 million in 2005, $23.7 million in 2004 and $25.3 million in 2003.

Transmission Business Project Commitments: These amounts represent commitments for various services and materials associated with CL&P’s Bethel, Connecticut to Norwalk, Connecticut and the Middletown, Connecticut to Norwalk, Connecticut projects and other projects.

Yankee Gas Liquefied Natural Gas (LNG) Storage Facility: In 2004, Yankee Gas signed a contract for the design and building of the LNG facility. Yankee Gas anticipates that the facility will become operational in time for the 2007/2008 heating season. Certain future estimated construction expenditures totaling $16 million are not included in the contract signed to build the LNG facility and are not included in the table of estimated future annual Utility Group costs below.

Northern Wood Power Project: In October of 2004, PSNH received the approvals necessary to begin construction related to the conversion of one of three 50 MW units at the coal-fired Schiller Station to burn wood (Northern Wood Power Project). Construction of the $75 million Northern Wood Power Project began in 2004 and significant construction has been completed. Certain other estimated construction expenditures totaling $3.8 million are not included in the contracts signed for the Northern Wood Power Project and are not included in the table of estimated future annual Utility Group costs below.

Yankee Companies FERC-Approved Billings, Subject to Refund: NU has significant decommissioning and plant closure cost obligations to the Yankee Companies. Each plant has been shut down and is undergoing decommissioning. The Yankee Companies collect decommissioning and closure costs through wholesale, FERC-approved rates charged under power purchase agreements with several New England utilities, including NU’s electric utility companies. These companies in turn pass these costs on to their customers through state regulatory commission approved retail rates. YAEC and MYAPC received FERC approval to collect all presently estimated decommissioning and closure costs. On November 23, 2005, YAEC submitted an application to the FERC to increase YAEC’s wholesale decommissioning charges. On January 31, 2006, the FERC issued an order accepting the rate increase, effective February 1, 2006, subject to refund after hearings and settlement judge proceedings. CYAPC received an order on August 30, 2004 from the FERC allowing collection of its decommissioning and closure costs, subject to refund. The table of estimated future annual Utility Group costs below includes the estimated decommissioning and closure costs for YAEC, MYAPC and CYAPC.

Estimated Future Annual Utility Group Costs: The estimated future annual costs of the Utility Group’s significant long-term contractual arrangements at December 31, 2005 are as follows:


(Millions of Dollars)	2006	2007	2008	2009	2010	Thereafter
VYNPC	$ 28.6	$ 27.5	$ 27.8	$ 30.2	$ 29.2	$ 37.1
Electricity procurement contracts	336.3	267.4	230.4	200.7	179.2	930.5
Natural gas procurement contracts	239.6	103.3	38.0	37.5	37.1	73.0
PNGTS pipeline commitments	2.0	2.0	2.0	2.0	2.0	15.9
Hydro-Quebec	23.4	22.3	22.1	21.9	21.9	216.9
Transmission business project commitments	173.8	7.0	7.0	7.0	-	-
Yankee Gas LNG facility	41.9	4.0	-	-	-	-
Northern Wood Power Project	6.5	-	-	-	-	-
Yankee Companies FERC-approved billings, subject to refund	95.1	75.4	65.4	61.7	60.6	-
Totals	$947.2	$508.9	$392.7	$361.0	$330.0	$1,273.4

NU Enterprises:

Select Energy Purchase Agreements: Select Energy maintains long-term agreements to purchase energy as part of its portfolio of resources to meet its actual or expected sales commitments. These sales commitments were formerly accounted for on the accrual basis but are now recorded at their mark-to-market value.

Contract Assignment Agreement: During the fourth quarter of 2005, Select Energy settled a wholesale contract for $55.9 million with payments commencing in January of 2006 and ending in December of 2008. If certain conditions are met, these payments could be accelerated.

NGC Northfield Mountain Commitment: NGC has a commitment to purchase a spare main transformer to be delivered in the summer of 2006 for on-site storage. The transformer will cost $4 million and will replace one of the two existing in-service transformers.

HWP Project Commitments: In March of 2005, HWP notified Massachusetts environmental regulators that it planned to install a selective catalytic reduction system at the 146 MW Mt. Tom coal-fired station in Holyoke, Massachusetts. The $14 million project commenced in July of 2005 and is expected to be completed by mid-2006. Amounts spent on this project through December 31, 2005 totaled $9.9 million.

HWP Coal Commitments: In July of 2005, HWP entered into a $50.4 million contract to purchase coal to fuel the Mt. Tom coal-fired station in Holyoke, Massachusetts. Obligations under this contract will commence in 2006.

Estimated Future Annual NU Enterprises Costs: The estimated future annual costs of NU Enterprises’ significant contractual arrangements are as follows:


(Millions of Dollars)	2006	2007	2008	2009	2010	Thereafter
Select Energy purchase agreements	$2,226.1	$657.0	$281.1	$20.3	$18.2	$5.0
Contract assignment agreement	18.5	18.3	19.1	-	-	-
NGC Northfield Mountain commitment	4.0	-	-	-	-	-
HWP project commitments	4.1	-	-	-	-	-
HWP coal commitments	2.3	22.9	22.9	2.3	-	-
Totals	$2,255.0	$698.2	$323.1	$22.6	$18.2	$5.0

Select Energy’s purchase contract amounts exceed the amount expected to be reported in fuel, purchased and net interchange power because energy trading transactions are classified in revenues. Select Energy also maintains certain wholesale energy commitments whose mark-to-market values have been recorded on the consolidated balance sheets as derivative assets and liabilities. The aggregate amount of these purchase contracts was $2.6 billion at December 31, 2005.

The amounts and timing of the costs associated with Select Energy’s purchase agreements could be impacted by the exit from NU Enterprises’ merchant energy business.

Deferred Contractual Obligations

FERC Proceedings: In 2003, CYAPC increased the estimated decommissioning and plant closure costs for the period 2000 through 2023 by approximately $395 million over the April 2000 estimate of $436 million approved by the FERC in a 2000 rate case settlement. The revised estimate reflects the increases in the projected costs of spent fuel storage, increased security and liability and property insurance costs, and the fact that CYAPC is now self performing all work to complete the decommissioning of the plant due to the termination of the decommissioning contract with Bechtel Power Corporation (Bechtel) in July of 2003. NU’s share of CYAPC’s increase in decommissioning and plant closure costs is approximately $194 million.

On July 1, 2004, CYAPC filed with the FERC for recovery seeking to increase its annual decommissioning collections from $16.7 million to $93 million for a six-year period beginning on January 1, 2005. On August 30, 2004, the FERC issued an order accepting the rates, with collection beginning on February 1, 2005, subject to refund.

rate increase of approximately $395 million. NU’s share of the DPUC’s recommended disallowance would be between $110 million to $115 million. The FERC staff also filed testimony that recommended a $38 million decrease in the requested rate increase claiming that CYAPC should have used a different gross domestic product (GDP) escalator. NU’s share of this recommended decrease is $18.6 million.

The company cannot at this time predict the timing or outcome of the FERC proceeding required for the collection of the increased CYAPC decommissioning costs. The company believes that the costs have been prudently incurred and will ultimately be recovered from the customers of CL&P, PSNH and WMECO. However, there is a risk that some portion of these increased costs may not be recovered, or will have to be refunded if recovered, as a result of the FERC proceedings.

On June 10, 2004, the DPUC and the Connecticut Office of Consumer Counsel (OCC) filed a petition seeking a declaratory order that CYAPC be allowed to recover all decommissioning costs from its wholesale purchasers, including CL&P, PSNH and WMECO, but that such purchasers may not be allowed to recover in their retail rates any costs that the FERC might determine to have been imprudently incurred. On August 30, 2004, the FERC denied this petition. On September 29, 2004, the DPUC and OCC asked the FERC to reconsider the petition and on October 20, 2005, the FERC denied the reconsideration, holding that the sponsor companies are only obligated to pay CYAPC for prudently incurred decommissioning costs and the FERC has no jurisdiction over the sponsors’ rates to their retail customers. On December 12, 2005, the DPUC sought review of these orders by the United States Court of Appeals for the D.C. Circuit. The FERC and CYAPC have asked the court to dismiss the case and the DPUC has objected to a dismissal. NU cannot predict the timing or the outcome of these proceedings.

Spent Nuclear Fuel Litigation: CYAPC, YAEC and MYAPC also commenced litigation in 1998 charging that the federal government breached contracts it entered into with each company in 1983 under the Act. Under the Act, the DOE was to begin removing spent nuclear fuel from the nuclear plants of the Yankee Companies no later than January 31, 1998 in return for payments by each company into the nuclear waste fund. No fuel has been collected by the DOE, and spent nuclear fuel is stored on the sites of the Yankee Companies’ plants. The Yankee Companies collected the funds for payments into the nuclear waste fund from wholesale utility customers under FERC-approved contract rates. The wholesale utility customers in turn collect these payments from their retail electric customers. The Yankee Companies’ individual damage claims attributed to the government’s breach ranging from $523 million to $543 million are specific to each plant and include incremental storage, security, construction and other costs through 2010. The CYAPC damage claim ranges from $186 million to $198 million, the YAEC damage claim ranges from $177 million to $185 million and the MYAPC damage claim is $160 million. The DOE trial ended on August 31, 2004 and a verdict has not been reached. Post-trial findings of facts and final briefs were filed by the parties in January of 2005. The Yankee Companies’ current rates do not include an amount for recovery of damages in this matter. Management can predict neither the outcome of this matter nor its ultimate impact on NU.

YAEC: In November of 2005, YAEC established an updated estimate of the cost of completing the decommissioning of its plant resulting in an increase of approximately $85 million. NU’s share of the increase in estimated costs is $32.7 million. This estimate reflects the cost of completing site closure activities from October of 2005 forward and storing spent nuclear fuel and other high level waste on site until 2020. This estimate projects a total cost of $192.1 million for the completion of decommissioning and long-term fuel storage. To fund these costs, on November 23, 2005, YAEC submitted an application to the FERC to increase YAEC’s wholesale decommissioning charges. The DPUC and the Massachusetts attorney general protested these increases. On January 31, 2006, the FERC issued an order accepting the rate increase, effective February 1, 2006, subject to refund after hearings and settlement judge proceedings. The hearings have been suspended pending settlement discussions between YAEC, the FERC and other intervenors in the case. NU has a 38.5 percent ownership interest in YAEC and can predict neither the outcome of this matter nor its ultimate impact on NU.

NRG Energy, Inc. Exposures

Certain subsidiaries of NU, including CL&P and Yankee Gas, have entered into transactions with NRG Energy, Inc. (NRG) and certain of its subsidiaries. On May 14, 2003, NRG and certain of its subsidiaries filed voluntary bankruptcy petitions and on December 5, 2003, NRG emerged from bankruptcy. NU’s NRG-related exposures as a result of these transactions relate to 1) the recovery of congestion charges incurred by NRG prior to the implementation of standard market design (SMD) on March 1, 2003, which is still pending before the court, 2) the recovery of CL&P’s station service billings from NRG, which is currently the subject of an arbitration, and 3) the recovery of Yankee Gas’ and CL&P’s expenditures that were incurred related to an NRG subsidiary’s generating plant construction project that has ceased. While it is unable to determine the ultimate outcome of these issues, management does not expect their resolution will have a material adverse effect on NU’s consolidated financial condition or results of operations.

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 an opinion dated October 12, 2005, a panel of three judges at the Second Circuit held that the shareholders of NU had no right to sue Con Edison for its alleged breach of the parties’ Merger Agreement. NU’s request for a rehearing was denied on January 3, 2006. This ruling left intact the remaining claims between NU and Con Edison for breach of contract, which include NU’s claim for recovery of costs and expenses of approximately $32 million and Con Edison’s claim for damages of "at least $314 million." NU is currently considering whether to seek review by the United States Supreme Court. At this stage, NU cannot predict the outcome of this matter or its ultimate effect on NU.

10.

Fair Value of Financial Instruments

The following methods and assumptions were used to estimate the fair value of each of the following financial instruments:

Cash and Cash Equivalents and Special Deposits: The carrying amounts approximate fair value due to the short-term nature of these cash items.

SERP Investments: Investments held for the benefit of the SERP are recorded at fair market value based upon quoted market prices. The investments having a cost basis of $54 million and $50.1 million held for benefit of the SERP were recorded at their fair market values at December 31, 2005 and 2004, of $58.1 million and $55.1 million, for 2005 and 2004, respectively. For further information regarding the SERP liabilities and related investments, see Note 7E, "Employee Benefits – Supplemental Executive Retirement and Other Plans," and Note 11, "Marketable Securities," to the consolidated financial statements.

Prior Spent Nuclear Fuel Trust: During 2004, WMECO established a trust to fund the amounts due to the DOE for its prior spent nuclear fuel obligation. These investments having a cost basis of $51.1 million and $49.5 million for 2005 and 2004, respectively, were recorded at their fair market value of $50.8 million and $49.3 million at December 31, 2005 and 2004, respectively. For further information regarding these investments, see Note 11, "Marketable Securities," to the consolidated financial statements.

Preferred Stock, Long-Term Debt and Rate Reduction Bonds: The fair value of NU’s fixed-rate securities is based upon the quoted market price for those issues or similar issues. Adjustable rate securities are assumed to have a fair value equal to their carrying value. The carrying amounts of NU’s financial instruments and the estimated fair values are as follows:


	At December 31, 2005
(Millions of Dollars)	Carrying Amount	Fair Value
Preferred stock not subject to mandatory redemption	$ 116.2	$ 98.5
Long-term debt -
First mortgage bonds	1,314.8	1,425.7
Other long-term debt	1,744.3	1,791.5
Rate reduction bonds	1,350.5	1,433.6


	At December 31, 2004
(Millions of Dollars)	Carrying Amount	Fair Value
Preferred stock not subject to mandatory redemption	$ 116.2	$ 101.4
Long-term debt -
First mortgage bonds	1,072.3	1,228.8
Other long-term debt	1,812.4	1,898.7
Rate reduction bonds	1,546.5	1,674.0

Other long-term debt includes $268 million and $259.7 million of fees and interest due for spent nuclear fuel disposal costs at December 31, 2005 and 2004, respectively.

Other Financial Instruments: The carrying value of financial instruments included in current assets and current liabilities, including investments in securitizable assets, approximates their fair value.

11.

Marketable Securities

The following is a summary of NU’s available-for-sale securities which are recorded at their fair market values and are included in current and long-term marketable securities on the accompanying consolidated balance sheets. Changes in the fair value of these securities are recorded as unrealized gains and losses in accumulated other comprehensive income.


	At December 31,
(Millions of Dollars)	2005	2004
Globix	$ 3.7	(a)
SERP securities	58.1	$ 55.1
WMECO prior spent nuclear fuel trust	50.8	49.3
Totals	$112.6	$104.4

For 2005, management determined that the decline in the value of the Globix investment was other than temporary in nature and recorded pre- tax charges totaling $6.1 million in other income, net on the accompanying consolidated statements of (loss)/income. This amount is included in the negative $0.9 million after-tax amount which was reclassified from accumulated other comprehensive income and recognized in earnings in 2005.

(a)

At December 31, 2004, NU’s $9.8 million investment in NEON was not a marketable security. On March 8, 2005, NEON merged with Globix, and NU’s investment in Globix became a marketable security at that time. For further information regarding the Globix investment, see Note 1X, "Summary of Significant Accounting Policies – Marketable Securities," to the consolidated financial statements.

At December 31, 2005 and 2004, these marketable securities are comprised of the following:


(Millions of Dollars) At December 31, 2005	Amortized Cost	Pre-Tax Gross Unrealized Gains	Pre-Tax Gross Unrealized Losses	Estimated Fair Value
United States equity securities	$ 23.2	$3.9	$(0.3)	$ 26.8
Non-United States equity securities	6.3	0.9	-	7.2
Fixed income securities	79.3	0.2	(0.9)	78.6
Totals	$108.8	$5.0	$(1.2)	$112.6


(Millions of Dollars) At December 31, 2004	Amortized Cost	Pre-Tax Gross Unrealized Gains	Pre-Tax Gross Unrealized Losses	Estimated Fair Value
United States equity securities	$19.3	$3.8	$(0.2)	$ 22.9
Non-United States equity securities	5.6	1.3	-	6.9
Fixed income securities	74.7	0.3	(0.4)	74.6
Totals	$99.6	$5.4	$(0.6)	$104.4

At December 31, 2005 and 2004, NU evaluated the securities in an unrealized loss position and has determined that none of the related unrealized losses are deemed to be other-than-temporary in nature. At December 31, 2005 and 2004, the gross unrealized losses and fair value of NU’s investments that have been in a continuous unrealized loss position for less than 12 months and 12 months or greater were as follows:


	Less than 12 Months		12 Months or Greater		Total
(Millions of Dollars) At December 31, 2005	Estimated Fair Value	Pre-Tax Gross Unrealized Losses	Estimated Fair Value	Pre-Tax Gross Unrealized Losses	Estimated Fair Value	Pre-Tax Gross Unrealized Losses
United States equity securities	$ 2.9	$(0.2)	$0.4	$(0.1)	$ 3.3	$(0.3)
Non-United States equity securities	-	-	-	-	-	-
Fixed income securities	39.8	(0.7)	5.7	(0.2)	45.5	(0.9)
Totals	$42.7	$(0.9)	$6.1	$(0.3)	$48.8	$(1.2)


	Less than 12 Months		12 Months or Greater		Total
(Millions of Dollars) At December 31, 2004	Estimated Fair Value	Pre-Tax Gross Unrealized Losses	Estimated Fair Value	Pre-Tax Gross Unrealized Losses	Estimated Fair Value	Pre-Tax Gross Unrealized Losses
United States equity securities	$ 1.7	$(0.2)	$ -	$ -	$ 1.7	$(0.2)
Non-United States equity securities	-	-	-	-	-	-
Fixed income securities	40.0	(0.4)	-	-	40.0	(0.4)
Totals	$41.7	$(0.6)	$ -	$ -	$41.7	$(0.6)

For information related to the change in net unrealized holding gains and losses included in shareholders’ equity, see Note 15, "Accumulated Other Comprehensive Income/(Loss)," to the consolidated financial statements.

For the years ended December 31, 2005, 2004, and 2003, realized gains and losses recognized on the sale of available-for-sale securities are as follows:


(Millions of Dollars)	Realized Gains	Realized Losses	Net Realized Gains/(Losses)
2005	$1.3	$(7.1)	$(5.8)
2004	0.9	(0.3)	0.6
2003	0.5	(0.1)	0.4

For the year ended December 31, 2005, realized losses of $0.4 million relating to the WMECO spent nuclear fuel trust are included in fuel, purchased and net interchange power on the accompanying consolidated statements of (loss)/income. There were no realized losses relating to the WMECO spent nuclear fuel trust in 2004 or 2003. For the years ended December 31, 2005, 2004 and 2003, all other net realized (losses)/gains of $(5.4) million, $0.6 million, and $0.4 million, respectively, are included in other income, net on the accompanying consolidated statements of (loss)/income.

NU utilizes the specific identification basis method for the Globix and SERP securities and the average cost basis method for the WMECO prior spent nuclear fuel trust to compute the realized gains and losses on the sale of available-for-sale securities.

Proceeds from the sale of these securities, including proceeds from short-term investments, totaled $137.1 million, $106.2 million, and $34.1 million for the years ended December 31, 2005, 2004 and 2003, respectively.

At December 31, 2005, the contractual maturities of the available-for sale securities are as follows:


(Millions of Dollars)	Amortized Cost	Estimated Fair Value
Less than one year	$ 51.8	$ 56.0
One to five years	28.7	28.5
Six to ten years	6.7	6.6
Greater than ten years	21.6	21.5
Totals	$108.8	$112.6

NU’s investment in Globix is included in the one to five years maturity category in the table above. All other available-for-sale equity securities are included in the less than one year maturity category in the table above.

For further information regarding marketable securities, see Note 1X, "Summary of Significant Accounting Policies – Marketable Securities" to the consolidated financial statements.

12.

Leases

NU has entered into lease agreements, some of which are capital leases, for the use of data processing and office equipment, vehicles, and office space. The provisions of these lease agreements generally provide for renewal options. Certain lease agreements contain contingent lease payments. The contingent lease payments are based on various factors, such as the commercial paper rate plus a credit spread or the consumer price index.

Capital lease rental payments were $3.4 million in 2005, $3.3 million in 2004 and $3.7 million in 2003. Interest included in capital lease rental payments was $1.9 million in 2005, $2 million in 2004 and $2.3 million in 2003. Capital lease asset amortization was $1.4 million in 2005, $1.3 million in 2004, and $1.4 million in 2003.

Operating lease rental payments charged to expense were $15.6 million in 2005, $16.3 million in 2004 and $16.1 million in 2003. These amounts include $1.1 million, $1.1 million, and $0.9 million included in income from discontinued operations on the accompanying consolidated statements of (loss)/income for the years ended December 31, 2005, 2004, and 2003, respectively. The capitalized portion of operating lease payments was approximately $9.4 million, $8.2 million, and $7.7 million for the years ended December 31, 2005, 2004, and 2003, respectively.

Future minimum rental payments excluding executory costs, such as property taxes, state use taxes, insurance, and maintenance, under long-term noncancelable leases, at December 31, 2005 are as follows:


(Millions of Dollars)	Capital Leases	Operating Leases
2006	$ 2.7	$ 33.4
2007	2.6	29.9
2008	2.3	26.8
2009	2.0	18.8
2010	1.5	15.5
Thereafter	16.6	42.3
Future minimum lease payments	27.7	$166.7
Less amount representing interest	13.7
Present value of future minimum lease payments	$14.0

Total projected future operating lease payments of $166.7 million above includes an aggregate amount of $2 million related to companies classified as discontinued operations in the accompanying consolidated financial statements.

13.

Long-Term Debt

Long-term debt maturities and cash sinking fund requirements on debt outstanding at December 31, 2005, for the years 2006 through 2010 and thereafter, which exclude $268 million of fees and interest due for spent nuclear fuel disposal costs and a negative $9.1 million related to net unamortized premiums or discounts and other fair value adjustments at December 31, 2005, are as follows (millions of dollars):


Year
2006		$ 22.7
2007		4.1
2008		155.3
2009		56.5
2010		8.0
Thereafter		2,544.5
Total		$2,791.1

Essentially all utility plant of CL&P, PSNH, NGC, and Yankee Energy System, Inc. is subject to the liens of each company’s respective first mortgage bond indenture.

CL&P has $315.5 million of tax-exempt Pollution Control Revenue Bonds (PCRBs) secured by second mortgage liens on transmission assets, junior to the liens of its first mortgage bond indentures.

CL&P has $62 million of tax-exempt PCRBs with bond insurance and secured by the first mortgage bonds. For financial reporting purposes, this debt is not considered to be first mortgage bonds unless CL&P failed to meet its obligations under the PCRBs.

PSNH entered into financing arrangements with the Business Finance Authority (BFA) of the state of New Hampshire, pursuant to which the BFA issued five series of PCRBs and loaned the proceeds to PSNH. At both December 31, 2005 and 2004, $407.3 million of the PCRBs were outstanding. PSNH’s obligation to repay each series of PCRBs is secured by bond insurance and by first mortgage bonds. Each such series of first mortgage bonds contains similar terms and provisions as the applicable series of PCRBs. For financial reporting purposes, these first mortgage bonds would not be considered outstanding unless PSNH failed to meet its obligations under the PCRBs.

NU’s long-term debt agreements provide that certain of its subsidiaries must comply with certain financial and non-financial covenants as are customarily included in such agreements, including but not limited to, debt service coverage ratios and interest coverage ratios. The parties to these agreements currently are and expect to remain in compliance with these covenants.

On November 2, 2005, NU entered into an unsecured credit facility, under which all borrowings will have a maturity of 13 months, with such borrowings being classified as long-term debt. The new facility provides a total commitment of $310 million in borrowings and LOCs. This facility will expire no later than November 30, 2007, although no advances or LOCs will be available under the facility beyond October 30, 2006. NU may borrow at variable rates plus an applicable margin based upon certain debt ratings, as rated by the higher of Standard and Poor’s or Moody’s. Under this facility, NU must comply with certain financial and non-financial covenants as are customarily included in such agreements, including but not limited to, consolidated debt ratios. NU currently is and expects to remain in compliance with these covenants. At December 31, 2005, there were no borrowings outstanding under this facility.

Long-term debt – first mortgage bonds on the accompanying consolidated statements of capitalization at December 31, 2005 include $200 million, $50 million, and $50 million of long-term debt issued in 2005 related to CL&P, PSNH and Yankee Gas, respectively.

The weighted-average effective interest rate on PSNH’s variable-rate pollution control notes was 2.51 percent for 2005 and 1.25 percent for 2004. The pollution control note due in 2031, has an interest rate of 3.35 percent effective through October 1, 2008, at which time the bonds will be remarketed, and the interest rate will be adjusted.

Other long-term debt – other on the accompanying consolidated statements of capitalization at December 31, 2005 includes $50 million of long-term debt issued in 2005 related to WMECO.

Liabilities of assets held for sale at December 31, 2005 includes $82.6 million relating to SESI long-term debt.

For information regarding fees and interest due for spent nuclear fuel disposal costs, see Note 9C, "Commitments and Contingencies – Spent Nuclear Fuel Disposal Costs," to the consolidated financial statements.

The change in fair value totaling a negative $5.2 million and a positive $0.1 million at December 31, 2005 and 2004, respectively, on the accompanying consolidated statements of capitalization, reflects the NU parent 7.25 percent amortizing note, due 2012 in the amount of $263 million, and is hedged with a fixed to floating interest rate swap. The change in fair value of the debt was recorded as an adjustment to long-term debt with an equal and offsetting adjustment to derivative assets for the change in fair value of the fixed to floating interest rate swap.

14.

Dividend Restrictions

The Federal Power Act and certain state statutes limit the payment of dividends by CL&P, PSNH, and WMECO to their respective retained earnings balances. Yankee Gas is also subject to certain restrictions. At December 31, 2005, retained earnings available for payment of dividends totaled $330.4 million.

NGC is subject to certain dividend payment restrictions under its bond covenants.

15.

Accumulated Other Comprehensive Income/(Loss)

The accumulated balance for each other comprehensive income/(loss) item is as follows:


(Millions of Dollars)	December 31, 2004	Current Period Change	December 31, 2005
Qualified cash flow hedging instruments	$(3.5)	$21.7	$18.2
Unrealized gains on securities	3.2	(0.9)	2.3
Minimum supplemental executive retirement pension liability adjustments	(0.9)	0.4	(0.5)
Accumulated other comprehensive (loss)/income	$(1.2)	$21.2	$20.0


(Millions of Dollars)	December 31, 2003	Current Period Change	December 31, 2004
Qualified cash flow hedging instruments	$24.8	$(28.3)	$(3.5)
Unrealized gains on securities	2.0	1.2	3.2
Minimum supplemental executive retirement pension liability adjustments	(0.8)	(0.1)	(0.9)
Accumulated other comprehensive income/(loss)	$26.0	$(27.2)	$(1.2)

The changes in the components of other comprehensive income/(loss) are reported net of the following income tax effects:


	2005	2004	2003
Qualified cash flow hedging instruments	$(13.4)	$14.4	$(6.4)
Unrealized gains on securities	0.6	(0.7)	(1.4)
Minimum supplemental executive retirement pension liability adjustments	(0.3)	0.1	0.5
Accumulated other comprehensive income	$(13.1)	$13.8	$(7.3)

Adjustments to accumulated other comprehensive income/(loss) for NU’s qualified cash flow hedging instruments are as follows:


	At December 31,
(Millions of Dollars, Net of Tax)	2005	2004
Balance at beginning of year	$(3.5)	$24.8
Hedged transactions recognized to earnings	5.6	(57.8)
Change in fair value	11.0	25.0
Cash flow transactions entered into for the period	5.1	4.5
Net change associated with the current period hedging transactions	21.7	(28.3)
Total fair value adjustments included in accumulated other comprehensive income	$18.2	$(3.5)

16.

Earnings Per Share

EPS is computed based upon the weighted-average number of common shares outstanding, excluding unallocated ESOP shares, during each year. Diluted EPS is computed on the basis of the weighted-average number of common shares outstanding plus the potential dilutive effect if certain securities are converted into common stock. In 2005, 2004 and 2003, 1,122,541 options, 696,994 options and 355,153 options, respectively, were excluded from the following table as these options were antidilutive. The weighted average common shares outstanding at December 31, 2005 include the impact of the issuance of 23 million common shares on December 12, 2005 which were outstanding for 20 days in 2005. The following table sets forth the components of basic and diluted EPS:


(Millions of Dollars, except share information)	2005	2004	2003
(Loss)/income from continuing operations	$(266.6)	$69.8	$77.2
Income from discontinued operations	14.1	46.8	43.9
(Loss)/income before cumulative effects of accounting changes	(252.5)	116.6	121.1
Cumulative effects of accounting changes, net of tax benefits	(1.0)	-	(4.7)
Net (loss)/income	$(253.5)	$116.6	$116.4

Basic EPS common shares outstanding (average)	131,638,953	128,245,860	127,114,743
Dilutive effect of employee stock options	-	150,216	125,981
Fully diluted EPS common shares outstanding (average)	131,638,953	128,396,076	127,240,724

Basic and fully diluted EPS:
(Loss)/income from continuing operations	$ (2.03)	$0.54	$0.61
Income from discontinued operations	0.11	0.37	0.34
Cumulative effects of accounting changes, net of tax benefits	(0.01)	-	(0.04)
Net (loss)/income	$ (1.93)	$0.91	$0.91

17.

Segment Information

Presentation: NU is organized between the Utility Group and NU Enterprises businesses based on a combination of factors, including the characteristics of each business’ products and services, the sources of operating revenues and expenses and the regulatory environment in which they operate. Effective January 1, 2005, the portion of NGS’s business that supports NGC’s and HWP’s generation assets was reclassified from the services and other segment to the merchant energy segment within the NU Enterprises segment. Effective January 1, 2004, separate detailed information regarding the Utility Group’s transmission businesses and NU Enterprises’ merchant energy business is now included in the following segment information. Segment information for all periods has been restated to conform to the current presentation except for total asset information for the transmission business segment as this information is not available.

The Utility Group segment, including both the regulated electric distribution and transmission businesses, as well as the gas distribution business comprising Yankee Gas, represents approximately 74.4 percent, 70.1 percent, and 73.1 percent of NU’s total revenues from continuing operations for the years ended December 31, 2005, 2004 and 2003, respectively, and includes the operations of the regulated electric utilities, CL&P, PSNH and WMECO, whose complete financial statements are included in NU’s report on Form 10-K. PSNH’s distribution segment includes generation activities. Also included in NU’s report on Form 10-K is detailed information regarding CL&P’s, PSNH’s, and WMECO’s transmission businesses. Utility Group revenues from the sale of electricity and natural gas are primarily derived from residential, commercial and industrial customers and are not dependent on any single customer.

The NU Enterprises merchant energy business segment includes Select Energy, NGC, NGS, and the generation operations of HWP (Mt. Tom), while the NU Enterprises services and other business segment includes Boulos, Woods Electrical, and NGS Mechanical, Inc., (which are subsidiaries of NGS), SESI, SECI, HEC/Tobyhanna, HEC/CJTS, and intercompany eliminations. The results of NU Enterprises parent are also included within services and other. On March 9, 2005, NU announced its decision to exit the wholesale marketing business and the energy services businesses. On November 7, 2005, NU announced its decision to also exit its retail marketing and competitive generation businesses. In November of 2005, NU Enterprises sold SECI-NH (a division of SECI) and Woods Network. For further information regarding NU Enterprises’ businesses, which are being exited, see Note 2, "Wholesale Contract Market Changes," Note 3, "Restructuring and Impairment Charges," and Note 4, "Assets Held for Sale and Discontinued Operations," to the consolidated financial statements.

NU’s consolidated statements of (loss)/income for the years ended December 31, 2005, 2004 and 2003 present the operations for NGC, Mt. Tom, SESI, SECI- NH, Woods Network, and Woods Electrical as discontinued operations. For further information, see Note 4, "Assets Held for Sale and Discontinued Operations," to the consolidated financial statements.

Other in the tables includes the results for Mode 1 Communications, Inc., an investor in Globix, the results of the non-energy-related subsidiaries of Yankee (Yankee Energy Services Company, Yankee Energy Financial Services Company, and NorConn Properties, Inc.), the non-energy operations of HWP, and the results of NU’s parent and service companies. Interest expense included in other primarily relates to the debt of NU parent.

Other includes pre-tax investment write-downs totaling $6.9 million, $13.8 million, and $1.4 million in 2005, 2004, and 2003, respectively.

Intercompany Transactions: Select Energy has served a portion of CL&P’s TSO or standard offer load for 2004 and 2003. Total Select Energy revenues from CL&P for CL&P’s standard offer load, TSO load and for other transactions with CL&P, represented approximately $53.4 million for the year ended December 31, 2005, $611.3 million for the year ended December 31, 2004 and $688 million for the year ended December 31, 2003, of total NU Enterprises’ revenues. Total CL&P purchases from Select Energy are eliminated in consolidation.

WMECO’s purchases from Select Energy for standard offer and default service and for other transactions with Select Energy represented $36.3 million, $108.5 million and $143 million of total NU Enterprises’ revenues for the years ended December 31, 2005, 2004 and 2003, respectively. Total WMECO purchases from Select Energy are eliminated in consolidation.

Customer Concentrations: Select Energy revenues related to contracts with NSTAR companies represented $296.7 million of total NU Enterprises’ revenues for the year ended December 31, 2005 and represented $300.2 million of total NU Enterprises’ revenues for the year ended December 31, 2004. Select Energy also provides basic generation service in the New Jersey and Maryland market. Select Energy revenues related to these contracts represented $530 million of total NU Enterprises’ revenues for the year ended December 31, 2005, $334.2 million for the year ended December 31, 2004 and $380.4 million for the year ended December 31, 2003. No other individual customer represented in excess of 10 percent of NU Enterprises’ revenues for the years ended December 31, 2005, 2004, or 2003.

Due to the decision to exit the wholesale business, all wholesale revenues, including intercompany revenues, have been included in fuel, purchased and net interchange power beginning in the second quarter of 2005.

NU’s segment information for the years ended December 31, 2005, 2004, and 2003 is as follows (some amounts may not agree between segment schedules due to rounding):


	For the Year Ended December 31, 2005
	Utility Group
	Distribution
(Millions of Dollars)	Electric	Gas	Transmission	NU Enterprises	Other	Eliminations	Total
Operating revenues	$4,836.5	$ 503.3	$167.5	$1,963.6	$ 353.0	$ (426.2)	$ 7,397.7
Wholesale contract market changes, net	-	-	-	(425.4)	-	-	(425.4)
Restructuring and impairment charges	-	-	-	(44.1)	-	-	(44.1)
Depreciation and amortization	(549.1)	(22.0)	(24.0)	(3.0)	(17.8)	13.6	(602.3)
Other operating expenses	(4,015.3)	(441.0)	(73.5)	(2,125.8)	(355.1)	427.3	(6,583.4)
Operating income/(loss)	272.1	40.3	70.0	(634.7)	(19.9)	14.7	(257.5)
Interest expense, net of AFUDC	(169.5)	(17.1)	(15.0)	(18.3)	(34.9)	15.7	(239.1)
Interest income	3.6	0.3	0.6	4.9	17.0	(19.2)	7.2
Other income/(loss), net	44.1	(0.1)	(0.6)	(0.6)	150.6	(152.8)	40.6
Income tax (expense)/benefit	(41.1)	(6.1)	(12.5)	237.4	18.4	(8.3)	187.8
Preferred dividends	(5.6)	-	-	-	-	-	(5.6)
Income/(loss) from continuing operations	103.6	17.3	42.5	(411.3)	131.2	(149.9)	(266.6)
Income from discontinued operations	-	-	-	14.1	-	-	14.1
Income/(loss) before cumulative effect of accounting change	103.6	17.3	42.5	(397.2)	131.2	(149.9)	(252.5)
Cumulative effect of accounting change, net of tax benefit	-	-	-	(1.0)	-	-	(1.0)
Net income/(loss)	$ 103.6	$ 17.3	$ 42.5	$ (398.2)	$ 131.2	$ (149.9)	$ (253.5)
Total assets (1)	$8,923.3	$1,195.3	$ -	$ 2,424.7	$4,796.3	$(4,770.5)	$12,569.1
Cash flows for total investments in plant	$ 400.9	$ 74.6	$247.0	$ 23.2	$ 29.7	$ -	$ 775.4


	For the Year Ended December 31, 2004
	Utility Group
	Distribution
(Millions of Dollars)	Electric	Gas	Transmission	NU Enterprises	Other	Eliminations	Total
Operating revenues	$4,040.0	$ 407.8	$140.7	$2,709.3	$ 289.6	$(1,045.4)	$6,542.0
Depreciation and amortization	(458.5)	(26.2)	(21.6)	(7.3)	(16.4)	13.7	(516.3)
Other operating expenses	(3,278.4)	(347.8)	(68.9)	(2,792.5)	(284.5)	1,038.6	(5,733.5)
Operating income/(loss)	303.1	33.8	50.2	(90.5)	(11.3)	6.9	292.2
Interest expense, net of AFUDC	(159.1)	(16.6)	(12.3)	(11.6)	(26.3)	10.9	(215.0)
Interest income	4.8	0.1	0.3	1.6	17.0	(13.1)	10.7
Other income/(loss), net	25.6	(0.2)	0.2	(5.6)	85.5	(96.2)	9.3
Income tax (expense)/benefit	(56.8)	(3.0)	(8.9)	44.2	15.3	(12.6)	(21.8)
Preferred dividends	(5.6)	-	-	-	-	-	(5.6)
Income/(loss) from continuing operations	112.0	14.1	29.5	(61.9)	80.2	(104.1)	69.8
Income from discontinued operations	-	-	-	46.8	-	-	46.8
Net income/(loss)	$ 112.0	$ 14.1	$ 29.5	$ (15.1)	$ 80.2	$ (104.1)	$ 116.6
Total assets (1)	$8,393.3	$1,147.9	$ -	$2,176.2	$4,313.1	$(4,392.1)	$11,638.4
Cash flows for total investments in plant	$ 408.7	$ 59.5	$172.3	$ 17.6	$ 13.4	$ -	$ 671.5

(1)

Information for segmenting total assets between electric distribution and transmission is not available at December 31, 2005 or December 31, 2004. On a NU consolidated basis, these distribution and transmission assets are disclosed in the electric distribution columns above.


	For the Year Ended December 31, 2003
	Utility Group
	Distribution
(Millions of Dollars)	Electric	Gas	Transmission	NU Enterprises	Other	Eliminations	Total
Operating revenues	$ 3,865.8	$ 361.5	$117.9	$2,449.8	$ 257.9	$(1,109.5)	$ 5,943.4
Depreciation and amortization	(483.8)	(23.4)	(18.7)	(8.4)	(14.2)	10.3	(538.2)
Other operating expenses	(3,084.7)	(313.1)	(51.9)	(2,505.2)	(238.2)	1,088.5	(5,104.6)
Operating income/(loss)	297.3	25.0	47.3	(63.8)	5.5	(10.7)	300.6
Interest expense, net of AFUDC	(166.2)	(13.1)	(3.5)	(9.7)	(23.5)	8.5	(207.5)
Interest income	3.8	-	0.1	0.6	9.4	(9.5)	4.4
Other income/(loss), net	12.5	(1.0)	(0.9)	(3.2)	100.2	(102.4)	5.2
Income tax (expense)/benefit	(44.8)	(3.6)	(14.8)	28.8	14.6	(0.1)	(19.9)
Preferred dividends	(5.6)	-	-	-	-	-	(5.6)
Income/(loss) from continuing operations	97.0	7.3	28.2	(47.3)	106.2	(114.2)	77.2
Income from discontinued operations	-	-	-	43.9	-	-	43.9
Income/(loss) before cumulative effect of accounting change	97.0	7.3	28.2	(3.4)	106.2	(114.2)	121.1
Cumulative effect of accounting change, net of tax benefit	-	-	-	-	(4.7)	-	(4.7)
Net income/(loss)	$ 97.0	$ 7.3	$ 28.2	$ (3.4)	$ 101.5	$ (114.2)	$ 116.4
Cash flows for total investments in plant	$ 361.2	$ 49.7	$ 95.3	$ 18.7	$ 33.2	$ -	$ 558.1

NU Enterprises' segment information for the years ended December 31, 2005, 2004, and 2003 is as follows. Eliminations are included in the services and other columns.


	NU Enterprises – For the Year Ended December 31, 2005
(Millions of Dollars)	Merchant Energy	Services and Other	Total
Operating revenues	$1,868.8	$ 94.8	$1,963.6
Wholesale contract market charges, net	(425.4)	-	(425.4)
Restructuring and impairment charges	(27.1)	(17.0)	(44.1)
Depreciation and amortization	(2.2)	(0.8)	(3.0)
Other operating expenses	(2,026.5)	(99.3)	(2,125.8)
Operating loss	(612.4)	(22.3)	(634.7)
Interest expense	(17.8)	(0.5)	(18.3)
Interest income	3.7	1.2	4.9
Other loss, net	(0.6)	-	(0.6)
Income tax benefit	230.1	7.3	237.4
Loss from continuing operations	(397.0)	(14.3)	(411.3)
Income/(loss) from discontinued operations	37.4	(23.3)	14.1
Loss before cumulative effect of accounting change	(359.6)	(37.6)	(397.2)
Cumulative effect of accounting change, net of tax benefit	(1.0)	-	(1.0)
Net loss	$ (360.6)	$ (37.6)	$ (398.2)
Total assets	$ 2,222.2	$ 202.5	$2,424.7
Cash flows for total investments in plant	$ 23.2	$ -	$ 23.2


	NU Enterprises – For the Year Ended December 31, 2004
(Millions of Dollars)	Merchant Energy	Services and Other	Total
Operating revenues	$2,599.2	$110.1	$2,709.3
Depreciation and amortization	(6.4)	(0.9)	(7.3)
Other operating expenses	(2,679.6)	(112.9)	(2,792.5)
Operating loss	(86.8)	(3.7)	(90.5)
Interest expense	(11.4)	(0.2)	(11.6)
Interest income	1.2	0.4	1.6
Other loss, net	(3.1)	(2.5)	(5.6)
Income tax benefit	39.6	4.6	44.2
Loss from continuing operations	(60.5)	(1.4)	(61.9)
Income from discontinued operations	43.2	3.6	46.8
Net (loss)/income	$ (17.3)	$ 2.2	$ (15.1)
Total assets	$1,914.2	$262.0	$2,176.2
Cash flows for total investments in plant	$ 17.6	$ -	$ 17.6


	NU Enterprises – For the Year Ended December 31, 2003
(Millions of Dollars)	Merchant Energy	Services and Other	Total
Operating revenues	$2,369.1	$ 80.7	$2,449.8
Depreciation and amortization	(7.6)	(0.8)	(8.4)
Other operating expenses	(2,421.0)	(84.2)	(2,505.2)
Operating loss	(59.5)	(4.3)	(63.8)
Interest expense	(9.6)	(0.1)	(9.7)
Interest income	0.5	0.1	0.6
Other (loss)/income, net	(5.3)	2.1	(3.2)
Income tax expense	28.0	0.8	28.8
Loss from continuing operations	(45.9)	(1.4)	(47.3)
Income from discontinued operations	39.2	4.7	43.9
Net (loss)/income	$ (6.7)	$ 3.3	$ (3.4)
Cash flows for total investment in plant	$ 18.7	$ -	$ 18.7

18.

Subsequent Events

Beginning with the quarter ended March 31, 2006, the operations of NGC and Mt. Tom were presented as discontinued operations. Management concluded that NGC and Mt. Tom should be presented as discontinued operations beginning in the first quarter of 2006, when a plan to market these businesses was implemented and the criteria for this presentation were met. As a result, NU's consolidated statements of (loss)/income for the years ended December 31, 2005, 2004 and 2003 were revised to present the operations for NGC and Mt. Tom as discontinued operations, along with the operations of SESI, SECI-NH, Woods Network, and Woods Electrical which were previously reported as discontinued operations. Under this presentation, revenues and expenses of these businesses are included in the income from discontinued operations on the consolidated statements of (loss)/income for all prior periods.

For summarized financial information for the discontinued operations, see Note 4, "Assets Held for Sale and Discontinued Operations," to the consolidated financial statements.

NU's consolidated balance sheets, consolidated statements of comprehensive (loss)/income, consolidated statements of shareholders' equity, consolidated statements of cash flows and consolidated statements of capitalization were not impacted by this revision.

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

On June 1, 2006, NU Enterprises completed the sale of its retail marketing business to Hess Corporation in accordance with the terms of its definitive agreement signed on May 1, 2006.

CONSOLIDATED STATEMENTS OF QUARTERLY FINANCIAL DATA (UNAUDITED)


(Thousands of Dollars, except per share information)		Quarter Ended (a) (b) (c)
2005		March 31,		June 30,		September 30,		December 31,
Operating Revenues	$	2,232,964	$	1,531,613	$	1,754,942	$	1,878,224
Operating Loss		(126,237)		(16,090)		(85,672)		(29,482)
Loss from Continuing Operations		(113,297)		(38,386)		(99,732)		(15,161)
(Loss)/Income from Discontinued Operations		(4,422)		10,682		5,240		2,593
Cumulative effect of accounting change, net of tax benefit		-		-		-		(1,005)
Net Loss		(117,719)		(27,704)		(94,492)		(13,573)
Basic and Fully Diluted (Loss)/Income per Common Share:
Loss from Continuing Operations		(0.86)		(0.29)		(0.77)		(0.11)
(Loss)/Income from Discontinued Operations		(0.03)		0.08		0.04		0.02
Cumulative effect of accounting change, net of tax benefit		-		-		-		(0.01)
Net Loss		(0.89)		(0.21)		(0.73)		(0.10)


2004
Operating Revenues	$	1,799,224	$	1,485,017	$	1,624,492	$	1,633,305
Operating Income		143,593		67,741		8,069		72,755
Income/(Loss) from Continuing Operations		57,370		13,187		(17,502)		16,721
Income from Discontinued Operations		10,072		10,805		9,594		16,341
Net Income/(Loss)		67,442		23,992		(7,908)		33,062
Basic and Fully Diluted Earnings/(Loss) per Common Share:
Income/(Loss) from Continuing Operations		0.45		0.10		(0.13)		0.13
Income from Discontinued Operations		0.08		0.09		0.07		0.13
Net Income/(Loss)		0.53		0.19		(0.06)		0.26

(a)

The summation of quarterly earnings per share data may not equal annual data due to rounding.

(b)

Amounts differ from those previously reported as a result of the presentation of discontinued operations as a result of meeting the criteria requiring this presentation.

(c)

Quarterly operating (loss)/income amounts differ from those previously reported as a result of the change in classification of certain expense amounts previously included in other income, net. These amounts are summarized as follows (thousands of dollars):


Quarter Ended	2005	2004
March 31,	$5,486	$2,893
June 30,	4,419	2,814
September 30,	3,922	3,385


Exhibit 12

Ratio of Earnings to Fixed Charges
(In thousands)
	Year Ended	Year Ended		Year Ended	Year Ended	Year Ended
Earnings, as defined:	December 31, 2005 (a)	December 31, 2004 (a)		December 31, 2003 (a)	December 31, 2002	December 31, 2001

Net (loss)/income from continuing operations before
extraordinary item and cumulative effect of accounting change	$ (266,576)	$ 69,776		$ 77,266	$ 148,529	$ 265,942
Income tax (benefit)/expense	(187,796)	21,765		19,879	72,682	173,952
Equity in earnings of regional nuclear
generating and transmission companies	(3,311)	(2,592)		(4,487)	(11,215)	(3,970)
Dividends received from regional equity investees	687	3,879		8,904	11,056	7,060
Fixed charges, as below	260,927	236,499		228,908	290,590	304,663
Interest capitalized (not including AFUDC)	-	-		-	(2,085)	(684)
Preferred dividend security requirements of
consolidated subsidiaries	(9,265)	(9,265)		(9,265)	(9,265)	(12,082)
Total (loss)/earnings, as defined	$ (205,334)	$ 320,062		$ 321,205	$500,292	$734,881

Fixed charges, as defined:

Interest on long-term debt	$ 131,870	$ 107,365		$ 88,700	$ 134,471	$ 140,497
Interest on rate reduction bonds	87,439	98,899		108,359	115,791	87,616
Other interest	19,775	8,762		10,398	16,998	51,545
Rental interest factor	6,733	7,066		7,366	5,433	7,033
Amortized premiums, discounts and
capitalized expenses related to indebtedness	5,845	5,142		4,820	6,547	5,206
Preferred dividend security requirements of
consolidated subsidiaries	9,265	9,265		9,265	9,265	12,082
Interest capitalized (not including AFUDC)	-	-		-	2,085	684
Total fixed charges, as defined	$ 260,927	$ 236,499		$ 228,980	$ 290,590	$ 304,663


Ratio of Earnings to Fixed Charges - Pro Forma	(0.79) (b)		1.35	1.40	1.72	2.41


(a) Certain line items have been revised for the reclassification of NGC and Mt. Tom to discontinued operations. (b) Earnings were inadequate to cover fixed charges by $466.4 million for the year ended December 31, 2005.