NU 2006 Annual Report

Exhibit 13

2006 Annual Report
Northeast Utilities and Subsidiaries

Management’s Discussion and Analysis

Financial Condition and Business Analysis

Executive Summary

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

Results, Strategy and Outlook:

In 2006, Northeast Utilities (NU or the company) earned $470.6 million, or $3.05 per share, compared with a loss of $253.5 million, or $1.93 per share, in 2005. All per share amounts are fully diluted. 2006 earnings include $257.3 million, or $1.67 per share, from the regulated Utility Group businesses, $211.3 million, or $1.37 per share, from NU Enterprises, Inc. (NU Enterprises), and earnings of $2 million, or $0.01 per share, from NU Parent and affiliates. The 2005 loss includes earnings of $163.4 million, or $1.24 per share, from the Utility Group, losses of $398.2 million, or $3.03 per share, from NU Enterprises, and losses of $18.7 million, or $0.14 per share, from NU Parent and affiliates.

NU’s 2006 results include certain significant items, including the following: On November 1, 2006, NU completed the sale of NU Enterprises' competitive generation business, which includes 100 percent ownership interest in Northeast Generation Company (NGC) and Holyoke Water Power Company’s (HWP) 146 megawatt (MW) Mt. Tom coal-fired plant (Mt. Tom), to affiliates of Energy Capital Partners (ECP) for $1.34 billion. As a result, NU recorded an after-tax gain of approximately $314 million, or $2.04 per share, in 2006. The results for 2006 also included an after-tax loss of $32.8 million, or $0.21 per share, related to the sale of Select Energy, Inc.'s (Select Energy) retail marketing business and a $25 million pre-tax charge for a donation from NU Enterprises to the NU Foundation, Inc. (NU Foundation). In 2006, the Connecticut Light and Power Company (CL&P) also recorded a reduction in income tax expense of $74 million, or $0.48 per share, pursuant to a private letter ruling (PLR) received from the Internal Revenue Service (IRS).

Excluding the PLR, earnings at the distribution businesses of CL&P, Public Service Company of New Hampshire (PSNH), Western Massachusetts Electric Company (WMECO), and Yankee Gas Services Company (Yankee Gas) and the regulated generation business of PSNH totaled $123.5 million, or $0.80 per share, compared with earnings of $122.3 million, or $0.93 per share, in 2005.

The transmission businesses of CL&P, PSNH and WMECO earned $59.8 million, or $0.39 per share, in 2006, compared with $41.1 million, or $0.31 per share, in 2005.

Excluding the gain on the sale of the competitive generation business for NU Enterprises and the after-tax loss related to the sale of the retail marketing business, NU Enterprises lost $62.9 million, or $0.41 per share, compared with losses of $398.2 million, or $3.03 per share, in 2005.

NU has exited substantially all of the competitive NU Enterprises businesses. In addition to the sale of the competitive generation business in 2006, Select Energy sold its retail marketing business in 2006. NU Enterprises also completed the sale of three and portions of two other energy services businesses, and served out approximately half of the wholesale power obligations that existed at the beginning of 2006.

On October 12, 2006, CL&P energized a 21-mile 115 kilovolt (KV)/345 KV transmission project between Bethel, Connecticut and Norwalk, Connecticut. The final cost of the project was approximately $340 million, $10 million below budget.

On December 1, 2006, the conversion of PSNH's 50 MW coal-fired unit at Schiller Station in Portsmouth, New Hampshire to burn wood (the Northern Wood Power Project) was completed and became operational. The total cost was on budget at approximately $74 million.

NU projects 2007 combined earnings for the Utility Group and NU Parent and affiliates of between $1.30 per share and $1.55 per share, which includes earnings of between $0.80 per share and $0.90 per share at the Utility Group distribution and generation businesses, between $0.50 per share and $0.60 per share at the transmission business, and NU Parent and affiliates of between zero and earnings of $0.05 per share. NU projects approximately breakeven results at NU Enterprises for 2007, excluding any potential mark-to-market impacts of its remaining wholesale power contracts.

NU currently projects that it can achieve compounded annual earnings per share (EPS) growth of between 10 percent and 14 percent over 2006 EPS for the period 2007 through 2011. 2006 EPS for this comparison represents 2006 Utility Group and parent

and affiliates results, excluding the $0.48 per share benefit associated with CL&P’s PLR. That growth rate includes compounded annual growth of approximately 23 percent in its transmission rate base and 7 percent in its distribution and generation rate base.

Legislative, Legal and Regulatory Items:

On December 29, 2006, Yankee Gas filed a request with the Connecticut Department of Public Utility Control (DPUC) for a rate increase of approximately $67.8 million effective on July 1, 2007. The request proposes to recover its liquefied natural gas (LNG) facility costs and increased cost of providing distribution delivery service. Yankee Gas expects that the increase will be offset by projected commodity and pipeline savings, for a net revenue increase of $37.2 million or 8.4 percent above current rates.

On December 14, 2006, the Massachusetts Department of Telecommunications and Energy (DTE) approved a settlement agreement among WMECO, the Massachusetts Attorney General, the Associated Industries of Massachusetts and Low Income Energy Affordability Network that included distribution rate increases of $1 million beginning on January 1, 2007 and an additional $3 million increase beginning on January 1, 2008. Also included in the settlement agreement are cost tracking mechanisms for pension and other postretirement benefit costs, bad debts related to energy costs, and recovery of certain capital improvements needed for system reliability. Under this settlement agreement, management expects that a regulatory return on equity (Regulatory ROE) of between 9 percent and 10 percent annually is achievable for WMECO in 2007 and 2008.

On October 31, 2006, the Federal Energy Regulatory Commission (FERC) issued its decision on the ROE and incentives for the New England transmission owners. On a going forward basis, NU's transmission capital program will be largely comprised of regional infrastructure that is included within the regional planning process. Over 90 percent of the company's projected $2.5 billion capital program for 2007 through 2011 is expected to be in this category and is expected to earn the 12.4 percent ROE for regional infrastructure projects as opposed to the 10.9 percent base ROE.

In 1998, the Connecticut Yankee Atomic Power Company (CYAPC), the Yankee Atomic Electric Company (YAEC) and the Maine Yankee Atomic Power Company (MYAPC) (collectively, the Yankee Companies) filed separate complaints against the United States Department of Energy (DOE) in the United States Court of Federal Claims (Court of Federal Claims) seeking monetary damages resulting from the DOE's failure to begin accepting spent nuclear fuel. In a ruling released on October 4, 2006, the Court of Federal Claims held that the DOE was liable for damages to CYAPC for $34.2 million through 2001, YAEC for $32.9 million through 2001 and MYAPC for $75.8 million through 2002. CL&P, PSNH and WMECO collectively own 49 percent of CYAPC, 38.5 percent of YAEC and 20 percent of MYAPC. In December of 2006 the DOE appealed the ruling. The refund to CL&P, PSNH and WMECO of any damages that may be recovered from the DOE is established in the Yankee Companies' FERC-approved rate settlement agreements, although implementation will be subject to the final determination of the FERC. CL&P, PSNH, and WMECO expect to pass any recovery onto their customers. As such, no earnings are expected to result from the court decision.

On August 4, 2006, CL&P notified Connecticut Governor Rell and the DPUC that it intends to postpone filing a distribution rate case until mid-2007 for rates effective in early 2008.

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

Liquidity:

NU’s liquidity improved significantly in 2006, primarily as a result of the sale of NU Enterprises' competitive generation business. NU received approximately $1 billion from this sale, net of the assumption of $320 million of debt by the buyer.

NU’s cash capital expenditures totaled $872.2 million in 2006, compared with $775.4 million in 2005. NU’s 2006 cash capital expenditures included $567.2 million by CL&P, $126.7 million by PSNH, $42.8 million by WMECO, $87.6 million by Yankee Gas, and $47.9 million by other NU subsidiaries, including $25.8 million by NU Enterprises.

NU projects Utility Group capital expenditures of approximately $4.9 billion from 2007 through 2011, including $1.2 billion in 2007. Over the five-year period, approximately $2.4 billion is projected to be spent on distribution and generation and $2.5 billion on transmission. In 2007, approximately $700 million will be spent on transmission and $500 million on distribution and generation.

Cash flows from operations decreased by $34.1 million to $407.1 million in 2006 from $441.2 million in 2005. Items impacting cash flows in 2006 were payments made to settle NU Enterprises derivative contracts, payments to the Yankee Companies for estimated decommissioning and closure costs, regulatory refund payments, repayment of amounts under the CL&P receivables facility and income tax payments.

In June of 2006, NU terminated a $310 million liquidity facility as a result of the reduced liquidity needs of NU Enterprises. In December of 2006, NU reduced the maximum borrowing limit of its parent company credit facility to $500 million from $700 million as a result of its current cash balance and lower projected liquidity requirements of NU Enterprises' wholesale marketing contracts. There were no borrowings under this credit facility at December 31, 2006.

Overview

Consolidated: In 2006, NU earned $470.6 million, or $3.05 per share, compared with a loss of $253.5 million, or $1.93 per share, in 2005 and earnings of $116.6 million, or $0.91 per share, in 2004. EPS is reported on a fully diluted basis, and the weighted average common shares outstanding at December 31, 2006 and 2005 includes the impact of the issuance of 23 million NU common shares on December 12, 2005. 2006 results include earnings of $257.3 million, or $1.67 per share, from the regulated Utility Group businesses and $211.3 million, or $1.37 per share, from the competitive NU Enterprises businesses. Those results also included earnings of $2 million, or $0.01 per share, at NU Parent and affiliates. The 2005 loss includes earnings of $163.4 million, or $1.24 per share, from the Utility Group, and losses of $398.2 million, or $3.03 per share, from NU Enterprises. The 2005 results also include a loss of $18.7 million, or $0.14 per share, from NU Parent and affiliates.

The significant improvement in NU's 2006 results compared to 2005 relate to decisions made in 2005 to exit all of the competitive businesses. The 2005 results included $322.6 million of after-tax restructuring and impairment charges, mark-to-market charges, primarily on wholesale electric marketing contracts, and losses on the sale of discontinued operations. NU's results for 2006 include an after-tax gain of approximately $314 million from the sale of NU’s 100 percent ownership interest in NGC stock and Mt. Tom. The results for 2006 also included a reduction in income tax expense at CL&P of $74 million, or $0.48 per share, pursuant to a PLR received from the IRS and an after-tax loss of $32.8 million, or $0.21 per share, related to the sale of Select Energy's retail marketing business.

A summary of NU’s earnings/(losses) by major business line for 2006, 2005 and 2004 is as follows (millions of dollars):


	For the Years Ended December 31,
Segment	2006				2005				2004
	Amount		Per Share		Amount		Per Share		Amount		Per Share
Utility Group	$	257.3	$	1.67	$	163.4	$	1.24	$	155.6	$	1.21
NU Enterprises		211.3		1.37		(398.2)		(3.03)		(15.1)		(0.12)
Parent and affiliates		2.0		0.01		(18.7)		(0.14)		(23.9)		(0.18)
Net Income/(Loss)	$	470.6	$	3.05	$	(253.5)	$	(1.93)	$	116.6	$	0.91

The only common equity securities that are publicly traded are common shares of NU. The EPS of any segment does not represent a direct legal interest in the assets and liabilities allocated to any one segment but rather represents a direct interest in NU's assets and liabilities as a whole. A portion of NU Enterprises results are included in discontinued operations.

Within the Utility Group, NU segments its earnings between its electric transmission and its electric and its gas distribution businesses, with PSNH generation included with the distribution business. The transmission business earned $59.8 million, or $0.39 per share, in 2006, compared with $41.1 million, or $0.31 per share, in 2005, and $28.2 million, or $0.22 per share, in 2004. The higher level of earnings in 2006 and 2005 was due primarily to a return on a higher level of transmission investment at CL&P.

In 2006, the distribution and generation business earned $197.5 million, or $1.28 per share, compared with earnings of $122.3 million, or $0.93 per share, in 2005 and $127.4 million, or $0.99 per share, in 2004. Distribution business results in 2006 were primarily affected by rate increases and a reduction of $74 million, or $0.48 per share, to CL&P’s income tax expense as a result of the PLR, partially offset by a 4 percent reduction in total retail electric sales, an 11.2 percent reduction in firm natural gas sales and higher operation, depreciation and interest expenses.

NU’s consolidated revenues were $6.9 billion in 2006 compared to $7.4 billion in 2005 and $6.5 billion in 2004. The decrease is a result of a lower level of activity at NU Enterprises. Utility Group revenues totaled $6 billion in 2006, compared with $5.5 billion in 2005 and $4.6 billion in 2004. Higher regulated revenues are primarily caused by higher fuel and energy costs, which are passed through to customers. NU Enterprises revenues totaled $0.9 billion before eliminations in 2006, compared with $2 billion in 2005 and $2.7 billion in 2004. The lower 2006 NU Enterprises revenues reflect the exit from the NU Enterprises businesses and wholesale contracts in 2006 and 2005.

Utility Group: The Utility Group is comprised of CL&P, PSNH, WMECO, and Yankee Gas, and is comprised of transmission, distribution and regulated generation businesses. The Utility Group earned $257.3 million, or $1.67 per share, in 2006, compared with $163.4 million, or $1.24 per share, in 2005, and $155.6 million, or $1.21 per share, in 2004. A summary of Utility Group earnings by company and business segment for 2006, 2005 and 2004 is as follows:


	For the Years Ended December 31,
(Millions of Dollars)	2006		2005		2004
CL&P Distribution*	$	147.6	$	60.0	$	64.0
PSNH Distribution and Generation		27.0		33.9		39.9
WMECO Distribution		11.0		11.1		9.4
Yankee Gas		11.9		17.3		14.1
Total Distribution and Generation		197.5		122.3		127.4
CL&P Transmission*		46.9		29.3		18.5
PSNH Transmission		8.3		7.8		6.7
WMECO Transmission		4.6		4.0		3.0
Total Transmission		59.8		41.1		28.2
Total Utility Group Net Income	$	257.3	$	163.4	$	155.6

*After preferred dividends in all years.

The increase in 2006 CL&P distribution earnings is due primarily to a PLR that reduced CL&P’s 2006 income tax expense by $74 million. CL&P’s 2006 distribution earnings also include the recognition of an after-tax deferred gain of $7.7 million related to an unregulated portion of generation assets CL&P previously sold to its affiliate, NGC. This deferred gain was being recognized on a CL&P stand-alone basis over the life of the generation assets. The remainder was recognized in 2006 as a result of the sale of the competitive generation business to a third party. Excluding the impact of these items, CL&P’s distribution business earned $65.9 million in 2006, or an increase of $5.9 million when compared to 2005. This increase was due to an $11.9 million distribution rate increase that took effect on January 1, 2006, the settlement of a tax appeal with the State of Connecticut, and the absence of employee termination and benefit curtailment charges that were recorded in 2005. These factors were partially offset by a 4.9 percent decline in sales, increased storm-related expenses, and higher interest expense. CL&P’s regulatory return on equity (Regulatory ROE) for 2006 was approximately 7.5 percent compared to its allowed ROE of 9.85 percent. In 2007, CL&P expects its ROE to be between 6 percent and 6.5 percent as a result of higher operating expenses being only partially offset by a $7 million distribution rate increase that took effect on January 1, 2007.

PSNH’s distribution and generation earnings were $6.9 million lower in 2006, when compared to 2005, due primarily to higher unitary state income taxes resulting from the impact of the sale of NU Enterprises' competitive generation assets. PSNH also experienced a 1.3 percent decline in sales and increased wholesale transmission costs in 2006, offset by a temporary annual distribution rate increase of $24.5 million that was effective on July 1, 2006. PSNH’s Regulatory ROE for 2006 was approximately 6.4 percent, and in 2007, PSNH expects distribution and generation earnings to improve as a result of the ongoing distribution rate case and a lower effective tax rate than in 2006.

WMECO’s distribution earnings in 2006 were approximately the same as 2005 due to a $3 million distribution rate increase that took effect on January 1, 2006 offset by a 4.2 percent decrease in sales, and higher operating and interest expenses. WMECO’s Regulatory ROE for 2006 was approximately 9.6 percent and in 2007, WMECO expects the ROE to be between 9 and 10 percent in 2007 and 2008.

The decline in Yankee Gas earnings from 2005 to 2006 was due primarily to unseasonably warm weather in the early and late months of 2006. Overall firm sales of natural gas in 2006 were 11.2 percent lower than 2005 and Yankee Gas’ Regulatory ROE was approximately 5.9 percent in 2006 compared to its allowed ROE of 9.9 percent. In 2007, Yankee Gas expects its earnings and ROE to improve as a result of its request for a distribution rate increase that was filed with the DPUC on December 29, 2006 for new rates to be effective on July 1, 2007.

The increase in transmission earnings in 2006 is due to higher levels of investment in the transmission system, particularly in Connecticut, partially offset by the October 31, 2006 FERC ROE decision.

For the Utility Group, a summary of changes in CL&P, PSNH and WMECO electric kilowatt-hour (KWH) sales and Yankee Gas firm natural gas sales for 2006 as compared to 2005 on an actual and weather normalized basis is as follows:


	Electric								Firm Natural Gas
	CL&P		PSNH		WMECO		Total		Yankee Gas
	Percentage Decrease	Weather Normalized Percentage Decrease	Percentage Decrease	Weather Normalized Percentage Increase/ (Decrease)	Percentage Decrease	Weather Normalized Percentage Decrease	Percentage Decrease	Weather Normalized Percentage Decrease	Percentage Decrease	Weather Normalized Percentage Decrease
Residential	(6.6)%	(2.1)%	(2.4)%	0.5 %	(5.3)%	(1.3)%	(5.6)%	(1.5)%	(13.9)%	(2.9)%
Commercial	(3.0)%	(1.5)%	-	1.4 %	(2.6)%	(1.3)%	(2.3)%	(0.8)%	(12.7)%	(2.7)%
Industrial	(5.6)%	(4.8)%	(1.9)%	(1.1)%	(5.3)%	(4.8)%	(4.5)%	(3.8)%	(6.8)%	(3.9)%
Other	(4.7)%	(4.7)%	(5.4)%	(5.4)%	(0.5)%	(0.5)%	(4.4)%	(4.4)%	N/A	N/A
Total	(4.9)%	(2.3)%	(1.3)%	0.5 %	(4.2)%	(2.1)%	(4.0)%	(1.6)%	(11.2)%	(3.2)%

Regulated electric sales in 2006 declined due to lower use per customer as a result of a combination of milder summer and winter weather in 2006, compared with 2005, and customer reaction to higher energy prices. Firm gas sales in 2006 were lower largely as a result of milder weather in 2006. The company forecasts retail sales growth for CL&P, PSNH and WMECO for the period 2007 through 2011 to be 1.1 percent, 2.3 percent and 0.1 percent, respectively.

NU Enterprises: The companies that have been included in NU Enterprises are reported in two business segments: the merchant energy business segment and the energy services business segment. At December 31, 2006, the one remaining merchant energy business is Select Energy’s wholesale marketing contracts, while the energy services business segment is comprised of Northeast Generation Services Company (NGS), the remaining contracts of the former Woods Electrical Co., Inc. (Woods Electrical - Other), the E. S. Boulos Company (Boulos) and the Connecticut division of Select Energy Contracting, Inc. (SECI-CT). NGS provides maintenance, operations and testing services under two contracts that remain to be exited. Boulos provides third-party electrical services. Woods Electrical - Other and SECI-CT are in the wind down stage. The remainder of the NU Enterprises businesses were exited in 2005 and 2006.

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

NGC, which was sold in November of 2006 to ECP,

Mt. Tom, which was sold in November of 2006 to ECP,

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

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

The New Hampshire division of Select Energy Contracting, Inc. (SECI-NH), which was sold in November of 2005, and

Woods Network Services, Inc. (Woods Network), which was sold in November of 2005.

A summary of NU Enterprises' earnings/(losses) for 2006, 2005 and 2004 is as follows:


	For the Years Ended December 31,
(Millions of Dollars)	2006		2005		2004
Merchant Energy	$	268.8	$	(360.6)	$	(17.3)
Energy Services and Other		(57.5)		(37.6)		2.2
Total NU Enterprises Net Income/(Loss)	$	211.3	$	(398.2)	$	(15.1)

A summary of NU Enterprises' (losses)/earnings from continuing operations and discontinued operations for 2006, 2005 and 2004 is as follows:


	For the Years Ended December 31,
(Millions of Dollars)	2006		2005		2004
Continuing Operations:
Merchant Energy	$	(93.5)	$	(397.0)	$	(60.5)
Energy Services and Other		(32.5)		(14.3)		(1.4)
		(126.0)		(411.3)		(61.9)
Discontinued Operations:
Merchant Energy		362.3		37.4		43.2
Energy Services and Other		(25.0)		(23.3)		3.6
		337.3		14.1		46.8
Cumulative effect of accounting change		-		(1.0)		-
Net Income/(Loss)	$	211.3	$	(398.2)	$	(15.1)

Merchant energy earnings included in discontinued operations relate to NGC's and Mt. Tom's contracts with Select Energy through the sale date of November 1, 2006 as well as the gain on the sale of the competitive generation business. NU Enterprises' wholesale marketing business is not included in discontinued operations because it does not meet the accounting criteria for this presentation.

Retail marketing business results are also not included in discontinued operations, as separate financial information for the retail marketing business is not available due to the manner in which the merchant energy business operated prior to January 1, 2006. For information regarding NU’s business segments, see Note 16, "Segment Information," to the consolidated financial statements.

Merchant energy earnings in 2006 were primarily the result of the sale of the competitive generation business on November 1, 2006, offset by losses at the retail marketing business prior to the exit from that business on June 1, 2006. The retail marketing business lost $70.3 million in 2006, reflecting losses from both electricity sales and natural gas sales and an after-tax loss of $32.8 million related to the sale of the retail marketing business.

The losses on retail electricity sales were caused primarily by replacing the electricity supply at current prices. When the decision to exit the competitive generation and retail marketing businesses was announced in 2005, the resources of the competitive generation business that were previously dedicated to the retail marketing business at a fixed price were separated from the retail marketing business, exposing the portfolio of retail sales to current market prices. Market prices have generally been higher than those that would have been charged by the competitive generation business (with the competitive generation business receiving a partially offsetting benefit). The retail marketing business losses on natural gas were primarily the result of mild weather that lowered demand and created a surplus of supply which was either sold at a loss or remained in storage with a reduced fair value.

Excluding the gain on the sale of the competitive generation business in discontinued operations, the combined wholesale marketing and competitive generation businesses recorded earnings of $32.1 million in 2006. Included in these results were higher 2006 competitive generation business earnings through the November 1, 2006 sale date. Competitive generation business earnings were higher in 2006 as this business sold its products into a market that was generally higher than sales to the retail marketing business. However, short-term energy prices decreased during 2006, which reduced the value received from sale of generation products. Also included in these earnings is approximately an $8 million tax benefit from eliminating tax reserves established in 2005 that are no longer needed due to the tax gain on the sale of the generation assets.

The energy services businesses, parent and other loss in 2006 was due to after-tax charges totaling approximately $13 million related to the following:

Collectibility of accounts receivable and other assets;

Contingencies and costs related to projects, including litigation, warranty and other contingencies;

Costs related to the valuation and termination of guarantees; and

Adjustments under various purchase and sale agreements.

Losses on the sale of the services businesses along with the NU Enterprises $25 million pre-tax contribution to the NU Foundation,
also contributed to the services, parent and other, loss in 2006.

NU Enterprises' 2005 loss was primarily due to net after-tax charges of $322.6 million as a result of restructuring and impairment charges, mark-to-market charges, primarily on wholesale electric marketing contracts, and losses on the sale of discontinued operations. In addition to these mark-to-market, restructuring and impairment charges, 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 results included an after-tax loss of $48.3 million associated with marking-to-market certain natural gas positions. These positions were balanced by entering into offsetting contracts in the first quarter of 2005 and had no impact on earnings since then. There were no restructuring and impairment charges recorded in 2004.

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

NU Parent and Affiliates: NU Parent and affiliates earned $2 million, or $0.01 per share, in 2006, compared with losses of $18.7 million, or $0.14 per share, in 2005 and $23.9 million, or $0.18 per share, in 2004. The improved 2006 results related to an increase in income generated by higher cash and cash equivalent balances and investments in the NU money pool (pool) as a result of the proceeds received from the sale of the competitive generation business and a small amount of earnings at some of the company's support and real estate companies. The pool investments are eliminated in consolidation along with the corresponding interest expense for the pool borrowers. In 2006, in addition to the higher investment income, a $2 million after-tax gain associated with the sale of NU's investment in Globix Corporation (Globix), a telecommunications company, also contributed to the increase from 2005. 2006 results were negatively impacted by additional environmental reserves totaling $1.3 million recorded by HWP associated with its manufactured gas plant (MGP) coal tar site. 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 consolidated earnings of between $1.30 per share and $1.55 per share in 2007.

Utility Group Distribution and Generation: NU projects that its regulated electric and natural gas distribution businesses and PSNH’s generation business will earn between $0.80 per share and $0.90 per share in 2007. Those results will be impacted by the outcome of the PSNH and Yankee Gas rate cases, both of which are expected to be decided by the middle of 2007.

Utility Group Transmission: NU projects that the transmission business will earn between $0.50 per share and $0.60 per share in 2007. The growth in 2007 EPS over 2006 is expected to be the result of earnings on a higher level of investment.

NU Enterprises: NU projects that NU Enterprises results will be approximately break even in 2007, excluding any potential mark-to-market impacts of its remaining wholesale power contracts.

Parent and Affiliates: NU projects that NU Parent and affiliates will earn between zero and $0.05 per share in 2007.

NU currently projects that it can achieve compounded annual growth in EPS of between 10 percent and 14 percent over 2006 EPS for the period 2007 through 2011, with this growth expected to be higher than that range in early years and below that range in later years. 2006 EPS for this comparison represents 2006 Utility Group and parent and affiliates results, excluding the $0.48 per share benefit associated with CL&P’s PLR. That growth rate includes compounded annual growth of approximately 23 percent in its regulated electric transmission rate base and 7 percent in its regulated distribution and generation rate base. This assumes appropriate regulatory approvals on its electric transmission and distribution and natural gas distribution investments.

Liquidity

Consolidated: NU’s liquidity improved significantly in 2006, primarily as a result of the $1 billion of proceeds from the sale of NU Enterprises' competitive generation business, net of the assumption of $320 million of debt by ECP. A portion of these proceeds was used to repay short-term borrowings under NU's and the Utility Group's revolving credit facilities which were incurred during 2006. At December 31, 2006, there were no borrowings on NU's or the Utility Group's revolving credit facilities or sales of accounts receivable from CL&P’s $100 million accounts receivable sales facility. At December 31, 2006, NU had $481.9 million of cash and cash equivalents on hand compared with $45.8 million at December 31, 2005.

The exit from the NU Enterprises' businesses also allowed the company to eliminate much of its highest interest rate debt. In addition to receiving approximately $1 billion in cash from the sale of the competitive generation business, this sale eliminated $320 million of 8.81 percent NGC secured debt, which was assumed by ECP. The sale of SESI also eliminated approximately $85 million of debt, which was held for sale at December 31, 2005 and the final scheduled payment of $21 million on NU’s 8.58 percent 1991 notes on December 1, 2006 also reduced additional relatively high-cost debt. As a result, the consolidated weighted average interest rate on fixed rate long-term debt for NU was 5.73 percent at December 31, 2006, compared with 5.96 percent at December 31, 2005.

NU’s cash position is expected to change significantly in 2007. In the first quarter of 2007, the company will pay approximately $350 million in federal and state taxes due to the tax gain on the sale of the competitive generation business, offset by tax losses incurred at NU Enterprises. Additionally, NU is forecasting capital expenditures of approximately $1.2 billion and common and preferred dividends of more than $100 million in 2007, compared with forecasted net cash flows from operations of between $500 million and $600 million. As a result, the company expects that it will need to borrow on its credit facilities in 2007 and that its cash position will be significantly lower by the end of 2007 than it was at the end of 2006. All four of the Utility Group businesses are expected to issue long-term debt in 2007, primarily to fund their capital programs. CL&P is expected to issue approximately $500 million of new debt, while PSNH, WMECO and Yankee Gas each is expected to issue up to $75 million of long-term debt in 2007.

Cash flows from operations decreased by $34.1 million to $407.1 million in 2006 from $441.2 million in 2005. Several items impacting operating cash flows in 2006 are as follows:

Cash payments related to Select Energy’s wholesale, retail and generation derivative contracts settled during 2006 amounted to approximately $100 million. In 2005, the wholesale contracts were marked-to-market with a non-cash charge of approximately $440 million, but cash payments of $186.5 million were made to terminate a number of wholesale contracts along with cash payments to serve contracts of approximately $40 million. With the settlement of a significant portion of these contracts in 2006 and 2005, cash payments in 2007 to serve remaining wholesale contracts are expected to be much lower than during 2006 and are expected to be approximately $40 million. Cash flows for and from selling the retail and generation businesses, including their derivative contracts, are included in investing cash flows.

Payments totaling $90.7 million were made to CYAPC, MYAPC and YAEC for decommissioning and closure costs. These payments are expected to decline in future years and are expected to total $44 million in 2007.

Regulatory refunds paid in the amount of $96.6 million related primarily to amounts refunded to CL&P’s ratepayers. No such significant CL&P refunds are expected for 2007 at this time.

$80 million of outstanding sales under CL&P’s sale of receivables facility were repaid in 2006 and included as an operating cash outflow. In addition, regulated accounts receivable and accounts payable fluctuated due to an increase in receivables due to

higher rates, offset by an increase in accounts payable due to higher prices. This had an approximately $70 million positive impact on operating cash flows.

NU Enterprises accounts receivable and accounts payable both decreased due primarily to a decrease in the volume of wholesale and retail billing and payables activity. This had an approximately $45 million positive impact on operating cash flows.

A federal income tax payment of approximately $55 million related to NU’s 2005 tax return which was made in the first quarter of 2006. Tax payments will increase in the first quarter of 2007 due to a payment of approximately $350 million in net federal and state taxes due primarily to the gain on the sale of competitive generation business.

In 2007, excluding the approximately $350 million tax payment related to the 2006 sale of the competitive generation business, the company expects cash flows from operations to be between $250 million and $300 million higher than they were in 2006.

Cash flows from operations decreased by $19.4 million from $460.6 million in 2004 to $441.2 million in 2005. The decrease in operating cash flows is primarily due to the 2005 payments made by NU Enterprises of $186.5 million related to the exit from long-term wholesale marketing contracts and an accounts receivable increase due to the retail distribution rate increases that took effect in 2005. These decreases were partially 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.

At December 31, 2006, NU maintained a parent company credit facility of $500 million which expires on November 6, 2010. In December of 2006, NU reduced the maximum borrowing limit of this facility to $500 million from $700 million as a result of its current cash and cash equivalents balance and lower projected liquidity requirements of NU Enterprises' wholesale marketing contracts. In addition, the letter of credit (LOC) sub-limit of $550 million was also reduced to $500 million. At December 31, 2006, NU had no borrowings on that credit facility but had $67.5 million of LOCs secured by that facility. In June of 2006, NU terminated a separate $310 million liquidity facility as a result of the reduced liquidity needs of NU Enterprises.

NU’s 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 December 12, 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 to contribute equity to the Utility Group companies. In 2006, NU contributed $60.8 million of equity to CL&P, $21.7 million to PSNH, $31.9 million to WMECO, and $35.1 million to Yankee Gas. The company does not expect to issue additional common equity in 2007 or 2008, other than through its compensation plans. A modest equity issuance in 2009 is possible, depending on the company's capital program and the company's future debt to equity ratio compared to targets.

NU’s senior unsecured debt is rated Baa2, BBB-, and BBB with a stable outlook, by Moody’s Investors Service (Moody’s), Standard & Poor’s (S&P) and Fitch Ratings (Fitch), respectively. If NU were to be downgraded to a sub-investment grade level by either Moody’s or S&P, a number of Select Energy’s contracts would require the posting of additional collateral in the form of cash or LOCs. If NU’s senior unsecured ratings were reduced to sub-investment grade by either Moody’s or S&P, Select Energy could, under its present contracts, be asked to provide approximately $136.8 million of collateral or LOCs to various unaffiliated counterparties and approximately $52.4 million to several independent system operators and unaffiliated local distribution companies (LDCs) in each case at December 31, 2006. If such a downgrade were to occur, management believes NU would currently be able to provide this collateral.

There was limited ratings activity involving NU and its subsidiaries in 2006. Moody’s downgraded PSNH secured debt to Baa1 from A3 due to lower projected cash flows as a result of PSNH’s full recovery of Part 3 stranded costs as of June 30, 2006. On December 12, 2005, Moody’s also lowered the outlook for Yankee Gas to "negative" from "stable" to reflect the fact that some of Yankee Gas’s credit measures are relatively weak in relation to its Baa2 issuer rating. NU expects that the Moody’s decision on Yankee Gas’s rating will depend upon the outcome of the rate case Yankee Gas filed on December 29, 2006. Additionally, S&P improved NU’s business risk position to a "4" from a "5," to reflect the exit of the NU Enterprises businesses, while Fitch raised its outlook on NU and CL&P to stable from negative also due primarily to the exit from the NU Enterprises businesses.

NU paid common dividends of $112.7 million in 2006, compared with $87.6 million in 2005 and $80.2 million in 2004. The increase in common dividends reflects increases in quarterly dividends of $0.0125 per share in the third quarters of 2004, 2005, and 2006 as well as a higher number of shares outstanding in 2006 as a result of NU's common share issuance on December 12, 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. In February of 2007, the NU Board of Trustees approved a quarterly dividend of $0.1875 per share, payable on March 30, 2007, to shareholders of record as of March 1, 2007. In general, the Utility Group companies pay approximately 60 percent of their cash earnings to NU in the form of common dividends. In 2006, CL&P, PSNH, WMECO, and Yankee Gas paid $63.7 million, $41.7 million, $7.9 million, and $7.9 million, respectively, in common dividends to NU.

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

companies and on Yankee Gas. CL&P, PSNH, WMECO and Yankee Gas also have a revolving credit agreement that imposes leverage restrictions.

Cash capital expenditures included on the accompanying consolidated statements of cash flows and described in the liquidity section of this management's discussion and analysis do not include cost of removal, the allowance for funds used during construction (AFUDC) related to equity funds and the capitalized portion of pension expense or income. NU’s cash capital expenditures totaled $872.2 million in 2006, compared with $775.4 million in 2005 and $671.5 million in 2004. NU’s 2006 cash capital expenditures included $567.2 million by CL&P, $126.7 million by PSNH, $42.8 million by WMECO, $87.6 million by Yankee Gas, and $47.9 million by other NU subsidiaries, including $25.8 million by NU Enterprises. The increase in NU’s cash capital expenditures was primarily the result of higher transmission capital expenditures, particularly at CL&P. For information regarding 2007 through 2011 projected capital expenditures, see "Business Development and Capital Expenditures," included in this Management's Discussion and Analysis.

NU expects to fund approximately 60 percent 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.

Utility Group: The Utility Group companies maintain a $400 million credit line that expires on November 6, 2010. There were no borrowings outstanding under that facility at December 31, 2006.

In addition to its revolving credit facility, CL&P has an arrangement with a financial institution under which CL&P can sell up to $100 million of accounts receivable and unbilled revenues. There were no amounts outstanding under that facility at December 31, 2006. For more information regarding the sale of receivables, see Note 1L, "Summary of Significant Accounting Policies - Sale of Receivables," to the consolidated financial statements.

On June 7, 2006, CL&P closed on the sale of $250 million of 30-year first mortgage bonds with a coupon rate of 6.35 percent. Because of an interest rate hedge CL&P executed earlier in 2006 to offset the impact of higher interest rates, CL&P received $7.8 million from the hedge counterparties at the closing of this transaction.

On June 21, 2006, PSNH converted $89.3 million variable interest rate insured tax-exempt pollution control revenue bonds to a fixed interest rate of 4.75 percent with maturity in 2021.

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

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. By December 31, 2006, NU exited substantially all of these businesses and simplified its business model, reduced its business risk, improved its financial flexibility, and enhanced earnings visibility.

NU expects the Utility Group to invest up to approximately $4.9 billion in its electric transmission and distribution and natural gas distribution businesses from 2007 through 2011. Those amounts include up to $2.5 billion for the high-voltage electric transmission system and $2.4 billion for the electric and natural gas distribution systems and regulated generation.

Business Development and Capital Expenditures

Consolidated: NU's capital expenditures including cost of removal, AFUDC, and the capitalized portion of pension expense or income, totaled $945.8 million in 2006, compared with $814.3 million in 2005, and $677 million in 2004. Included in these amounts are $907.6 million, $767.4 million, and $641.9 million, respectively, related to the Utility Group.

Utility Group:

Transmission: Most of the increase in transmission capital expenditures in 2006 when compared to 2005 and 2004 below was due to CL&P’s construction of transmission projects in southwest Connecticut. A summary of NU’s transmission capital expenditures including AFUDC by Utility Group company in 2006, 2005 and 2004 is as follows (millions of dollars):


	Year
		2006		2005		2004
CL&P	$	415.6	$	215.3	$	132.7
PSNH		36.1		28.5		29.8
WMECO		13.0		12.9		6.5
Other		0.8		0.6		1.5
Totals	$	465.5	$	257.3	$	170.5

Under NU’s FERC-approved tariffs, transmission projects enter rate base once they enter commercial operation. Additionally, 50 percent of NU’s capital expenditures on its four major transmission projects in southwest Connecticut enter rate base during the construction period with the remainder entering rate base once the projects are complete. At the end of 2006, NU’s approximate transmission rate base was $1.1 billion, including approximately $840 million at CL&P, $140 million at PSNH and $75 million at WMECO. NU’s total transmission rate base was approximately $600 million at the end of 2005. The company forecasts that its total transmission rate base will grow to approximately $1.4 billion at the end of 2007, $1.9 billion at the end of 2008, $2.6 billion at the end of 2009, $2.8 billion at the end of 2010, and $3 billion at the end of 2011. This increase in transmission rate base is driven by the need to improve the capacity and reliability of NU’s regulated transmission system. A summary of projected year end transmission rate base by Utility Group company is as follows (millions of dollars):


	Year
		2007		2008		2009		2010	2011
CL&P	$	1,173	$	1,512	$	2,117	$	2,218	$	2,461
PSNH		175		276		282		335		325
WMECO		80		132		173		208		239
Totals	$	1,428	$	1,920	$	2,572	$	2,761	$	3,025

Several factors may impact the Utility Group transmission rate base amounts above, including the level and timing of capital expenditures and plant placed in service, regulatory approvals of various projects, and other factors.

CL&P worked on a number of major transmission projects in 2006, most of which were located in southwest Connecticut. Each of these projects has received approval from the Connecticut Siting Council (CSC) and the New England Independent System Operator (ISO-NE). These projects are designed to improve the reliability and capacity for transmitting electricity. Capital expenditures for these projects, including AFUDC, totaled $328.1 million in 2006 compared to $155.9 million in 2005. These projects include:

A newly completed 21-mile, 115 KV/345 KV transmission project between Bethel, Connecticut and Norwalk, Connecticut, construction of which began in April of 2005. On October 12, 2006, the line was fully energized and went into service, approximately two months ahead of schedule at a cost of $340 million, $10 million below budget;

A 69-mile, 115 KV/345 KV transmission project from Middletown to Norwalk, Connecticut on which CL&P has commenced site work. CL&P has received the Connecticut Department of Environmental Protection's (DEP) and the United States Army Corps of Engineers’ permits for the project but still requires CSC review of certain detailed construction plans. Although this project is currently expected to be completed by the end of 2009, opportunities to optimize schedule performance may result in an earlier completion date. This project is currently 16 percent complete and CL&P's portion of this project is estimated to cost approximately $1.05 billion. At December 31, 2006, CL&P has capitalized $186.4 million associated with this project;

A two-cable, 9-mile, 115 KV underground transmission project between Norwalk and Stamford, Connecticut (Glenbrook Cables), construction of which began in October of 2006. Glenbrook Cables is intended to respond to the growing electric demand in the area and is expected to cost $183 million. This project is currently approximately 20 percent complete and on schedule for a December 2008 in-service date. At December 31, 2006, CL&P has capitalized $40.9 million associated with this project; and

The replacement of the existing 138 KV undersea cable between Connecticut and Long Island, for which design and engineering work for the project is complete, and cable manufacturing commenced in mid-January of 2007. On October 1, 2004, CL&P and the Long Island Power Authority (LIPA) jointly filed plans with the DEP to replace an 11-mile 138 KV undersea electric transmission line between Norwalk 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. CL&P's portion of the project is estimated to cost $72 million. Final permits are expected by mid-2007 with marine construction activities commencing in October of 2007. The project in-service date is expected to be in 2008. At December 31, 2006, CL&P has capitalized $16.9 million associated with this project.

In 2006, CL&P completed construction of a new substation in Killingly, Connecticut, which will improve CL&P's 345 KV and 115 KV transmission systems in northeast Connecticut. At December 31, 2006, CL&P has capitalized $25.9 million associated with this project and estimates the final cost to be approximately $29 million, $3 million below the budget of $32 million.

As part of a larger regional system plan, NU, ISO-NE and National Grid have begun planning upgrades to the transmission system connecting Massachusetts, Rhode Island and Connecticut in a comprehensive study called the Southern New England Transmission Reinforcement (SNETR) Project. That study has led to the identification of three interdependent NU projects that work together to address the region's transmission needs: the Greater Springfield Reliability Project, the Central Connecticut Reliability Project, and the Interstate Reliability Project. Together, these three projects, along with National Grid’s Rhode Island Reliability Project, are referred to as the New England East-West Solution (NEEWS). NU and National Grid have not yet completed a detailed estimate of the total cost for these upgrades, but NU estimates that its share of these projects may range from $1.1 billion to $1.4 billion of which approximately $710 million is included in its $2.5 billion 2007 through 2011 capital budget. NU and National Grid have entered into a formal agreement to plan and permit these projects.

Distribution and Generation: In December of 2003, the DPUC approved in rates $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 2006, CL&P’s distribution capital expenditures were $210.3 million, compared with $254.6 million in 2005 and $254.8 million in 2004. In 2007, CL&P projects an increase in distribution capital expenditures to $270 million.

In 2006, PSNH’s distribution capital expenditures totaled $77.5 million, compared with $73.6 million in 2005 and $84.4 million in 2004. PSNH’s generation capital expenditures were $32.1 million in 2006, compared with $70 million in 2005 and $36.2 million in 2004. In 2007, PSNH’s distribution capital expenditures are expected to be $91 million and its generation capital expenditures are expected to be $37 million. The increase in distribution capital expenditures is due to additional reliability spending. The decline in generation capital expenditures projected for 2007 is due to the completion in 2006 of the Northern Wood Power Project. The project became operational on December 1, 2006. The total cost was on budget at approximately $74 million.

Under the terms of the order issued by the NHPUC approving the Northern Wood Power Project, the costs of the project are subject to a prudence review by the NHPUC, and the cost of the project was capped at $75 million with PSNH and its customers each sharing half of any overrun. While the project's cost was approximately $74 million and PSNH's actions during the construction of the project have been prudent and consistent with industry practices, PSNH is unable to determine the impact, if any, of the NHPUC's prudence review on PSNH's earnings, financial position or cash flows.

In 2006, WMECO's distribution capital expenditures were $30 million, compared with $32.4 million in 2005 and $32.1 million in 2004. In 2007, WMECO projects distribution capital expenditures of approximately $34 million.

In 2006, Yankee Gas’ capital expenditures were $89.9 million, compared with $78.5 million in 2005 and $62 million in 2004. Yankee Gas is constructing an 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 put in service by mid-2007 in time for the 2007/ 2008 heating season. At December 31, 2006, the facility, which is expected to cost $108 million, is 89 percent complete and Yankee Gas had capitalized $95.3 million related to this project. In its order approving the construction of the LNG facility, the DPUC viewed construction of the LNG facility as reasonable in light of expected increases in peak capacity demand and market uncertainties. The DPUC will review the LNG expenditures as part of Yankee Gas' 2007 rate case.

The LNG project represented approximately 54 percent of Yankee Gas’ capital expenditures in 2006. In 2007, Yankee Gas projects total capital expenditures of approximately $62 million. The decline is attributable to the expected completion of the LNG facility.

A summary of projected year end distribution and generation rate base by Utility Group company is as follows (millions of dollars):


	Year
		2007		2008		2009		2010	2011
CL&P	$	1,964	$	2,083	$	2,220	$	2,359	$	2,466
PSNH		974		1,092		1,153		1,225		1,293
WMECO		367		388		406		422		436
Yankee Gas		646		655		656		669		679
Totals	$	3,951	$	4,218	$	4,435	$	4,675	$	4,874

Several factors may impact the Utility Group distribution and generation rate base amounts above, including the level and timing of capital expenditures and plant placed in service, regulatory approval of rate increases and other factors.

NU projects a total of approximately $4.9 billion of Utility Group capital expenditures from 2007 through 2011. A summary of these estimated capital expenditures for the Utility Group transmission and distribution/generation businesses by company for 2007 through 2011, excluding approximately $18 million per year at the corporate service companies, is as follows (millions of dollars):


	Year
		2007		2008		2009		2010	2011		Totals
CL&P:
Transmission	$	590	$	517	$	343	$	231	$	333	$	2,014
Distribution		270		261		266		270		279		1,346
		860		778		609		501		612		3,360
PSNH:
Transmission		83		85		37		35		6		246
Distribution and generation		128		134		111		128		148		649
		211		219		148		163		154		895
WMECO:
Transmission		16		54		45		43		42		200
Distribution		34		33		31		31		31		160
		50		87		76		74		73		360
Yankee Gas distribution		62		42		41		41		41		227
Totals - transmission		689		656		425		309		381		2,460
Totals - distribution and generation		494		470		449		470		499		2,382
Totals	$	1,183	$	1,126	$	874	$	779	$	880	$	4,842

Actual levels of capital expenditures could vary from the estimated amounts for the companies and periods above.

NU Enterprises: NU Enterprises capital expenditures were $20.6 million in 2006, compared with $21.3 million in 2005 and $19.3 million in 2004. A portion of the 2006 capital expenditures related to work performed for the selective catalytic reduction system installed at Mt. Tom. This project was completed in June of 2006 at a cost of $14 million, of which approximately $4.1 million was spent in 2006. On November 1, 2006, Mt. Tom was sold.

NU Enterprises Divestitures

At December 31, 2006, with the completion of the sale of its competitive generation business on November 1, 2006, NU has exited substantially all of the competitive businesses. As a result of exiting these businesses, NU's annual revenues related to NU Enterprises have decreased by approximately $1 billion from 2005 levels. NU is using the net proceeds from the sale of these businesses to invest in its regulated businesses and reduce short-term debt. An overview of this process is as follows:

Wholesale Marketing Business: In 2005, NU exited its New England wholesale electric sales commitments by buying out some contracts and assigning others to a third party. The total pre-tax cost of exiting those commitments in 2005 was approximately $242 million. Select Energy continues to serve its remaining PJM and New York Municipal Power Association (NYMPA) wholesale sales contract obligations, which have been marked-to-market since 2005.

In 2006, Select Energy sold 8.4 million megawatt-hours (MWH) to regulated utilities in the PJM pool, and at December 31, 2006 its estimated remaining obligations through May 31, 2008 totaled 3.6 million MWH. Those obligations are largely hedged (or sourced) through their remaining term, and management does not expect future price movements to cause them to have a material impact on net income in 2007 if loads are served as currently expected. Select Energy has a long-term contract with NYMPA. Under that contract, Select Energy expects to sell an estimated 3.9 million MWH to NYMPA members through 2013 unless it is successful in exiting its remaining obligations. While most of Select Energy’s obligations over the next 5 years are hedged, obligations in the later years are partially unhedged, and Select Energy's financial results can vary based on mark-to-market movements in the unhedged portions of the NYMPA contract. In addition to the contracts noted above, Select Energy’s only other long-term wholesale obligation is a contract to purchase forward reserve in New England through 2012. That contract is expected to be profitable for Select Energy, which will recognize earnings on this contract as the products are delivered. Based on the current value of this contract, when combined with the net wholesale derivative contract portfolio that has been marked-to-market at December 31, 2006 with a value of negative $126.5 million, management believes, under present conditions, that the total cash cost to exit the remaining wholesale marketing business is significantly less than $100 million.

As of December 31, 2006, Select Energy's remaining wholesale sales obligations are estimated to be 7.5 million MWH, down from approximately 22 million MWH in March of 2005 when NU Enterprises announced it was exiting the wholesale marketing business.

Retail Marketing Business: On June 1, 2006, Select Energy sold its retail marketing business to Hess, including all of its retail sales obligations and supply contracts. Under the terms of the agreement, Select Energy paid Hess approximately $11.5 million at closing, $12.9 million in December of 2006 and will pay $14.8 million by the end of 2007, which is included in other current liabilities on the accompanying consolidated balance sheet.

At December 31, 2006, Select Energy has net accounts receivable in the process of being collected of approximately $5 million for services provided to customers prior to the June 1, 2006 sale of the retail marketing business.

Select Energy is in the process of obtaining the final remaining consents from its retail customers to assign contracts to Hess. Those contracts that have not been assigned are subject to administrative arrangements with Hess that mirror Select Energy's obligations.

Competitive Generation Business: On November 1, 2006, NU completed the sale of its 100 percent ownership in NGC stock and Mt. Tom for $1.34 billion, which included ECP's assumption of $320 million of NGC debt. As a result, NU recorded an after-tax gain of approximately $314 million in the fourth quarter of 2006.

Energy Services Businesses: SECI-NH and Woods Network were sold in November of 2005. In January of 2006, the Massachusetts service location of SECI-CT was sold. In April of 2006, NU Enterprises sold Woods Electrical - Services. In May of 2006, SESI was sold.

In connection with the sale of the retail marketing business, the competitive generation business and certain of the energy services businesses, NU provided various guarantees and indemnifications to the purchasers of these businesses. See Note 8H, "Commitments and Contingencies - Guarantees and Indemnifications," for information regarding these items.

NU Enterprises Items Not Sold: Businesses and items that have not yet either been sold or placed under contract to be sold by NU Enterprises are as follows:

Select Energy wholesale contracts (five PJM sales contracts - four of which expire in May of 2007 and one of which expires in May of 2008, one NYMPA sales contract that expires in 2013 and three power purchase contracts - two of which expire in 2007 and one of which expires in 2012);

Remaining assets, liabilities, and contingencies associated with previously exited businesses or companies, including a contract to complete a cogeneration facility;

Contracts associated with the wind down of NGS, Woods Electrical - Other and SECI-CT; and

Boulos

See Note 3, "Assets Held for Sale and Discontinued Operations," for information regarding what businesses are held for sale and discontinued operations at December 31, 2006, and additional information regarding Select Energy's contracts included in the "NU Enterprises" section of this management's discussion and analysis.

At December 31, 2006, $10.7 million in total assets and $15.8 million in total liabilities of NGC, Mt. Tom, SESI, Woods Electrical - Services, SECI-NH, and Woods Network are retained by NU Enterprises. These assets and liabilities are primarily comprised of accounts receivable and unbilled revenues, accounts payable and long-term and short-term debt.

Transmission Rate Matters and FERC Regulatory Issues

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

Transmission - Wholesale Rates: Wholesale transmission revenues are based on rates and formulas that are approved by the FERC. Most of NU's wholesale transmission revenues are collected through a combination of ISO-NE FERC Electric Tariff No. 3, Open Access Transmission Tariff (RNS), and Schedule 21 - NU (LNS) to that tariff. The RNS tariff is administered by ISO-NE and is billed to all New England transmission users. RNS recovers the revenue requirements associated with facilities that are deemed to provide a regional benefit, or pool transmission facilities (PTF). The RNS rate is reset on June 1^stof each year and NU collects approximately 75 percent of its wholesale transmission revenues under its RNS tariff. NU's LNS rate is reset on January 1^st and June 1^st of each year and 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.

FERC ROE Decision: On October 31, 2006, the FERC issued its decision on the RTO ROE and incentives for the New England transmission owners. The FERC set the base ROE (before incentives) at 10.2 percent for the historical locked-in period of February 1, 2005 (when the New England RTO was activated) to October 31, 2006. Effective November 1, 2006, the FERC also added 70 basis points for the true-up to the 10-year treasury rate, bringing the going forward base ROE to 10.9 percent. In addition, the FERC approved a 50 basis point adder for joining an RTO and approved a 100 basis point adder for all new transmission investment where the projects have been identified as necessary by the ISO-NE regional planning process. Both ROE adders for certain projects were retroactive to February 1, 2005.

The following is a summary of the ROEs for the applicable periods and facilities:


	LNS	RNS	New ISO-NE Approved Projects
RTO - February 1, 2005 to October 31, 2006	10.2% (base)	10.7% (10.2% base plus 0.5% for RTO membership)	11.7% (10.7% for RNS plus 100 basis adder)
RTO - November 1, 2006 forward	10.9% (10.2% base plus 0.7% true-up)	11.4% (10.2% base plus 0.5% for RTO membership plus 0.7% true-up)	12.4% (11.4% for RNS plus 100 basis adder)

On a going forward basis, NU's transmission capital program will be largely comprised of regional infrastructure that is included within the regional planning process. Over 90 percent of the company's projected $2.5 billion capital program for 2007 through 2011 is expected to be in this category and is expected to earn the 12.4 percent ROE for regional infrastructure projects as opposed to the 10.9 percent base ROE.

Prior to this decision, the base ROE being utilized in the calculation of LNS transmission wholesale rates was 12.8 percent. The ROE being utilized in the calculation of RNS transmission wholesale rates was 12.8 percent base plus a 50 basis point adder for joining an RTO, or a total of 13.3 percent, plus an additional 100 basis point adder on new regional transmission investment.

In calculating the refunds owed to customers as a result of this FERC ROE decision, the New England Transmission Owners (NETOs) applied the "last clean rate" doctrine. The doctrine provides that FERC may not order refunds down to the rate level determined in the rate proceeding but can only order refunds down to the "last clean rate" authorized by FERC. This creates a refund floor for the locked-in period from February 1, 2005 to October 31, 2006. During this locked-in period, the refund floor is the higher of the ROE level established by FERC’s October 31, 2006 decision or the previously effective ROE level for NU. In NU’s case, the "last clean rate" was 11 percent and as such, refunds for the locked-in period will be refunded to this 11 percent floor. Since prior to this ROE decision the transmission business assumed an ROE of 11.5 percent for the purpose of revenue recognition, the cumulative impact from February 1, 2005 to transmission’s 2006 earnings was approximately $3 million, net of tax. As of December 31, 2006, a total regulatory liability for refunds of $25.6 million has been accumulated and recorded, including interest. As a result, transmission business earnings as of November 1, 2006 include the ROEs in the FERC's October 31, 2006 order. The FERC issued an order accepting the NETOs' compliance filing detailing the ROEs applicable to refunds, but several state regulators and municipal utilities claimed that the New England utilities used incorrect ROEs for the refund calculations. The impact of these claims is not expected to be material.

On November 30, 2006, as a result of the review of the FERC ROE decision, the NETOs jointly filed a rehearing request for an additional 30 basis points for the base ROE to correct what appears to be an error in the FERC’s base ROE calculation. Additionally, several New England public utility commissions, consumer counsels and municipalities have also filed a rehearing request to challenge the 70 basis point treasury bond adder and the 100 basis point adder for new regional transmission investment.

On December 29, 2006, the FERC issued an order stating that it has accepted the various rehearing requests and intends to act on them. This order allows the regional transmission owners to collect tariffs per the ROE order, subject to refund. The order did not include an action date, and until FERC takes some action on the rehearing requests, parties cannot bring an appeal to court.

Other Rate Matters: Effective on February 1, 2006, NU started including 50 percent of construction work in progress (CWIP) for its four major southwest Connecticut transmission projects in its formula rate for transmission service (Schedule 21 - NU (LNS)). The new rates allow NU to collect 50 percent of the construction financing expenses while these projects are under construction. Once transmission projects are included in rate base, NU will earn an appropriate FERC-regulated ROE, and the recording of AFUDC ceases.

On July 20, 2006, the FERC issued final rules promoting transmission investment through pricing reform that included up to 100 percent of CWIP in rate base, accelerated book depreciation, and higher ROEs for belonging to an RTO, among others. The final rule identifies specific incentives the FERC will allow when justified in the context of specific rate applications. The burden remains on the applicant, such as NU's transmission businesses, to illustrate through its filing that the incentives requested are just and reasonable and the project involved increases reliability or decreases congestion costs. The FERC reaffirmed these incentives in its order on rehearing issued on December 22, 2006.

On July 28, 2006, the FERC approved NU's proposal to allocate costs associated with the Bethel to Norwalk transmission project that are determined to be localized costs to all customers in Connecticut as all of Connecticut will benefit from the associated reduction in congestion charges. There are three load serving entities in Connecticut: CL&P, UI and the Connecticut Municipal Electrical Energy Cooperative. These customers began paying their allocated shares of the localized costs on a projected basis commencing on June 1, 2006, subject to true-up based on actual costs. On December 26, 2006, FERC rejected a UI request for rehearing of this decision. On February 23, 2007, UI appealed the FERC's orders to the D.C. Circuit Court of Appeals (Court of Appeals).

On September 22, 2006, ISO-NE issued its determination letter with respect to CL&P's February 3, 2006 revised transmission cost allocation (TCA) application for the Bethel to Norwalk transmission project. The decision finds that $239.8 million of the total estimated cost of $357.2 million qualifies as pool-supported PTF costs, indicating $117.4 million of total estimated costs will be localized. If the $357.2 million estimated cost is lower, the amounts related to pool supported PTF costs and localized costs will be proportionally reduced. CL&P has decided not to challenge the ISO-NE cost allocation decision. In July of 2007, the final cost of the Bethel to

Norwalk project will be included in NU's LNS tariff annual true-up mechanism, and the amounts related to the pool supported PTF costs and localized costs will be proportionally adjusted to reflect the project's final cost.

Legislative Matters

Connecticut:

Act Concerning Energy Independence: Public Act 05-01, an "Act Concerning Energy Independence," (Act) was signed by Governor Rell on July 22, 2005. The legislation provides incentives to encourage the construction of distributed generation, new large-scale generation, and conservation and load management initiatives to reduce federally mandated congestion cost (FMCC) charges. The legislation requires regulators to a) implement near-term measures as soon as possible and b) commence new request for proposals (RFP) to build customer-side distributed resources and contracts for new or repowered larger generating facilities in the state. Developers could receive contracts of up to 15 years from Connecticut distribution companies, including CL&P. The legislation provides utilities with the opportunity to earn one-time awards for generation that is installed in their service territories. The legislation requires the DPUC to investigate the financial impact of entering into long-term contracts on distribution companies and to allow distribution companies to recover any increased costs through rates. On December 28, 2005, the DPUC ruled in response to CL&P's argument that the financial impact of any such contracts is hypothetical and instructed the utilities to raise the issue in subsequent rate cases. CL&P appealed this decision. CL&P and the DPUC entered into a settlement agreement that would provide CL&P with some additional protection not included in the December 28, 2005 decision. The DPUC has also been conducting other proceedings to implement the Act.

On March 27, 2006, the DPUC issued final decisions that would allow distribution companies, including CL&P, to be eligible for awards in 2006 and 2007 of $200 per KW for customer-side distributed generation when these units become operational. Earnings in 2006 related to this incentive were de minimis. In addition, under the Act, CL&P earns incentives of $25/KW-year for conservation programs that it has developed in 2006.

On September 13, 2006, under the provisions of the Act, the DPUC issued an interim decision containing an RFP that solicited customer-side distributed resources, grid-side distributed resources, and new generation facilities, including expanded or repowered generation. Winning bidders may be awarded contracts up to 15 years with the state's electric utilities, including CL&P. The DPUC-approved contract structure for the RFP is a "contract for differences," which will require each winning bidder to be paid the difference, if any, between a fixed contract price and the applicable ISO-NE wholesale capacity market price. The DPUC requested bids in December of 2006. Winning bids are expected to be selected in April of 2007 and executed contracts will be approved no later than November 8, 2007. The DPUC will determine the amount and duration of any such contracts.

New Hampshire:

Environmental Legislation: In April of 2006, New Hampshire adopted legislation requiring PSNH to reduce the level of mercury emissions from its coal-fired plants by 2013 with incentives for early reductions. To comply with the legislation, PSNH intends to install wet scrubber technology by mid-2013 at its two Merrimack coal units, which combined generate 433 MW. PSNH currently anticipates the cost to comply with this law to be $250 million, but this amount has the potential to increase materially as the project is undertaken, primarily as a result of changes in commodity prices and labor costs. NU expects that this project will have a positive impact on NU’s earnings, as state law and PSNH's restructuring settlement agreement provide for the recovery of its generation costs from its customers, including the cost to comply with state environmental regulations.

Utility Group Regulatory Issues and Rate Matters

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 2005, CL&P began tracking its retail transmission revenues and expenses for recovery. WMECO implemented its retail transmission tracker and rate adjustment mechanism in January of 2002 as part of its 2002 rate change filing. PSNH does not currently have a retail transmission rate tracking mechanism, but the company requested such a mechanism in its 2006 rate case. Such a mechanism was also included in the rate case settlement agreement that PSNH reached with the NHPUC staff and the OCA that was filed with the NHPUC.

Forward Capacity Market: On March 6, 2006, ISO-NE and a broad cross-section of critical stakeholders from around the region, including CL&P, PSNH and Select Energy, filed a comprehensive settlement agreement at the FERC proposing a forward capacity market (FCM) in place of the previously proposed LICAP, an administratively determined electric generation capacity pricing mechanism. The settlement agreement provided 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. According to preliminary estimates, FCM would require NU's operating companies to pay approximately the following amounts from December 1, 2006 through December 31, 2009: CL&P - $470 million; PSNH - $80 million; and WMECO - $100 million. CL&P, PSNH and WMECO expect to recover these costs from their ratepayers. On June 16, 2006, the FERC approved the settlement agreement. Rehearing of this issue was sought by several parties, which was denied by the FERC on October 31, 2006. Several parties also challenged the FERC's approval of the settlement agreement and that challenge is now pending in the Court of Appeals. In addition, ISO-NE has received approval from FERC on many of the rules that implement the terms of the settlement agreement. On December 1, 2006, the settlement agreement was implemented and the payment of fixed compensation to generators began.

Connecticut - CL&P:

Income Taxes: In 2000, CL&P requested from the IRS a PLR regarding the treatment of unamortized investment tax credits (UITC) and excess deferred income taxes (EDIT) related to generation assets that were sold. On April 18, 2006, the IRS issued a PLR to CL&P regarding the treatment of UITC and EDIT. EDIT are temporary differences between book and taxable income that were recorded when the federal statutory tax rate was higher than it is now or when those differences were expected to be resolved. The PLR holds that it would be a violation of tax regulations if the EDIT or UITC are used to reduce customers' rates following the sale of the generation assets. CL&P's UITC and EDIT balances related to generation assets that have been sold totaled $59 million and $15 million, respectively, and $74 million combined. CL&P was ordered by the DPUC to submit the PLR to the DPUC within 10 days of issuance and retain the UITC and EDIT in their existing accounts pending its receipt and review of the PLR. On July 27, 2006, the DPUC determined that the UITC and EDIT amounts were no longer required to be held in their existing accounts. As a result of this determination, the $74 million balance was reflected as a reduction to CL&P's 2006 income tax expense with an increase to CL&P's earnings by the same amount.

Procurement Fee Rate Proceedings: CL&P was allowed to collect a fixed procurement fee of 0.50 mills per KWH from customers who purchase Transitional Standard Offer (TSO) service through 2006. One mill is equal to one-tenth of one cent. That fee can increase to 0.75 mills per KWH if CL&P outperforms certain regional benchmarks. CL&P submitted to the DPUC its proposed methodology to calculate the variable portion (incentive portion) of the procurement fee and 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 as proposed by CL&P and authorized payment of the $5.8 million incentive fee. A final decision, which had been scheduled for December 28, 2005, was delayed by the DPUC, and the DPUC re-opened the docket to allow the Office of Consumer Counsel (OCC) to submit additional testimony.

On December 1, 2006, the DPUC issued an RFP to secure a consultant to review CL&P's and UI's TSO incentive methodologies and requested comment from all parties on the use of an appropriate statistical margin of error for calculating incentive payments which were due to be filed on January 11, 2007. The DPUC has not established a schedule beyond the January 11, 2007 comment deadline.

Management continues to believe that recovery of the $5.8 million asset related to CL&P's 2004 incentive payment, which was reflected in 2005 earnings, is probable. No amounts have been recorded in 2006 related to the 2005 or 2006 incentive portions of CL&P's procurement fee; however, a preliminary estimate of $3.3 million for 2006 and $3.6 million for 2005 would be recognized in earnings if CL&P's methodology is upheld. The statute allowing collection of a procurement fee expired on January 1, 2007.

Streetlighting Decision: On June 30, 2005, the DPUC issued a final decision that required CL&P to recalculate all previously issued refunds (except for the towns of Stamford and Middletown) utilizing applicable approved pre-tax cost of capital rates. The net impact in 2005 was an additional $4.1 million of pre-tax reserve. On August 11, 2005, CL&P filed an appeal of this decision to the Connecticut Superior Court. On August 29, 2006, the court issued its final decision on CL&P's appeal, which resulted in a 2006 after-tax reduction of $0.6 million to the streetlighting refund reserve.

In December of 2006, the DPUC ruled that CL&P’s refund methodology was acceptable and ordered CL&P to issue refund checks to eligible municipalities by January 5, 2007. In compliance with that order, CL&P refunded approximately $7.4 million to eligible towns in January of 2007.

Distribution Rates: For CL&P, a $25 million distribution rate increase took effect on January 1, 2005 with an additional $11.9 million distribution rate increase which took effect on January 1, 2006 and another $7 million distribution rate increase which took effect on January 1, 2007.

On August 4, 2006, CL&P notified Connecticut Governor Rell and the DPUC that it intends to postpone filing a distribution rate case until mid-2007 for rates effective in early 2008.

FMCC Filings: On February 1, 2006, CL&P filed with the DPUC a semi-annual reconciliation of FMCC charges for the year ended December 31, 2005. On October 25, 2006, the DPUC issued a final decision that approved the reconciliation and required no adjustment to FMCC rates for 2006.

On August 1, 2006, CL&P filed with the DPUC a semi-annual reconciliation of FMCC charges for the period January 1, 2006 through June 30, 2006. Concurrent with the proceeding that had begun related to this filing, the DPUC re-opened other dockets for the purpose of establishing all of CL&P’s unbundled retail rates for 2007. As part of these re-opened dockets, CL&P requested and was granted changes in its FMCC rates to begin January 1, 2007 that would collect 2007 FMCC net of projected overcollections related to FMCC for the period January 1, 2006 through December 31, 2006. As a result, no further change in FMCC rates is anticipated from the completion of the proceeding related to the semi-annual reconciliation period of January 1, 2006 through June 30, 2006.

Standard Service Procurement and Rates: On June 21, 2006, the DPUC approved a proposal by CL&P to issue RFPs periodically for periods from three months to three years to layer the standard service full requirements supply contracts to mitigate market volatility for its residential and lower-use commercial and industrial customers. Additionally, the DPUC approved the issuance of RFPs for supplier of last resort service for larger commercial and industrial customers every six months. Previously, all of CL&P's residential, commercial and industrial requirements, regardless of customer size, were bid together on an annual basis.

In September of 2006, CL&P received bids and awarded contracts for a portion of standard service for 2007 and 2008. In October of 2006, bids were received and contracts awarded for an additional portion of the standard service for 2007 through 2009. CL&P expects to receive bids during the first quarter of 2007 for standard service for the remaining 2007 requirements and for a portion of the requirements for 2008 and 2009. CL&P also received bids and awarded contracts in September 2006 for its supplier of last resort service for its larger commercial and industrial customers for January 2007 through June 2007.

On December 8, 2006, the DPUC approved CL&P’s standard service rates effective on January 1, 2007. The new standard service rates reflect an increase of approximately 7.8 percent and are expected to remain in effect until July 1, 2007 when these rates will likely be adjusted to reflect additional supplier bids received for 2007 and updated wholesale transmission costs. Supplier of last resort rates will vary, and total bills for those customers increased by 19 percent on January 1, 2007. CL&P is fully recovering the cost of its standard service supply.

CTA and SBC Reconciliation: The Competitive Transition Assessment (CTA) allows CL&P to recover stranded costs, such as securitization costs associated with its rate reduction bonds, amortization of regulatory assets, and independent power producer over-market costs, while the System Benefits Charge (SBC) allows CL&P to recover certain regulatory and energy public policy costs, such as public education outreach costs, hardship protection costs, transition period property taxes, and displaced worker protection costs.

On March 31, 2006, CL&P filed its 2005 CTA and SBC reconciliation, which compared CTA and SBC revenues to revenue requirements, with the DPUC. For the year ended December 31, 2005, total CTA revenues exceeded the CTA cost of service by $60.1 million. This amount was recorded as a regulatory liability on the accompanying consolidated balance sheets. For the same period, the SBC cost of service exceeded SBC revenues by $1.3 million. On July 24, 2006, the DPUC issued a final decision that approved the reconciliation of the CTA and SBC rates for the year 2005.

In CL&P's 2001 CTA and SBC reconciliation, 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 cost of service. This liability was included as a reduction in the calculation of CTA cost of service. 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. On June 20, 2006, the Connecticut Superior Court denied CL&P's appeal. On November 1, 2006, the aforementioned generation assets were sold by NGC. As a result of this sale, the intercompany liability and its related decrease to revenue requirements will no longer be reflected as a component of the CTA effective with the November 1, 2006 sale date.

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 short-term 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 on July 1, 2005, which includes two adjustments annually, on January 1^st and July 1^st. 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. On July 1, 2006, CL&P raised its transmission rates by an incremental $6.1 million on an annual basis. Rates effective on January 1, 2007 reflected no increase to the overall average retail transmission rate.

Connecticut - Yankee Gas:

Purchased Gas Adjustment: On September 9, 2005, the DPUC issued a draft decision regarding Yankee Gas Purchased Gas Adjustment (PGA) clause charges for the period of September 1, 2003 through August 31, 2004. The draft decision disallowed approximately $9 million in previously recovered PGA revenues associated with two separate Yankee Gas unbilled sales and revenue adjustments. At the request of Yankee Gas, the DPUC reopened the PGA hearings on September 20, 2005 and requested that Yankee Gas file supplemental information regarding the two adjustments. Yankee Gas complied with this request. The DPUC issued a new decision on April 20, 2006 requiring an audit of Yankee Gas' previously recovered PGA costs and deferred any conclusion on the $9 million of previously recovered revenues until the completion of the audit. In a recent draft decision regarding Yankee Gas PGA charges for the period September 1, 2004 through August 31, 2005, an additional $2 million related to previously recovered revenues was also identified, bringing the total maximum amount at issue with regard to PGA clause charges under audit to $11 million.

The DPUC has hired a consulting firm which has begun an audit of Yankee Gas' previously recovered PGA costs. The company expects that the audit will be completed in the first half of 2007. Management believes the unbilled sales and revenue adjustments and resulting charges to customers through the PGA clause for both periods were appropriate. Based on the facts of the case and the supplemental information provided to the DPUC, management believes the appropriateness of the PGA charges to customers for the time period under review will be approved, and has not reserved for any loss.

Yankee Gas Rate Relief: On December 29, 2006, Yankee Gas filed a request with the DPUC for a rate increase of approximately $67.8 million effective on July 1, 2007. The request proposes to recover its LNG facility costs and increased cost of providing distribution delivery service. Yankee Gas expects that the increase will be offset by projected commodity and pipeline-related savings, for a net revenue increase of $37.2 million or 8.4 percent above current rates.

New Hampshire:

SCRC Reconciliation and SCRC Rates: On an annual basis, PSNH files with the NHPUC a stranded cost recovery charge (SCRC) reconciliation filing for the preceding calendar year. The NHPUC reviews the filing, including a prudence review of the operations within PSNH‘s generation business. On May 1, 2006, PSNH filed its 2005 SCRC reconciliation with the NHPUC. On October 25, 2006, PSNH, the NHPUC staff and the OCA filed a settlement agreement with the NHPUC which resolved all outstanding issues associated with the 2005 reconciliation. After the NHPUC hearings held in October of 2006, the NHPUC issued its order affirming the settlement agreement. The terms of the settlement agreement had virtually no impact on PSNH's financial statements.

On September 22, 2006, PSNH filed a petition with the NHPUC requesting a change in its SCRC rate for the period January 1, 2007 through December 31, 2007. PSNH requested that the NHPUC review and approve the underlying data in this filing. On November 17, 2006, PSNH filed a revised petition with the NHPUC on the SCRC rate, which was approved by the NHPUC on December 15, 2006 and resulted in a decline in the SCRC rate to $0.0130 per KWH effective in 2007.

ES and ES Rates: In accordance with a restructuring settlement and state law, PSNH files for updated Energy Service (ES) rates 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 December 2, 2005, the NHPUC issued a decision lowering PSNH’s allowed ES ROE from 11 percent to 9.62 percent that was retroactive to an effective date of August 1, 2005. PSNH's request for reconsideration of that decision by the NHPUC was denied. On May 17, 2006, the New Hampshire Supreme Court declined to consider PSNH’s appeal of the NHPUC's decision. This decrease in allowed ES ROE lowers PSNH’s net income by approximately $1.5 million annually based on the current level of generation asset investment.

On January 20, 2006, the NHPUC approved new ES rates of $0.0913 per KWH for the eleven-month period of February 1, 2006 through December 31, 2006. In its order, the NHPUC also allowed PSNH to implement deferred accounting treatment for the new accounting associated with asset retirement obligations (AROs). On June 29, 2006, the NHPUC decreased the ES rate to $0.0818 per KWH based upon updated cost information for the period July 1, 2006 through December 31, 2006.

On September 8, 2006, PSNH filed a petition with the NHPUC requesting a change in its ES rate for the period January 1, 2007 through December 31, 2007. Consistent with previous filings, PSNH requested that the NHPUC review and approve the underlying operational data in this filing and not the specific ES rate. The underlying operational data in this filing included the projected costs and credits associated with the Northern Wood Power Project, which went into service on December 1, 2006. On November 17, 2006, PSNH filed a revised petition with the NHPUC requesting approval of an ES rate of $0.0859 per KWH based upon current energy market data. On December 15, 2006, the NHPUC approved the proposed ES rate, increasing the ES rates to $0.0859 per KWH effective in 2007. As in previous NHPUC ES rate orders, there is a provision to update the ES rate during the 2007 rate year based upon updated actual and projected cost information.

Under the terms of the order issued by the NHPUC approving the Northern Wood Power Project, certain revenue credits are shared between PSNH and its customers. These credits include renewable energy certificates (RECs), which are sold to other utilities, and production tax credits. In any given year, if the combination of REC revenues and production tax credits fall short of a stipulated revenue level, PSNH and its customers each share half of any deficiency and if the combination exceeds the stipulated revenue level, PSNH and its customers each share half of any subsequent REC sales revenues.

DS Rate Case: On May 30, 2006, PSNH filed a petition with the NHPUC requesting an increase in its delivery service (DS) rate by approximately $50 million, the approval of a transmission cost tracking mechanism, a decrease in its stranded cost charge and energy charge to reflect the completed recovery of certain stranded costs and changes in PSNH's actual costs to provide energy service. On June 29, 2006, the NHPUC approved the temporary DS rate increase of $24.5 million effective on July 1, 2006 and approved the decrease in the stranded cost and energy charges. On November 17, 2006, PSNH updated its DS rate filing, increasing the request to $60 million.

On February 26, 2007, PSNH filed a settlement agreement it reached with the NHPUC staff and the OCA related to its rate case filing. The settlement agreement includes, among other things, a transmission cost tracking mechanism, effective on July 1, 2006, to be reset annually, and an allowed ROE of 9.67 percent. The allowed generation ROE of 9.62 percent was unaffected. The settlement provides for a $37.7 million estimated annualized increase ($26.5 million for distribution and $11.2 million estimated for transmission) beginning July 1, 2007 in addition to the $24.5 million temporary increase that was effective on July 1, 2006. An additional delivery revenue increase of approximately $3 million would take effect on January 1, 2008, with a final estimated rate decrease of approximately $9 million scheduled for July 1, 2008. The increased revenues will enable PSNH to fund a $10 million annual Reliability Enhancement Program and more accurately fund its Major Storm Cost Reserve. The increased revenues also include approximately $9 million related to additional revenues for the period July 1, 2006 through June 30, 2007 that will be recovered over one year. The NHPUC has scheduled hearings on the proposed settlement beginning in March 2007, with a final decision expected by late spring of 2007.

Coal Procurement Docket: During 2006, the NHPUC opened a docket to review PSNH's coal procurement and coal transportation policies and procedures. PSNH has responded to data requests from the NHPUC's outside consultant. 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 NHPUC's review on PSNH's earnings, financial position or cash flows.

Massachusetts:

2006 Rate Case Settlement: On December 14, 2006, the DTE approved a settlement agreement among WMECO, the Massachusetts Attorney General, the Associated Industries of Massachusetts and Low-Income Energy Affordability Network, that included distribution rate increases of $1 million beginning on January 1, 2007 and an additional $3 million increase beginning on January 1, 2008. Also included in the settlement agreement are cost tracking mechanisms for pension and other postretirement benefit costs, bad debts related to energy costs, and recovery of certain capital improvements and related expenses needed for system reliability. These costs will be recovered through rates charged to customers. The settlement agreement includes an earnings sharing mechanism that will equally share with customers any earnings in excess of an actual ROE of 12 percent and any shortfall below an actual ROE of 8 percent during the two-year settlement period. The determination of any excess or shortfall will be done annually, with any such excess being recorded as a regulatory liability and any such shortfall being recorded as a regulatory asset. The time period for the refund of any excess or collection of any shortfall will be determined by the DTE. Under this settlement agreement, management expects that an ROE between 9 percent and 10 percent annually is achievable for WMECO in 2007 and 2008.

Annual Rate Change Filing: On November 30, 2006, WMECO made its 2006 annual rate change filing implementing the $1 million distribution rate increase and associated cost tracking mechanisms as allowed under its rate case settlement agreement and reflecting rate increases for 2007 default service supply. On average, total rates increased by 17.8 percent. On December 29, 2006, the DTE approved the rates effective on January 1, 2007.

Transition Cost Reconciliation: On October 24, 2006, the DTE issued its decision in WMECO's 2003 and 2004 transition cost reconciliation filing. The DTE decision in this combined docket resolves all outstanding issues through 2004 for transition, retail transmission, standard offer and default service costs/revenues and did not have a significant impact on WMECO's earnings, financial position or cash flows.

WMECO filed its 2005 transition cost reconciliation with the DTE on March 31, 2006. The DTE has not yet reviewed this filing or issued a schedule for review, and the timing of a decision is uncertain. Management does not expect the outcome of the DTE's review to have a significant adverse impact on WMECO's earnings, financial position or cash flows.

Deferred Contractual Obligations

NU has significant decommissioning and plant closure cost obligations to the Yankee Companies. 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. A summary of each of NU's subsidiaries' ownership percentages in the Yankee Companies at December 31, 2006 is as follows:


	CYAPC		YAEC		MYAPC
CL&P		34.5%		24.5%		12.0%
PSNH		5.0%		7.0%		5.0%
WMECO		9.5%		7.0%		3.0%
Totals		49.0%		38.5%		20.0%

CYAPC: On July 1, 2004, CYAPC filed with the FERC seeking to increase its annual decommissioning collections from $16.7 million to $93 million for a six-year period of January 1, 2005 to January 1, 2011. On August 30, 2004, the FERC issued an order accepting the rates, with collection by CYAPC beginning on February 1, 2005, subject to refund.

On June 10, 2004, the DPUC and the OCC filed a petition with the FERC seeking a declaratory order that CYAPC be allowed to recover all decommissioning costs from its wholesale purchasers, including CL&P, PSNH and WMECO, but that such purchasers may not be allowed to recover in their retail rates any costs that the FERC might determine to have been imprudently incurred. The FERC rejected the DPUC's and OCC's petition, whereupon the DPUC filed an appeal of the FERC's decision with the Court of Appeals.

On August 15, 2006, CYAPC, the DPUC, the OCC and Maine state regulators filed a settlement agreement with the FERC. The settlement agreement was approved by the FERC on November 16, 2006 and disposes of the pending litigation at the FERC and the Court of Appeals, among other issues.

Under the terms of the settlement agreement, the parties have agreed to a revised decommissioning estimate of $642.9 million (in 2006 dollars), taking into account actual spending through 2005 and the current estimate for completing decommissioning and long-term storage of spent fuel, a gross domestic product escalator of 2.5 percent for costs incurred after 2006, a 10 percent contingency factor for all decommissioning costs and extension of the collection period by five years. Annual collections began in January of 2007, and are reduced from the $93 million originally requested for years 2007 through 2010 to lower levels ranging from $37 million in 2007 rising to $49 million in 2015.

The reduction to annual collections is achieved by extending the collection period by 5 years through 2015, reflecting the proceeds from a settlement agreement with Bechtel Power Corporation (Bechtel), by reducing collections in 2007, 2008 and 2009 by $5 million per year, and making other adjustments. Additionally, the settlement agreement includes an incentive that reduces collections up to $10 million during years 2007 to 2010, but allows CYAPC to recoup up to $5 million of these collections, depending on the date that the Nuclear Regulatory Commission amends CYAPC's license permitting fuel storage-only operations. The settlement agreement also contains various mechanisms for true-ups and adjustments related to decommissioning and allows CYAPC to resume reasonable payment of dividends to its shareholders.

The settlement agreement also required CYAPC to forego collection of a $10 million regulatory asset that was written-off in 2006. NU included in 2006 earnings its 49 percent share of CYAPC's after-tax write-off.

YAEC: In November of 2005, YAEC established an updated estimate of the cost of completing the decommissioning of its plant. On January 31, 2006, the FERC issued an order accepting the rate increase, effective on February 1, 2006, subject to refund.

On July 31, 2006, the FERC approved a settlement agreement with the DPUC, the Massachusetts Attorney General and the Vermont Department of Public Service previously filed by YAEC. This settlement agreement did not materially affect the level of 2006 charges. Under the settlement agreement, YAEC agreed to revise its November 2005 decommissioning cost increase from $85 million to $79 million. The revision includes adjustments for contingencies and projected escalation and certain decontamination and dismantlement (D&D) expenses. Other terms of the settlement agreement include extending the collection period for charges through December 2014, reconciling and adjusting future charges based on actual D&D expenses and the decommissioning trust fund's actual investment earnings. The company believes that its $24.9 million share of the increase in decommissioning costs will ultimately be recovered from the customers of CL&P and WMECO (approximately $19.4 million and $5.5 million for CL&P and WMECO, respectively). PSNH has recovered its $5.5 million share of these costs.

MYAPC: MYAPC is collecting amounts in rates that are adequate to recover the remaining cost of decommissioning its plant, and CL&P and WMECO expect to recover their respective shares of such costs from their customers. PSNH has recovered its share of these costs.

Spent Nuclear Fuel Litigation: In 1998, CYAPC, YAEC and MYAPC filed separate complaints against the DOE in the Court of Federal Claims seeking monetary damages resulting from the DOE's failure to begin accepting spent nuclear fuel for disposal no later than January 31, 1998 pursuant to the terms of the 1983 spent fuel and high level waste disposal contracts between the Yankee Companies and the DOE. In 2004, a trial was conducted in the Court of Federal Claims in which the Yankee Companies initially claimed damages for incremental spent nuclear fuel storage, security, construction and other costs through 2010.

In a ruling released on October 4, 2006, the Court of Federal Claims held that the DOE was liable for damages to CYAPC for $34.2 million through 2001, YAEC for $32.9 million through 2001 and MYAPC for $75.8 million through 2002. The Yankee Companies had claimed actual damages for the same period as follows: CYAPC: $37.7 million; YAEC: $60.8 million; and MYAPC: $78.1 million. Most of the reduction in the claimed actual damages related to disallowed spent nuclear fuel pool operating expenses. The Court of Federal Claims found that the Yankee Companies would have incurred the disallowed expenses notwithstanding the DOE breach given the DOE's probable rate of acceptance of spent nuclear fuel had a depository been available.

The Court of Federal Claims, following precedent set in another case, also did not award the Yankee Companies future damages covering the period beyond the 2001/2002 damages award dates. The Yankee Companies believe they will have the opportunity in future lawsuits to seek recovery of actual damages incurred in the years following 2001 and 2002.

In December of 2006, the DOE appealed the ruling, and the Yankee Companies filed a cross-appeal. The refund to CL&P, PSNH and WMECO of any damages that may be recovered from the DOE will be realized through the Yankee Companies' FERC-approved rate settlement agreements, subject to final determination of the FERC.

CL&P, PSNH and WMECO's aggregate share of these damages would be $44.7 million. Their respective shares of these damages would be as follows: CL&P: $29 million; PSNH: $7.8 million; and WMECO: $7.9 million. CL&P, PSNH and WMECO cannot at this time determine the timing or amount of any ultimate recovery or the credit to future storage costs that may be realized in connection with this matter.

Uranium Enrichment Litigation: In 2001, NU asserted claims against the DOE in the Court of Federal Claims for overcharges for purchases of uranium enrichment separative work units (SWUs) for CYAPC's unit and the Millstone units between 1986 and 1993 (D&D Claims). The NU case was stayed by the Court of Federal Claims while other D&D Claims cases were being litigated. Beginning in 2005, NU joined a number of other utilities in a consortium in an attempt to negotiate a settlement agreement with the DOE. In late-2006, a settlement was reached between the consortium and the DOE. The distribution of proceeds under the settlement agreement totals approximately $0.8 million for CYAPC and approximately $1.4 million for Millstone and the Millstone portion was received on January 30, 2007. This distribution is based on the total number of SWUs purchased for CYAPC's unit and the Millstone units during the applicable period covered by the litigation. The company believes it is likely that the net proceeds from the settlement agreement will be credited to ratepayers. Prior to March 31, 2001, CL&P, PSNH and WMECO collectively owned 100 percent of Millstone 1 and 2 and 68.02 percent of Millstone 3.

NU Enterprises

Merchant Energy Business: At December 31, 2006, the merchant energy business is comprised of Select Energy’s remaining wholesale marketing business.

Energy Services Business: At December 31, 2006, the energy services business is comprised of NGS, Woods Electrical - Other, Boulos, and SECI-CT, which is a division of SECI. NGS provides maintenance, operations and testing services. Boulos provides third-party electrical services. Woods Electrical - Other and SECI-CT are in the wind down stage.

For information regarding the current status of the exit from the merchant energy and energy services businesses in 2005 and 2006, see "NU Enterprises Divestitures," included in this management's discussion and analysis.

Intercompany Transactions: There were no CL&P TSO purchases from Select Energy in 2006 or 2005 and $502 million in 2004. Other energy purchases between CL&P and Select Energy totaled $6.1 million, $53.4 million and $109.3 million in 2006, 2005 and 2004, respectively. WMECO was paid $4.4 million by Select Energy in 2006, while WMECO paid Select Energy $36.3 million and $108.5 million in 2005 and 2004, respectively.

Select Energy purchases from NGC and Mt. Tom represented $160.7 million, $209.7 million and $195.4 million the years ended December 31, 2006, 2005, and 2004, respectively. As a result of the sale of NGC and Mt. Tom, Select Energy's purchases from NGC and Mt. Tom ended on November 1, 2006.

Risk Management: From 2000 through 2006, NU Enterprises, through its subsidiaries, engaged in a broad variety of energy related businesses including the sale of competitive retail and wholesale gas and electricity services, electric generation and energy services, primarily in New England, New York and PJM. Implementation of the decision to exit all of its competitive businesses has reduced significantly the risk profile of NU Enterprises. NU Enterprises will continue to be exposed to certain market risks under its remaining wholesale contracts until they expire or are exited. Market risk at this point is comprised of the possibility of adverse energy commodity price movements affecting the unhedged portion of the remaining positions and, in the case of the wholesale marketing business, unexpected load ingress or egress.

As part of NU's overall enterprise risk management (ERM) process, NU Enterprises operates under a risk oversight policy for managing both the market and credit risk associated with its remaining portfolio. Under this policy, weekly meetings are held with NU Enterprises' leadership, and periodic meetings are held with NU leadership to review conformity to this policy. In addition, reviews are held with NU and NU Enterprises leadership upon the occurrence of specific portfolio-triggered events that result in portfolio losses that exceed risk oversight policy loss limits.

Wholesale Contracts: As a result of NU's decision to exit the wholesale marketing business, certain wholesale energy contracts previously accounted for under accrual accounting began to be marked-to-market in the first quarter of 2005 with changes in fair value reflected in the statements of income/(loss).

At December 31, 2006 and 2005, the fair value of Select Energy's wholesale derivative assets and derivative liabilities, which are subject to mark-to-market accounting, are as follows:


	December 31,
(Millions of Dollars)	2006		2005
Current wholesale derivative assets	$	43.6	$	256.6
Long-term wholesale derivative assets		22.3		103.5
Current wholesale derivative liabilities		(82.3)		(369.3)
Long-term wholesale derivative liabilities		(110.1)		(220.9)
Portfolio position	$	(126.5)	$	(230.1)

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

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

The methods Select Energy used to determine the fair value of its wholesale energy contracts are identified and segregated in the table of fair value of contracts at December 31, 2006 and 2005. A description of each method is as follows: 1) prices actively quoted primarily represent New York Mercantile Exchange (NYMEX) futures and swaps that are marked to closing exchange prices; and 2) prices provided by external sources primarily include over-the-counter forwards and options, including bilateral contracts for the purchase or sale of electricity, and are marked to the mid-point of bid and ask market prices. The mid-points of market prices are adjusted to include all applicable market information, such as prior contract settlements with third parties. Currently, Select Energy also has a contract for which a portion of the contract's fair value is determined based on a model. The model utilizes natural gas prices and a conversion factor to electricity for the years 2012 through 2013. Broker quotes for electricity at locations for which Select Energy has entered into transactions are generally available through the year 2011.

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

As of and for the years ended December 31, 2006 and 2005, 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, 2006
Sources of Fair Value	Maturity Less than One Year		Maturity of One to Four Years		Maturity in Excess of Four Years		Total Fair Value
Prices actively quoted	$	(6.9)	$	(11.2)	$	(1.9)	$	(20.0)
Prices provided by external sources		(32.2)		(44.8)		(12.7)		(89.7)
Model-based		0.4		3.5		(20.7)		(16.8)
Totals	$	(38.7)	$	(52.5)	$	(35.3)	$	(126.5)


(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)
Model-based		0.7		(10.3)		(25.9)		(35.5)
Totals	$	(115.5)	$	(85.9)	$	(28.7)	$	(230.1)


	Years Ended December 31,
	2006		2005
	Total Portfolio Fair Value
(Millions of Dollars)
Fair value of wholesale contracts outstanding at the beginning of the year	$	(230.1)	$	(48.9)
Contracts realized or otherwise settled during the year		118.9		254.2
Changes in fair value recorded:
Fuel, purchased and net interchange power		(15.4)		(462.7)
Operating revenues		0.1		13.1
Changes in model-based assumption included in operating revenues		-		14.2
Fair value of wholesale contracts outstanding at the end of the year	$	(126.5)	$	(230.1)

Select Energy has a wholesale non-derivative generation purchase contract expiring in 2012. At December 31, 2006, this contract had a positive fair value of approximately $100 million, that, as a non-derivative contract, has not been recorded in the financial statements.

Changes in the fair value of wholesale contracts that were marked-to-market as a result of the decision to exit the wholesale marketing business totaled a negative $10.9 million and $419 million for the years ended December 31, 2006 and 2005, respectively, and are recorded as fuel, purchased and net interchange power on the accompanying consolidated statements of income/(loss). Changes in the fair value of contracts within the New England and PJM portfolio and a generation purchase contract in New York totaling a negative $4.5 million and $43.7 million for the years ended December 31, 2006 and 2005, respectively, are also recorded as fuel, purchased and net interchange power. Changes in fair value of contracts formerly designated as trading totaling a positive $0.1 million and $13.1 million for the years ended December 31, 2006 and 2005, respectively, are recorded as revenue on the consolidated statements of income/(loss).

In the first quarter of 2005, the mark-to-market of Select Energy’s wholesale contracts increased by $14.2 million as a result of removing 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.

During the fourth quarter of 2005, Select Energy assigned a wholesale contract for $55.9 million with payments commencing in January of 2006 and ending in December of 2008. This amount is included in the 2005 contracts realized or otherwise settled during the year amount of $254.2 million. 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. The payments under this assignment bear interest at 12.5 percent. If certain conditions are met, these payments could be accelerated.

Retail Marketing Activities: Select Energy sold its retail marketing business to Hess on June 1, 2006.

At December 31, 2006, Select Energy had derivative assets and liabilities totaling $0.2 million and $0.1 million, respectively, related to administrative agreements for electric and gas contracts for which Select Energy has not yet received customer consents to transfer to

Hess. These derivative assets and liabilities are classified as assets held for sale and liabilities of assets held for sale, respectively, on the accompanying consolidated balance sheets.

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


	December 31,
(Millions of Dollars)	2006		2005
Current retail derivative assets	$	0.2	$	55.0
Long-term retail derivative assets		-		12.9
Current retail derivative liabilities		(0.1)		(27.2)
Long-term retail derivative liabilities		-		0.4
Total retail		0.1		41.1
Retail hedges		-		(24.1)
Mark-to-market portfolio	$	0.1	$	17.0

At December 31, 2006, the $0.1 million of the retail portfolio had a maturity of less than one year and was valued based on actively quoted prices. 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 NYMEX futures and swaps that are marked to closing exchange prices; and 2) prices provided by external sources primarily include over-the-counter forwards, including bilateral contracts for the purchase or sale of electricity or natural gas, and are marked to the mid-point of bid and ask market prices.

As of December 31, 2005 and for the years ended December 31, 2006 and 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		Total Fair Value
Prices actively quoted	$	(8.8)	$	-		$	(8.8)
Prices provided by external sources		25.8		-			25.8
Totals	$	17.0	$	-		$	17.0


	Total Portfolio Fair Value
	Year Ended December 31,
(Millions of Dollars)	2006		2005
Fair value of retail sourcing contracts outstanding at the beginning of the year	$	17.0	$	-
Contracts realized or otherwise settled during the year		(5.8)		(25.7)
Changes in fair value recorded:
Other operating expenses		(47.6)		-
Fuel, purchased and net interchange power		(8.5)		42.7
Transferred to Hess		45.0		-
Fair value of retail sourcing contracts outstanding at the end of the year	$	0.1	$	17.0

Changes in the fair value of retail contracts until the June 1, 2006 sale of the retail business totaling a negative $47.6 million were recorded in other operating expenses on the accompanying consolidated statements of income/(loss). This charge was recorded as part of the charge to reduce the retail marketing business' carrying value to its fair value less cost to sell. Any changes in fair value subsequent to the sale for contracts that were not yet assigned to Hess are recorded against the fair value less cost to sell and are reflected as other current liabilities and other deferred credits. During 2006, $45 million of derivatives were transferred to Hess subsequent to receiving customer consents to the assignment of their contracts. In connection with the decision to exit the wholesale marketing business in March of 2005, Select Energy identified certain contracts previously designated as wholesale and redesignated them to support its retail marketing business. For the years ended December 31, 2006 and 2005, a charge of $8.5 million and a benefit of $42.7 million, respectively, were recorded in fuel, purchased and net interchange power on the consolidated statements of income/(loss) related to these contracts.

Competitive Generation Activities: Until November 1, 2006, the competitive generation assets owned by NU Enterprises were 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 were also subject to various federal, state and local regulations. On November 1, 2006, all competitive generation derivative assets and derivative liabilities were transferred to ECP as a result of the sale, with the exception of certain generation contracts that expired on December 31, 2006.

The competitive generation business included third-party derivative generation related sales contracts (third-party generation contracts) and physical generation from NGC and HWP (physical generation).

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


(Millions of Dollars)	December 31, 2005
Current generation derivative assets	$	9.2
Long-term generation derivative assets		-
Current generation derivative liabilities		(5.1)
Long-term generation derivative liabilities		(15.5)
Total portfolio	$	(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, 2006 and 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 December 31, 2005, the sources of the fair value of generation 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		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)

For the years ended December 31, 2006 and 2005, the changes in fair value of these contracts are included in the following tables:


	Total Portfolio Fair Value
	Year Ended December 31,
(Millions of Dollars)	2006		2005
Fair value of competitive generation contracts outstanding at the beginning of the year	$	(11.4)	$	-
Contracts realized or otherwise settled during the year		(10.6)		(0.1)
Changes in fair value recorded:
Transferred to ECP		4.0		-
Discontinued operations		11.5		(15.5)
Fuel, purchased and net interchange power		(0.8)		-
Operating revenues		7.3		4.2
Fair value of competitive generation contracts outstanding at the end of the year	$	-	$	(11.4)

Changes in the fair value of generation sales contracts that became marked-to-market as a result of the decision to exit the remainder of the NU Enterprises' businesses were a positive $11.5 million and a negative $15.5 million for the years ended December 31, 2006 and 2005, respectively, which are recorded in discontinued operations on the accompanying consolidated statements of income/(loss). In November of 2006, $4 million of derivatives was transferred to ECP as a result of the sale. Changes in fair value of the remaining generation contracts that were marked-to-market as a result of the decision to exit the wholesale marketing business totaled a negative $0.8 million in 2006 and are recorded as fuel, purchased and net interchange power on the accompanying consolidated statements of income/(loss). Changes in the fair value of energy sales contracts that remain in continuing operations totaling a positive $7.3 million and $4.2 million for the years ended December 31, 2006 and 2005, respectively, are recorded as revenues on the consolidated statements of income/(loss).

For further information regarding Select Energy's derivative contracts, see Note 5, "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 Select Energy establishing credit limits prior to entering into contracts. The appropriateness of these limits is subject to continuing review. Concentrations among these counterparties may affect Select Energy's overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes to economic, regulatory or other conditions. At December 31, 2006, Select Energy's counterparty credit exposure to wholesale and trading counterparties was approximately 14 percent collateralized or rated BBB- or better and approximately 86 percent was non-rated. The composition of Select Energy's credit portfolio has shifted from being largely investment grade-rated to being mostly non-rated. This is largely due to the exit from Select Energy's wholesale New England and retail portfolios. The bulk of the non-rated credit exposure is comprised of one counterparty (98 percent of total) that is a creditworthy, non-rated public entity. Select Energy was provided $0.1 million and $28.9

million of counterparty deposits at December 31, 2006 and 2005, respectively. For further information, see Note 1U, "Summary of Significant Accounting Policies - Counterparty Deposits," to the consolidated financial statements.

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 accounts receivable and unbilled revenues 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, CRC had sold an undivided interest in its accounts receivable and unbilled revenues of $80 million to that financial institution with limited recourse. At December 31, 2006, CL&P had made no such sales.

CRC was established for the sole purpose of acquiring and selling CL&P’s accounts receivable and unbilled revenues and is included in CL&P's and NU's consolidated financial statements. On July 5, 2006, CRC renewed the bank commitment for the Receivables Purchase and Sale Agreement with CL&P and the financial institution through July 3, 2007, unless otherwise extended. 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 Extinguishments of Liabilities - A Replacement of SFAS No. 125." Accordingly, the $80 million outstanding under this facility at December 31, 2005, is not reflected as debt or included in the consolidated financial statements.

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: NU has various guarantees and indemnification obligations outstanding on behalf of former subsidiaries in connection with the exit from the NU Enterprises businesses. See Note 8H, "Commitments and Contingencies - Guarantees and Indemnifications," for information regarding the maximum exposure and amounts recorded under these guarantees and indemnification obligations.

Enterprise Risk Management

NU has implemented an ERM methodology for identifying the principal risks of the company. ERM involves the application of a well-defined, enterprise-wide methodology that will enable NU’s Risk and Capital Committee, comprised of senior NU officers, to oversee the identification, management and reporting of the principal risks of the business. However, there can be no assurances that the ERM process will identify every risk or event that could impact the company's financial condition or results of operations. The findings of this process are periodically discussed with NU's Finance Committee of the Board of Trustees.

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 meets the criteria for discontinued operations. At December 31, 2006, based on the status of exiting the NU Enterprises businesses, management concluded that discontinued operations presentation is appropriate for NGC, Mt. Tom, SESI, Woods Electrical - Services, SECI-NH and Woods Network. Discontinued operations treatment remains appropriate for these entities even though certain assets and liabilities, contingencies and costs related to projects (including litigation, warranty and other contingencies), costs related to the valuation and termination of guarantees, and adjustments under various purchase and sale agreements remain. Additionally, the company is providing transition services in connection with the sale of the competitive generation business, which are not considered significant.

The wholesale marketing business was not presented as discontinued operations as it is not held for sale. The retail marketing business, which was held for sale until it was sold on June 1, 2006, was not presented as discontinued operations because separate financial information was not available for this business for the periods prior to the first quarter of 2006. The remaining energy services businesses (NGS, Woods Electrical - Other, Boulos and SECI-CT) are not presented as discontinued operations as these business do not meet the criteria that SFAS No. 144 sets forth for this presentation.

For further information regarding these companies, see Note 3, "Assets Held for Sale and Discontinued Operations," to the consolidated financial statements. Management will continue to evaluate discontinued operations presentation for NU Enterprises' businesses that are being exited.

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. The testing of goodwill for impairment requires management to use estimates and judgment. Upon adoption in 2002, NU selected October 1^st of each year 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. In 2006, the impact of this goodwill impairment review was limited to Yankee Gas' goodwill balance totaling $287.6 million because in 2005 the total goodwill and intangible asset balances previously recorded by NU Enterprises totaling $50.7 million were written off.

NU completed its impairment analysis as of October 1, 2006 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. This analysis requires the input of several critical assumptions, including future growth rates, cash flow projections, operating cost escalation rates, rates of return, 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.

Updates 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 7, "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 rates are applied to customers’ use of energy to calculate their bills. In general, rates can only be changed through formal proceedings before the state regulatory commissions.

The determination of 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 and the bulk of recorded revenues is based on actual billings. 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 also 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 ISO-NE FERC Electric Tariff No. 3, Open Access Transmission Tariff (RNS), and Schedule 21 - NU (LNS) to that tariff. The RNS tariff is administered by ISO-NE and is billed to all New England transmission users. RNS recovers the revenue requirements associated with facilities that are deemed to provide a regional benefit, or PTF. The RNS rate is reset on June 1^st of each year. NU's LNS rate is reset on January 1^st and June 1^st of each year and 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.

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 2005, CL&P began tracking its retail transmission revenues and expenses for recovery. WMECO implemented a retail transmission tracker and rate adjustment mechanism in January of 2002 as part of its 2002 rate change filing. PSNH does not currently have a retail transmission rate tracking mechanism, but the company requested such a mechanism in its 2006 energy delivery rate case. Such a mechanism was also included in the rate case settlement agreement that PSNH reached with the NHPUC staff and the OCA that was filed with the NHPUC.

Revenues and expenses for derivative contracts that were entered into for trading purposes were recorded on a net basis in revenues when these transactions settled. 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 1E, "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 income/(loss) and are assets on the accompanying consolidated balance sheets 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.

The Utility Group estimates unbilled revenues monthly using the daily load cycle (DLC) method. The DLC method allocates billed sales to the current calendar month based on the daily load for each billing cycle. The billed sales are subtracted from total calendar month sales to estimate unbilled sales. Unbilled revenues are estimated by first allocating sales to the respective rate classes, then applying an average rate to the estimate of unbilled sales.

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.

Derivative Accounting: Most of the contracts comprising Select Energy’s competitive wholesale marketing and generation businesses were classified as derivatives, as were certain Utility Group contracts for the purchase or sale of energy or energy-related products. The application of derivative accounting rules is complex and requires management judgment in the following respects: identification of derivatives and embedded derivatives, designation of the normal purchases and sales exception, identifying hedge relationships and determining continuing qualification for hedge accounting, assessing and measuring hedge ineffectiveness, and estimating the fair value of derivatives. All of these judgments, depending upon their timing and effect, can have a significant impact on earnings.

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

The judgment applied in the election of the normal purchases and sales exception (and resulting accrual accounting) includes the conclusions that it is probable at the inception of the contract and throughout its term that it will result in physical delivery and that the quantities will be used or sold by the business over a reasonable period in the normal course of business. If facts and circumstances change and management can no longer support this conclusion, then the normal exception and accrual accounting is terminated and fair value accounting is applied. Contracts for which the company has elected the normal exception may be designated as a hedged item, and the derivative hedge may qualify as a cash flow hedge with changes in fair value recorded in accumulated other comprehensive income. If the normal exception is terminated for the hedged item, then the cash flow hedging of the normal contract, if any, is also terminated to the extent that the company no longer expects to physically deliver under the contract.

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

Regulatory Accounting: The accounting policies of NU’s 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. Management believes 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. All material net regulatory assets, are earning an equity return, except for securitized regulatory assets, which are not supported by equity. Amortization and deferrals of regulatory assets are included on a net basis in amortization expense on the accompanying consolidated statements of income/(loss). The regulatory assets not earning an equity return will be recovered over approximately 7 years.

During 2006, several items of a regulatory nature required management judgment. These items included:

The October 31, 2006 FERC decision regarding the RTO ROE and incentives for the New England transmission owners, which required the company's transmission businesses to adjust the 11.5 percent ROE being utilized for the purpose of revenue recognition. This adjustment resulted in a negative impact to the transmission businesses’ 2006 earnings of approximately $3 million, net of tax. Previously, management recognized revenues utilizing its best estimate of the RTO ROE since the RTO was activated on February 1, 2005.

The recording of a fixed procurement fee of 0.50 mills per KWH that CL&P was allowed to collect from customers who purchased TSO service through 2006. Earnings in 2005 included the recognition by CL&P of a $5.8 million asset related to CL&P's 2004 incentive payment. This amount was calculated based upon a methodology approved in a draft DPUC decision. To date, the DPUC has not issued a final decision regarding this methodology and CL&P has not recorded any additional incentive related earnings for 2005 or 2006. Management continues to believe that the $5.8 million asset related to CL&P's 2004 incentive payment, which was reflected in 2005 earnings, is probable of recovery.

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

A settlement agreement filed by CYAPC, the DPUC, the OCC and Maine state regulators which was approved by the FERC on November 16, 2006 and disposed of pending litigation at the FERC and the Court of Appeals, among other issues. The settlement agreement required CYAPC to forego collection of a $10 million regulatory asset that was written-off in 2006. NU included in 2006 earnings its 49 percent share of CYAPC's after-tax write-off.

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.

For further information, see Note 1F, "Summary of Significant Accounting Policies - Utility Group Regulatory Accounting," to the consolidated financial statements

Presentation: In accordance with generally accepted accounting principles, NU’s consolidated financial statements include all subsidiaries over which control is maintained and all variable interest entities (VIE). Determining whether the company is the primary beneficiary of a VIE is complex, 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 because NU has the ability to influence the operating or financial decisions of the companies. 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 to an investment requires management judgment.

Public Act 05-01, an "Act Concerning Energy Independence," (Act) was signed on July 22, 2005. The Act requires the DPUC to investigate the financial impact on distribution companies of entering into long-term contracts for capacity or contracts to purchase renewable energy products from new generating plants. CL&P has submitted filings to the DPUC related to the accounting implications of entering into these long-term contracts. If CL&P were required to enter into these contracts, this could trigger possible requirements to consolidate the generators for financial reporting purposes if they are VIEs or to record the long-term contracts as capital lease obligations or as derivatives. Determining whether or not consolidation is required or if capital lease obligations or derivatives should be recorded requires management judgment.

In 2006, NU approved a contribution of $25 million to the NU Foundation, Inc. (Foundation), an independent not-for-profit charitable entity designed to provide jobs, an educated workforce, sustainable development and a clean and healthy environment. The board of directors of the Foundation is comprised of certain NU officers. Management has determined that consolidation of the Foundation in the company's financial statements is not required under applicable accounting guidance. Determining whether or not consolidation of the Foundation is necessary required management judgment.

Impairment of Long-Lived Assets: The company evaluates individual 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 decisions to exit the NU Enterprises businesses.

When the company believes one of these events has occurred, the determination needs to be made whether a long-lived asset should be classified as held and used or held for sale. For assets classified as held and used, the company estimates the undiscounted future cash flows associated with the individual long-lived asset or asset group, and an impairment loss is recognized to the extent 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 asset group is measured at the lower of its carrying amount or fair value less cost to sell, and depreciation of these assets is discontinued.

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

As a result of the announcements to exit the competitive businesses in 2005, management evaluated the competitive wholesale and retail marketing businesses and the competitive generation long-lived assets and determined that these assets should continue to be classified as assets to be held and used as of December 31, 2005. As assets to be held and used, these assets were required to be tested for impairment as a result 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 in 2005.

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

In 2006, management determined that the retail marketing business met held for sale criteria under applicable accounting guidance, and should be recorded at the lower of carrying amount or fair value less cost to sell. The retail marketing business was reduced to its fair value less cost to sell through a $32.8 million after-tax charge.

Also in 2006, management determined that the competitive generation business should be classified as assets held for sale rather than held and used and that no impairment existed for these assets because the fair value of those assets less their expected costs to sell exceeded their expected purchase price. On November 1, 2006, NU sold the competitive generation business and realized a gain on the sale of approximately $314 million.

At December 31, 2006, the assets and liabilities of the wholesale marketing business, NGS, Woods Electrical - Other, Boulos and SECI-CT 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, were it to occur, may result in additional asset impairments and write-offs.

For further information regarding impairment charges, see Note 2, "Restructuring and Impairment Charges," and for information regarding assets held for sale Note 3, "Assets Held for Sale and Discontinued Operations," to the 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. In addition to the Pension Plan, NU also participates in a PBOP Plan to provide certain health care benefits, primarily medical and dental, and life insurance benefits 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 changes in benefit obligations, fair values of plan assets, funded status and net periodic expense could have a material impact on NU’s consolidated financial statements.

On December 31, 2006, NU implemented SFAS 158, "Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans," which amends SFAS No. 87, "Employers’ Accounting for Pensions," SFAS No. 88, "Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits," SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," and SFAS No. 132(R), "Employers' Disclosures about Pensions and Other Postretirement Benefits." SFAS No. 158 applies to the Pension Plan, NU's supplemental executive retirement plan (SERP), and PBOP Plan and requires NU to record the funded status of these plans based on the projected benefit obligation for the Pension Plan and accumulated postretirement benefit obligation (APBO) for the PBOP Plan on the consolidated balance sheet at December 31, 2006. Previously, the prepaid or accrued benefit obligation was recorded in accordance with SFAS No. 87 and SFAS No. 106, which allowed for the deferral of certain items and reconciliation to the funded status was provided in the footnotes to financial statements. These deferred items included the transition obligation, prior service costs, and net actuarial loss.

SFAS No. 158 requires the additional liability to be recorded with an offset to accumulated other comprehensive income in shareholders’ equity. NU recorded an after-tax charge totaling $4.4 million to accumulated other comprehensive income related to the impact of SFAS No. 158 on NU's unregulated subsidiaries. However, because the Utility Group companies are cost-of-service rate regulated entities under SFAS No. 71, regulatory assets were recorded in the amount of $407.4 million, as these amounts in pension expense have been and continue to be recoverable in cost-of-service, regulated rates. Regulatory accounting was also applied to the portions of the Northeast Utilities Service Company (NUSCO) costs that support the Utility Group, as these amounts are also recoverable.

Pre-tax periodic pension expense for the Pension Plan totaled $52.7 million, $42.5 million and $5.9 million for the years ended December 31, 2006, 2005 and 2004, respectively. The pension expense amounts exclude one-time items such as Pension Plan curtailments and termination benefits.

The pre-tax net PBOP Plan cost, excluding curtailments and termination benefits, totaled $50.7 million, $49.8 million and $41.7 million for the years ended December 31, 2006, 2005 and 2004, respectively.

On August 17, 2006, the Pension Protection Act of 2006 (Act) was enacted, with provisions becoming effective in 2008. The most significant impact on NU relates to changes in the IRS minimum funding requirements for the Pension and PBOP Plans. Management will continue to assess the impact of the Act on the company, but the Act is not expected to have any impact on NU’s earnings or financial position.

Impact of Medicare Changes on PBOP: On December 8, 2003, the President signed into law a bill that expanded 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 as of December 31, 2006 and 2005. 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, 2006, 2005 and 2004, this reduction in PBOP expense totaled approximately $3.6 million, including amortization of actuarial gains of $2 million and a reduction in interest cost and service cost based on a lower PBOP benefit obligation of $1.6 million. At December 31, 2006, NU had a receivable for the federal subsidy in the amount of $3.2 million related to benefit payments made in 2006. The amount is expected to be funded into the PBOP Plan when received in 2007.

Based upon guidance from the federal government released in 2005, NU also qualifies for the federal subsidy relating to employees whose PBOP Plan obligation is "capped" under NU's PBOP Plan. These subsidy amounts do not reduce NU's PBOP Plan benefit obligation as they will be used to offset retiree contributions. NU realizes a tax benefit because the federal subsidy is tax exempt when it is collected and tax deductible as the amounts are contributed to the PBOP Plan. These additional subsidy benefits are also being amortized over approximately 13 years beginning in 2005. For the years ended December 31, 2006 and 2005, the additional subsidy amounts were approximately $12.6 million. For the years ended December 31, 2006, 2005 and 2004, the subsidy amounts reduced expected tax expense by $5.5 million, $6 million and $1 million, respectively.

Pension and PBOP Plan Curtailments and Termination Benefits: In December of 2005, a new program was approved providing a benefit for certain employees hired on and after January 1, 2006 providing for these employees to receive retirement benefits under a new 401(k) benefit (K-Vantage Plan) rather than under the Pension Plan. The approval of the new plan resulted in the recording of an estimated pre-capitalization, pre-tax curtailment expense of $6.2 million in 2005, as a certain number of employees hired before that date were expected to elect the new 401(k) benefit as permitted, 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. Because the predicted level of elections of the new benefit did not occur, NU recorded a pre-capitalization, pre-tax reduction in the curtailment expense of $3.6 million and a pre-capitalization, pre-tax increase in pension expense of $5.4 million in 2006. The increase in pension expense reflects interest on the increased PBO and amortization of increased actuarial gains and losses resulting from the inclusion of additional employees in Pension Plan calculations.

In addition, as a result of its corporate reorganization, NU estimated and recorded a combined pre-capitalization, pre-tax curtailment expense and related termination benefits for the Pension Plan totaling $5.5 million in 2005. Refinements to this estimate resulted in a combined pre-capitalization, pre-tax increase in the curtailment expense and termination benefits expense of $1.1 million in 2006.

In 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 expense 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 its corporate reorganization. NU also accrued a $0.5 million pre-tax termination benefit expense at December 31, 2005 relating to certain benefits provided under the terms of the PBOP Plan. Based on refinements to its estimates, NU recorded an adjustment to the curtailment and related termination benefits in 2006. This adjustment resulted in a combined pre-capitalization, pre-tax reduction in the curtailment expense and termination benefits expense of $1.9 million in 2006. There were no curtailments or termination benefits in 2004.

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 are based on certain target asset allocation assumptions and expected long-term rates of return. NU believes that 8.75 percent is an appropriate aggregate 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 2006. 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
	2006 and 2005		2006 and 2005
	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, 2006 and 2005 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 6A, "Employee Benefits - Pension Benefits and Postretirement Benefits Other Than Pensions," to the consolidated financial statements.

Actuarial Determination of Expense: NU bases the actuarial determination of Pension Plan and PBOP Plan 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.

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, SERP 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, 2006. 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 5.90 percent for the Pension Plan and SERP and 5.80 percent for the PBOP Plan at December 31, 2006. Discount rates used at December 31, 2005 were 5.80 percent for the Pension Plans and SERP and 5.65 percent for the PBOP Plan.

Expected Contributions and Forecasted Expense: Due to the effect of the unrecognized actuarial losses and based on the long-term rate of return assumptions and discount rates as noted above as well as various other assumptions, NU estimates that expected contributions to and forecasted expense for the Pension Plan, SERP and PBOP Plan will be as follows (in millions):


	Pension Plan				SERP				Postretirement Plan
Year	Expected Contributions		Forecasted Expense		Expected Contributions		Forecasted Expense		Expected Contributions		Forecasted Expense
2007	$	-	$	26.2		N/A	$	3.6	$	39.8	$	39.8
2008	$	-	$	18.8		N/A	$	3.7	$	36.7	$	36.7
2009	$	-	$	8.9		N/A	$	3.8	$	33.9	$	33.9

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. Beginning in 2007, NU will make an additional contribution to the PBOP Plan for the amounts received from the federal Medicare subsidy. This amount is estimated at $3.2 million for 2007.

Sensitivity Analysis: The following represents the increase/(decrease) to the Pension Plan’s, SERP'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 Cost				SERP Cost				Postretirement Plan Cost
Assumption Change		2006		2005	2006		2005		2006		2005
Lower long-term rate of return	$	10.2	$	10.0		N/A		N/A	$	0.9	$	0.9
Lower discount rate	$	15.0	$	15.6	$	0.4	$	0.4	$	1.4	$	1.1
Lower compensation increase	$	(7.3)	$	(7.3)	$	(0.1)	$	(0.1)		N/A		N/A

Plan Assets: The market-related value of the Pension Plan assets has increased by $233.6 million to $2.4 billion at December 31, 2006. The PBO for the Pension Plan has also increased by $48.4 million to $2.3 billion at December 31, 2006. These changes have changed the funded status of the Pension Plan on a PBO basis from an underfunded position of $163.6 million at December 31, 2005 to an overfunded position of $21.6 million at December 31, 2006. The PBO includes expectations of future employee compensation increases. SFAS No. 158 requires NU to record the funded status of the Pension Plan based on the PBO on the consolidated balance sheet at December 31, 2006. NU has not made an employer contribution to the Pension Plan since 1991.

The accumulated benefit obligation (ABO) of the Pension Plan was approximately $260 million less than Pension Plan assets at December 31, 2006 and approximately $62 million less than Pension Plan assets at December 31, 2005. The ABO is the obligation for employee service and compensation provided through December 31^st.

The value of PBOP Plan assets has increased by $43.7 million to $266.6 million at December 31, 2006. The benefit obligation for the PBOP Plan has decreased by $23.9 million to $469.9 million at December 31, 2006. These changes have changed the underfunded status of the PBOP Plan on an accumulated projected benefit obligation basis from $270.9 million at December 31, 2005 to $203.3 million at December 31, 2006. SFAS No. 158 requires NU to record the funded status of the PBOP Plan based on the PBO on the consolidated balance sheet at December 31, 2006. 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. At December 31, 2005, 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 $1.2 million in 2006 and $0.9 million in 2005.

Income Taxes: Income tax expense is calculated in each reporting period in each of the jurisdictions in which NU operates. This process involves estimating actual current tax expense or benefit as well as the income tax impact of 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 that are recorded on the consolidated balance sheets. The income tax estimation process impacts all of NU’s segments. Adjustments made to income tax estimates can 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 $308 million and $332.5 million at December 31, 2006 and 2005, 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 income/(loss). 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 Note 1G, "Summary of Significant Accounting Policies - Income Taxes," to the consolidated financial statements.

The estimates that are made by management in order to record income tax expense are compared each year to the actual tax amounts included on NU’s income tax returns as filed. The income tax returns were filed in the fall of 2006 for the 2005 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. Recording these tax reserve adjustments did not have a material impact on NU's consolidated earnings in 2006 and 2005. Truing up income tax amounts between the consolidated financial statements and the income tax returns is a customary, annual process.

For information regarding the adoption of Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 48, "Accounting for Uncertainty in Income Taxes - An Interpretation of FASB Statement No. 109," see Note 1C, "Summary of Significant Accounting Policies - Accounting Standards Issued But Not Yet Adopted," to the consolidated financial statements.

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 reserves 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 third-party 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 rate recovery mechanisms in place for environmental costs. As a result, regulatory assets have been recorded for certain of PSNH’s and Yankee Gas’ environmental liabilities. As of December 31, 2006 and 2005, $32.6 million and $30.3 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 separate regulatory mechanism to recover environmental costs from its customers, and changes in WMECO’s environmental reserves impact WMECO’s earnings.

Initial remediation activities have been conducted at a coal tar contaminated river site in Massachusetts that is the responsibility of HWP. The cost to clean up that contamination may be more significant than currently estimated, but the level and extent of contamination is not yet known. Any and all exposure related to this site are not subject to ratepayer recovery. An increase to the environmental reserve for this site would be recorded in earnings in future periods and may be material.

For further information, see Note 8B, "Commitments and Contingencies - Environmental Matters," to the consolidated financial statements.

Asset Retirement Obligations: In March of 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 and recorded a cumulative effect of an accounting change reflecting a $1 million after-tax loss related to NU Enterprises on the accompanying consolidated statements of income/(loss).

For further information regarding the adoption of FIN 47, see Note 1M, "Summary of Significant Accounting Policies - Asset Retirement Obligations," to the consolidated financial statements.

Regulated utilities, including NU’s Utility Group companies, currently recover amounts in rates for future costs of removal of plant assets. At December 31, 2006 and 2005, these amounts totaling $290.8 million and $305.5 million, respectively, are classified as regulatory liabilities on the accompanying consolidated balance sheets.

Special Purpose Entities: In addition to special purpose entities (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.

Other Matters

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 related litigation.

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

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

For further information regarding other commitments and contingencies, see Note 8, "Commitments and Contingencies," to the consolidated financial statements.

Accounting Standards Issued But Not Yet Adopted:

Accounting for Servicing of Financial Assets: In March of 2006, the FASB issued SFAS No. 156, "Accounting for Servicing of Financial Assets - An Amendment of FASB Statement No. 140." SFAS No. 156 requires an entity to recognize a servicing asset or liability at fair value each time it undertakes an obligation to service a financial asset by entering into a servicing contract in a transfer of the servicer's financial assets that meets the requirements for sale accounting and in other circumstances. Servicing assets and liabilities may be subsequently measured through either amortization or recognition of fair value changes in earnings. SFAS No. 156 is required to be applied prospectively to transactions beginning in the first quarter of 2007. Implementation of SFAS No. 156 will not have an effect on the company's consolidated financial statements.

Uncertain Tax Positions: On July 13, 2006, the FASB issued FIN 48. FIN 48 addresses the methodology to be used in estimating and reporting amounts associated with uncertain tax positions, including interest and penalties. FIN 48 is required to be implemented prospectively in the first quarter of 2007 as a change in accounting principle with a cumulative effect adjustment reflected in opening retained earnings. The company is currently evaluating the potential impact of FIN 48 on its consolidated financial statements.

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

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

Contractual Obligations and Commercial Commitments: Information regarding NU’s contractual obligations and commercial commitments at December 31, 2006 is summarized annually through 2011 and thereafter as follows:


(Millions of Dollars)	2007		2008		2009		2010		2011		Thereafter		Totals
Long-term debt maturities^{(a) (b)}	$	4.9	$	154.3	$	54.3	$	4.3	$	4.3	$	2,472.0	$	2,694.1
Estimated interest payments on existing debt ^(c)		155.0		152.5		148.4		146.9		146.9		1,785.0		2,534.7
Capital leases ^(d)(e)		2.8		2.4		2.2		1.7		1.7		15.7		26.5
Operating leases ^(e)(f)		31.0		27.8		24.8		21.4		16.6		65.3		186.9
Required funding of other postretirement benefit obligations ^(f)		39.8		36.7		33.9		31.3		28.9		N/A		170.6
Estimated future annual Utility Group costs^{(e) (f)}		1,015.2		709.8		366.9		305.8		295.2		1,160.4		3,853.3
Estimated future annual NU Enterprises costs^{(e) (f)}		689.8		212.3		29.7		32.1		31.3		20.6		1,015.8
Other purchase commitments ^{(f) (g)}		1,515.4		-		-		-		-		-		1,515.4
Totals	$	3,453.9	$	1,295.8	$	660.2	$	543.5	$	524.9	$	5,519.0	$	11,997.3

(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 payments 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 $280.8 million of fees and interest due for spent nuclear fuel disposal costs, a negative $6.5 million of net changes in fair value and $3.1 million of net unamortized discounts as of December 31, 2006.

(c)

Estimated interest payments on fixed-rate debt are calculated by multiplying the coupon rate on the debt by its scheduled notional amount outstanding for the period of measurement. Estimated interest payments on floating-rate debt are calculated by multiplying the most recent floating-rate reset on the debt by its scheduled notional amount outstanding for the period of measurement. This same rate is then assumed for the remaining life of the debt. Interest payments on debt that have an interest rate swap in place

are estimated using the effective cost of debt resulting from the swap rather than the underlying interest cost on the debt, subject to the fixed and floating methodologies.

(d)

The capital lease obligations include imputed interest of $12.1 million as of December 31, 2006.

(e)

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.

(f)

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

(g)

Amount represents open purchase orders, excluding those obligations that are included in the estimated future annual Utility Group costs and the estimated future annual NU Enterprises costs. These payments are subject to change as certain purchase orders include estimates based on projected quantities of material and/or services that are provided on demand, the timing of which cannot be determined.

Rate reduction bond amounts are non-recourse to NU or its subsidiaries, 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. In addition, there are no Pension Plan contributions expected and therefore have been excluded from this table. For further information regarding NU’s contractual obligations and commercial commitments, see the consolidated statements of capitalization and Note 4, "Short-Term Debt," Note 6A, "Employee Benefits - Pension Benefits and Postretirement Benefits Other Than Pensions," Note 8D, "Commitments and Contingencies - Long-Term Contractual Arrangements," Note 11, "Leases," and Note 12, "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, changes in levels or timing of capital expenditures, developments in legal or public policy doctrines, technological developments, effectiveness of risk management policies and procedures, changes in accounting standards and financial reporting regulations, fluctuations in the value of remaining electricity positions, actions of rating agencies, terrorist attacks or other intentional disruptance on domestic energy facilities and other presently unknown or unforeseen factors. Other risk factors are detailed from time to time in reports to the Securities and Exchange Commission. 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	2006 over/(under) 2005				2005 over/(under) 2004
	Amount		Percent		Amount		Percent
Operating Revenues	$	(513)	(7)	%	$	855	13	%

Operating Expenses:
Fuel, purchased and net interchange power		(898)	(16)			1,127	26
Other operation		71	7			120	13
Restructuring and impairment charges		(34)	(77)			44	100
Maintenance		16	9			15	9
Depreciation		16	7			10	5
Amortization		(187)	(92)			65	47
Amortization of rate reduction bonds		12	7			11	7
Taxes other than income taxes		3	1			17	7
Total operating expenses		(1,001)	(13)			1,409	23
Operating income/(loss)		488	(a)			(554)	(a)
Interest expense, net		(1)	-			24	11
Other income, net		10	18			32	(a)
Income/(loss) from continuing operations before income tax (benefit)/expense		499	(a)			(546)	(a)
Income tax (benefit)/expense		106	57			(210)	(a)
Preferred dividends of subsidiary		-	-			-	-
Income/(loss) from continuing operations		393	(a)			(336)	(a)
Income from discontinued operations		330	(a)			(33)	(70)
Cumulative effect of accounting change, net of tax benefit		1	100			(1)	(100)
Net income/(loss)	$	724	(a)	%	$	(370)	(a)	%

(a) Percentage greater than 100.

2006 Compared to 2005

Operating Revenues

Operating revenues decreased $513 million in 2006 primarily due to lower revenues from NU Enterprises ($1.02 billion), partially offset by higher Utility Group revenues for both the distribution business ($450 million) and transmission business ($48 million).

NU Enterprises' revenues decreased $1.02 billion due to the exit from significant components of the competitive businesses during 2005 and 2006.

Distribution business revenues increased $450 million primarily due to higher electric distribution revenues ($500 million), partially offset by lower gas distribution revenues ($49 million). Higher electric distribution revenues include the components of CL&P, PSNH and WMECO retail revenues which are included in regulatory commission approved tracking mechanisms that track the recovery of certain incurred costs ($485 million). The distribution revenue tracking components increase of $485 million is primarily due to the pass through of higher energy supply costs ($566 million) and higher CL&P FMCC charges ($36 million), partially offset by lower PSNH SCRC revenues ($85 million) and lower wholesale revenues primarily due to the expiration or sale of CL&P market-based contracts ($41 million). The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections collected from customers in future periods.

The distribution component of these electric distribution businesses and the retail transmission component of PSNH which flow through to earnings increased $14 million primarily due to an increase in regulated retail rates, partially offset by a decrease in retail sales. The distribution retail electric sales were negatively affected by weather impacts in 2006 as compared with 2005 and by price elasticity driven by higher energy prices in 2006. Retail KWH electric sales decreased by 4.0 percent in 2006 compared with 2005 (a 1.6 percent decrease on a weather normalized basis). Absent the impacts of weather, management believes the decline in sales is primarily due to higher energy prices in 2006.

The increase in electric distribution revenues is partially offset by lower gas distribution revenues of $49 million primarily due to lower sales volumes. Firm gas sales decreased 11.2 percent in 2006 compared with 2005 primarily due to unseasonably warm weather in January, November and December of 2006 and customer reaction to higher energy prices. On a weather normalized basis, firm gas sales decreased 3.2 percent.

Transmission business revenues increased $48 million primarily due to a higher transmission investment base and higher operating expenses which are recovered under FERC-approved transmission tariffs.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expenses decreased $898 million in 2006 primarily due to lower costs at NU Enterprises ($1.46 billion), partially offset by higher purchased power costs for the Utility Group distribution business ($556 million).

NU Enterprises' lower costs of $1.46 billion are primarily due to the exit from significant components of the competitive businesses which includes lower mark-to-market expenses of $414 million.

The $556 million increase in distribution purchased power costs is primarily due to higher standard offer supply costs for CL&P and WMECO ($523 million) and higher expenses for PSNH primarily due to higher energy costs ($72 million). The increase in distribution purchased power costs is partially offset by lower Yankee Gas expenses as a result of lower gas sales ($39 million).

Other Operation

Other operation expenses increased $71 million in 2006 primarily due to higher Utility Group distribution and transmission business expenses ($80 million), partially offset by lower NU Enterprises' expenses ($10 million).

Higher distribution and transmission expenses of $80 million are primarily due to higher expenses that are recovered in the distribution regulatory rate tracking mechanisms. These costs include higher distribution reliability must run (RMR) costs and other power pool related expenses ($63 million) and higher CL&P conservation and load management expenses of $15 million. Distribution and transmission general and administrative expenses increased primarily due to higher employee related costs ($19 million), higher regulatory commission, outside service and other administrative costs ($6 million), partially offset by the absence of 2005 employee termination and benefit plan curtailment costs ($23 million) of which $21 million relates to regulated distribution that impact earnings.

NU Enterprises' expenses decreased $10 million primarily due to the exit from the competitive businesses ($88 million), partially offset by a charge to record the retail marketing business at its fair value less cost to sell ($53 million) and a donation of $25 million to the NU Foundation.

Restructuring and Impairment Charges

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

Maintenance

Maintenance expenses increased $16 million in 2006 primarily due to higher PSNH generation costs ($7 million) primarily as a result of a planned overhaul of a generating plant in 2006 and higher CL&P maintenance costs ($6 million) primarily due to storm-related tree trimming and overhead line maintenance expenses.

Depreciation

Depreciation increased $16 million in 2006 primarily due to higher distribution and transmission depreciation expense ($19 million) as a result of higher plant balances from the ongoing construction program. This increase is partially offset by lower NU Enterprises' depreciation ($4 million) from the competitive businesses not classified as discontinued operations.

Amortization

Amortization decreased $187 million in 2006 for the Utility Group distribution business primarily due to PSNH distribution ($92 million), CL&P distribution ($71 million) and WMECO distribution ($24 million). The PSNH decrease is primarily due to completing the recovery of its non-securitized stranded costs as of June 30, 2006. The CL&P decrease is primarily due to lower amortization related to distribution's recovery of transition charges ($70 million). The WMECO decrease is primarily due to the deferral of transmission costs ($18 million), mainly as a result of higher RMR costs, and the deferral of transition costs ($5 million) as a result of lower transition revenues and higher transition costs.

Amortization of Rate Reduction Bonds

Amortization of rate reduction bonds increased $12 million in 2006. The higher portion of principal within the rate reduction bonds payment results in a corresponding increase in the amortization of regulatory assets.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $3 million in 2006 primarily due to higher distribution and transmission property taxes ($7 million) and higher Connecticut gross earnings tax ($3 million) primarily due to higher CL&P distribution revenues. These increases are partially offset by lower NU Enterprises' other taxes ($4 million) from the competitive businesses not classified as discontinued operations.

Interest Expense, Net

Interest expense, net decreased $1 million in 2006 primarily due to lower rate reduction bond interest resulting from lower principal balances outstanding at CL&P, PSNH and WMECO, partially offset by higher interest from the issuance of CL&P long-term debt of $250 million in June of 2006 and from the issuance of Utility Group long-term debt of $350 million in 2005.

Other Income, Net

Other income, net increased $10 million in 2006 primarily due to a net decrease in non-competitive investment write-downs ($7 million), higher investment income ($6 million), CL&P Energy Independence Act (EIA) incentives ($5 million) and a $3 million gain associated with the sale of 2.7 million shares of Globix. These increases are partially offset by a lower CL&P procurement fee income ($7 million) and the CYAPC regulatory asset write-off ($3 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 prior 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 benefit decreased $106 million in 2006 due to higher pre-tax earnings ($175 million) and the regulatory recovery of tax expense associated with nondeductible acquisition costs ($11 million); partially offset by favorable tax adjustments of $74 million to remove UITC and EDIT deferred tax balances and $6 million related to generation plant sold to an affiliate.

Income from Discontinued Operations

NU's consolidated statements of income/(loss) for the years ended December 31, 2006, 2005, and 2004 present the operations for NGC, Mt. Tom, SESI, Woods Electrical - Services, 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 included net of tax in income from discontinued operations on the consolidated statements of income/(loss) and all prior periods are reclassified. The 2006 income from discontinued operations includes the approximately $314 million gain on the sale of the competitive generation business. See Note 3, "Assets Held for Sale and Discontinued Operations," to the consolidated financial statements for a further description and explanation of the discontinued operations.

Cumulative Effect of Accounting Change, Net of Tax Benefit

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 AROs.

2005 Compared to 2004

Operating Revenues

Operating revenues increased $855 million in 2005 primarily due to higher Utility Group revenues for both the distribution business ($891 million) and transmission business ($24 million), partially offset by lower revenues from NU Enterprises ($59 million).

The electric distribution business revenues increased $796 million 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 electric 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 tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections collected from customers in future periods.

The distribution component of these electric distribution businesses 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 normalized 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 being 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 $1.13 billion in 2005, primarily due to higher purchased power costs for the Utility Group ($1.34 billion), partially offset by lower costs at NU Enterprises ($217 million). The $1.34 billion increase for the Utility Group is due to the NU consolidating impact of eliminating lower intercompany standard offer 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 $217 million are primarily due to lower fuel costs at the wholesale marketing business ($304 million) primarily due to lower sales volumes. Additionally, fuel costs are lower due to the mark-to-market accounting for certain wholesale contracts related to the business being exited ($268 million) as a result of netting revenues with expenses. These decreases are partially offset by higher fuel costs and volumes in the retail marketing business ($355 million).

Other Operation

Other operation expense increased $120 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 an MGP 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).

Restructuring and Impairment Charges

See Note 2, "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 ($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 ($16 million) resulting from higher plant balances, partially offset by lower Yankee Gas depreciation expense ($6 million) as allowed in the January 1, 2005 rate decision, due to adequate reserve levels for cost of removal.

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 ($23 million) on long-term debt as a result of new Utility Group long-term debt issuance of $350 million 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. Interest expense, net is also higher due to higher short-term debt levels primarily at NU Parent ($6 million) and higher other interest for CL&P as a result of the final streetlight refund docket ($3 million). These increases are partially offset by lower rate reduction bond interest ($11 million) resulting from lower principal balances outstanding at CL&P, PSNH and WMECO.

Other Income, Net

Other income, net increased $32 million in 2005 primarily due to higher AFUDC ($8 million), higher investment income ($7 million), a net decrease in investment write-downs ($7 million), and a higher CL&P procurement fee income ($6 million).

Income Tax (Benefit)/Expense

Income tax expense decreased $210 million to a benefit of $188 million in 2005 primarily due to a loss before income tax and greater favorable flow through adjustments, offset by increases to the deferred state income tax valuation allowance. The increase in the state valuation allowance was required due to the magnitude of 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 income/(loss) from the years ended December 31, 2006, 2005 and 2004 present the operations for NGC, Mt. Tom, SESI, Woods Electrical - Services, 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 consolidated statements of income/(loss). See Note 3, "Assets Held for Sale and Discontinued Operations," to the consolidated financial statements for a further description and explanation of the discontinued operations.

Cumulative Effect of Accounting Change, Net of Tax Benefit

Company Report on Internal Controls Over Financial Reporting

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

Management is responsible for establishing and maintaining adequate internal controls over financial reporting. The Company’s internal control framework and processes have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. There are inherent limitations of internal controls over financial reporting that could allow material misstatements due to error or fraud to occur and not be prevented or detected on a timely basis by employees during the normal course of business. Additionally, internal controls over financial reporting may become inadequate in the future due to changes in the business environment. Under the supervision and with the participation of management, including our principal executive officer and principal financial officer, NU conducted an evaluation of the effectiveness of internal controls over financial reporting based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation under the framework in COSO, management concluded that our internal controls over financial reporting were effective as of December 31, 2006.

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

February 26, 2007

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 (the "Company") as of December 31, 2006 and 2005, and the related consolidated statements of income/(loss), comprehensive income/(loss), shareholders' equity, and cash flows for each of the three years in the period ended December 31, 2006. We also have audited management's assessment, included in the accompanying Company Report on Internal Controls Over Financial Reporting, that the Company maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on these financial statements, an opinion on management's assessment, and an opinion on the effectiveness of the Company's internal control over financial reporting 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 and whether effective internal control over financial reporting was maintained in all material respects. Our audit of financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of trustees, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and trustees of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Northeast Utilities and subsidiaries as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, management's assessment that the Company maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

In connection with its ongoing divestiture activities, the Company recognized a gain of $511.1 million on the sale of its generation business and a loss of $53.0 million on the sale of its retail business in 2006 (Note 3) and recorded charges of $27.6 million and $69.2 million in the years ended December 31, 2006 and 2005, respectively (Note 2). As discussed in Note 1G, the Company realized a $74 million reduction to income tax expense in 2006 due to a ruling that certain income tax credits and excess deferred income taxes could not be used to reduce customer’s rates following the sale of the generation business. As discussed in Note 6, the Company adopted Statement of Financial Accounting Standard No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.


/s/	DELOITTE & TOUCHE LLP
	DELOITTE & TOUCHE LLP

Hartford, Connecticut

February 26, 2007


NORTHEAST UTILITIES AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	At December 31,
(Thousands of Dollars)	2006	2005

ASSETS

Current Assets:
Cash and cash equivalents	$ 481,911	$ 45,782
Special deposits	48,524	103,789
Investments in securitizable assets	375,655	252,801
Receivables, less provision for uncollectible
accounts of $22,369 in 2006 and $24,444 in 2005	361,201	901,516
Unbilled revenues	88,170	175,853
Fuel, materials and supplies	173,882	206,557
Marketable securities - current	67,546	56,012
Derivative assets - current	88,699	403,507
Prepayments and other	45,305	128,042
Assets held for sale	158	101,784
	1,731,051	2,375,643

Property, Plant and Equipment:
Electric utility	7,129,526	6,378,838
Gas utility	858,961	825,872
Competitive energy	17,864	908,776
Other	281,525	254,659
	8,287,876	8,368,145
Less: Accumulated depreciation: $2,443,203 for electric and
gas utility and $171,903 for competitive energy and
other in 2006; $2,304,966 for electric and gas utility and
$246,356 for competitive energy and other in 2005	2,615,106	2,551,322
	5,672,770	5,816,823
Construction work in progress	569,416	600,407
	6,242,186	6,417,230

Deferred Debits and Other Assets:
Regulatory assets	2,449,132	2,483,851
Goodwill	287,591	287,591
Prepaid pension	21,647	298,545
Marketable securities - long-term	50,843	56,527
Derivative assets - long-term	271,755	425,049
Other	249,031	223,439
	3,329,999	3,775,002












Total Assets	$ 11,303,236	$ 12,567,875

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


NORTHEAST UTILITIES AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	At December 31,
(Thousands of Dollars)	2006	2005

LIABILITIES AND CAPITALIZATION

Current Liabilities:
Notes payable to banks	$ -	$ 32,000
Long-term debt - current portion	4,877	22,673
Accounts payable	569,940	972,368
Accrued taxes	364,659	95,210
Accrued interest	53,782	47,742
Derivative liabilities - current	125,781	402,530
Counterparty deposits	148	28,944
Other	244,586	272,252
Liabilities of assets held for sale	62	101,511
	1,363,835	1,975,230

Rate Reduction Bonds	1,177,158	1,350,502

Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	1,099,433	1,306,340
Accumulated deferred investment tax credits	32,427	95,444
Deferred contractual obligations	271,528	358,174
Regulatory liabilities	809,324	1,273,501
Derivative liabilities - long-term	148,557	272,995
Accrued postretirement benefits	203,320	16,506
Other	322,840	346,451
	2,887,429	3,669,411
Capitalization:
Long-Term Debt	2,960,435	3,027,288

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

Common Shareholders' Equity:
Common shares, $5 par value - authorized
225,000,000 shares; 175,420,239 shares issued
and 154,233,141 shares outstanding in 2006 and
174,897,704 shares issued and 153,225,892 shares
outstanding in 2005	877,101	874,489
Capital surplus, paid in	1,449,586	1,437,561
Deferred contribution plan - employee stock
ownership plan	(34,766)	(46,884)
Retained earnings	862,660	504,301
Accumulated other comprehensive income	4,498	19,987
Treasury stock, 19,684,249 shares in 2006
and 19,645,511 shares in 2005	(360,900)	(360,210)
Common Shareholders' Equity	2,798,179	2,429,244
Total Capitalization	5,874,814	5,572,732

Commitments and Contingencies (Note 8)

Total Liabilities and Capitalization	$ 11,303,236	$ 12,567,875


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


NORTHEAST UTILITIES AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME/(LOSS)


For the Years Ended December 31,	2006	2005	2004
	(Thousands of Dollars, except share information)

Operating Revenues	$ 6,884,388	$ 7,397,743	$ 6,542,038

Operating Expenses:
Operation -
Fuel, purchased and net interchange power	4,630,798	5,528,600	4,401,175
Other	1,129,557	1,058,620	938,791
Restructuring and impairment charges	10,300	44,143	-
Maintenance	193,975	178,521	163,626
Depreciation	240,715	225,278	215,063
Amortization	16,292	202,949	138,271
Amortization of rate reduction bonds	188,247	176,356	164,915
Taxes other than income taxes	250,580	247,555	230,793
Total operating expenses	6,660,464	7,662,022	6,252,634
Operating Income/(Loss)	223,924	(264,279)	289,404

Interest Expense:
Interest on long-term debt	141,579	131,870	107,365
Interest on rate reduction bonds	74,242	87,439	98,899
Other interest	22,217	19,755	8,762
Interest expense, net	238,038	239,064	215,026
Other Income, Net	64,394	54,530	22,722
Income/(Loss) from Continuing Operations Before
Income Tax (Benefit)/Expense	50,280	(448,813)	97,100
Income Tax (Benefit)/Expense	(81,429)	(187,796)	21,765
Income/(Loss) from Continuing Operations Before	`
Preferred Dividends of Subsidiary	131,709	(261,017)	75,335
Preferred Dividends of Subsidiary	5,559	5,559	5,559
Income/(Loss) from Continuing Operations	126,150	(266,576)	69,776
Discontinued Operations (Note 3):
Income from Discontinued Operations Before Income Taxes	44,871	24,327	76,803
Gain/(Loss) from Sale of Discontinued Operations	502,653	(1,123)	-
Income Tax Expense	(203,096)	(9,111)	(29,991)
Income from Discontinued Operations	344,428	14,093	46,812
Income/(Loss) Before Cumulative Effect of Accounting Change, Net of Tax Benefit	470,578	(252,483)	116,588
Cumulative effect of accounting change, net of tax benefit of $689	-	(1,005)	-
Net Income/(Loss)	$ 470,578	$ (253,488)	$ 116,588

Basic Earnings/(Loss) Per Common Share:
Income/(Loss) from Continuing Operations	$ 0.82	$ (2.03)	$ 0.54
Income from Discontinued Operations	2.24	0.11	0.37
Cumulative Effect of Accounting Change, Net of Tax Benefit	-	(0.01)	-
Basic Earnings/(Loss) Per Common Share	$ 3.06	$ (1.93)	$ 0.91

Fully Diluted Earnings/(Loss) Per Common Share:
Income/(Loss) from Continuing Operations	$ 0.82	$ (2.03)	$ 0.54
Income from Discontinued Operations	2.23	0.11	0.37
Cumulative Effect of Accounting Change, Net of Tax Benefit	-	(0.01)	-
Fully Diluted Earnings/(Loss) Per Common Share	$ 3.05	$ (1.93)	$ 0.91

Basic Common Shares Outstanding (weighted average)	153,767,527	131,638,953	128,245,860
Fully Diluted Common Shares Outstanding (weighted average)	154,146,669	131,638,953	128,396,076

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


NORTHEAST UTILITIES AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)


For the Years Ended December 31,	2006	2005	2004
	(Thousands of Dollars)

Net Income/(Loss)	$ 470,578	$ (253,488)	$ 116,588
Other comprehensive (loss)/income, net of tax:
Qualified cash flow hedging instruments	(12,340)	21,688	(28,246)
Unrealized gains/(losses) on securities	718	(899)	1,191
Minimum SERP liability	379	418	(156)
Other comprehensive (loss)/income, net of tax	(11,243)	21,207	(27,211)
Comprehensive Income/(Loss)	$ 459,335	$ (232,281)	$ 89,377


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


NORTHEAST UTILITIES AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY



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

Balance as of January 1, 2004	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
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
Change in 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)
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
Change in 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
Net income for 2006					470,578			470,578
Dividends on common shares - $0.725 per share					(112,219)			(112,219)
Issuance of common shares, $5 par value	522,535	2,612	6,882					9,494
Allocation of benefits - ESOP	523,452		(618)	12,118				11,500
Change in restricted shares, net	(38,738)		4,293				(690)	3,603
Tax deduction for stock options exercised and Employee Stock Purchase
Plan disqualifying dispositions			1,112					1,112
Capital stock expenses, net			356					356
Adjustment to funded status of pension, SERP, and other post retirement plans (SFAS No. 158)						(4,246)		(4,246)
Other comprehensive loss						(11,243)		(11,243)
Balance as of December 31, 2006	154,233,141	$ 877,101	$ 1,449,586	$ (34,766)	$ 862,660	$ 4,498	$ (360,900)	$ 2,798,179

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


NORTHEAST UTILITIES AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31,	2006	2005	2004
	(Thousands of Dollars)

Operating Activities:
Net income/(loss)	$ 470,578	$ (253,488)	$ 116,588
Adjustments to reconcile to net cash flows
provided by operating activities:
Pre-tax (gain)/loss on sale of discontinued operations	(502,653)	1,123	-
Restructuring and impairment charges	(2,282)	67,181	-
Bad debt expense	29,366	27,528	19,062
Depreciation	243,822	237,463	226,906
Deferred income taxes	(204,212)	(202,789)	111,710
Amortization	16,292	202,949	138,271
Amortization of rate reduction bonds	188,247	176,356	164,915
Amortization/(deferral) of recoverable energy costs	15,609	39,914	(22,751)
Pension expense	38,677	42,662	10,636
Wholesale contract buyout payments	-	(186,531)	-
Regulatory refunds	(96,560)	(65,236)	(150,119)
Derivative assets and liabilities	(98,685)	443,351	85,592
Deferred contractual obligations	(90,671)	(89,464)	(56,161)
Other non-cash adjustments	22,675	45,112	(30,053)
Other sources of cash	10,655	5,528	24,545
Other uses of cash	(10,134)	-	(10,189)
Changes in current assets and liabilities:
Receivables and unbilled revenues, net	605,366	(208,519)	(103,983)
Fuel, materials and supplies	16,718	(17,848)	(31,104)
Investments in securitizable assets	(158,651)	(113,410)	27,074
Other current assets	58,350	46,462	(9,387)
Accounts payable	(399,386)	131,043	124,437
Counterparty deposits and margin special deposits	26,469	(86,229)	(18,107)
Accrued taxes/(taxes receivable)	271,477	156,630	(112,300)
Other current liabilities	(43,993)	41,416	(44,935)
Net cash flows provided by operating activities	407,074	441,204	460,647

Investing Activities:
Investments in property and plant:
Electric, gas and other utility plant	(846,396)	(752,124)	(653,948)
Competitive energy assets	(25,785)	(23,231)	(17,527)
Cash flows used for investments in property and plant	(872,181)	(775,355)	(671,475)
Net proceeds from sales of competitive businesses	1,053,099	31,456	-
Cash payments for sales of competitive businesses	(32,359)	-	-
Proceeds from sales of investment securities	193,459	137,099	106,217
Purchases of investment securities	(193,917)	(142,260)	(171,511)
Restricted cash - LMP costs	-	-	93,630
Rate reduction bond escrow	(47,071)	(6,421)	3,874
Other investing activities	16,034	55,936	3,847
Net cash flows provided by/(used in) investing activities	117,064	(699,545)	(635,418)

Financing Activities:
Issuance of common shares	9,494	450,827	10,937
Issuance of long-term debt	250,000	350,355	512,762
Retirement of rate reduction bonds	(173,344)	(195,988)	(183,470)
(Decrease)/increase in short-term debt	(32,000)	(148,000)	75,000
Reacquisitions and retirements of long-term debt	(28,843)	(98,056)	(155,532)
Cash dividends on common shares	(112,745)	(87,554)	(80,177)
Other financing activities	(571)	(14,450)	(1,132)
Net cash flows (used in)/provided by financing activities	(88,009)	257,134	178,388
Net increase/(decrease) in cash and cash equivalents	436,129	(1,207)	3,617
Cash and cash equivalents - beginning of year	45,782	46,989	43,372
Cash and cash equivalents - end of year	$ 481,911	$ 45,782	$ 46,989


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


CONSOLIDATED STATEMENTS OF CAPITALIZATION
		At December 31,
(Thousands of Dollars)		2006	2005
Common Shareholders’ Equity		$2,798,179	$2,429,244
Preferred Stock:
CL&P Preferred Stock Not Subject to Mandatory Redemption - $50 par value – authorized 9,000,000 shares in 2006 and 2005; 2,324,000 shares outstanding in 2006 and 2005; 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
2009-2012	6.20% to 7.19%	75,714	80,000
2014-2015	4.80% to 5.25%	375,000	375,000
2019-2024	5.26% to 8.48%	209,845	209,845
2026-2036	5.35% to 8.81%	580,000	650,000
Total First Mortgage Bonds		1,240,559	1,314,845
Other Long-Term Debt: Pollution Control Notes:
2016-2018	5.90%	25,400	25,400
2021-2022	Variable Rate and 4.75% 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:
2006-2008	3.30% to 8.81%	150,591	173,263
2012-2015	5.00% to 9.24%	368,000	368,000
2034	5.90%	50,000	50,000
Total Pollution Control Notes and Other		1,453,576	1,476,248
Total First Mortgage Bonds, Pollution Control Notes and Other		2,694,135	2,791,093
Fees and interest due for spent nuclear fuel disposal costs		280,820	268,008
Change in Fair Value		(6,483)	(5,211)
Unamortized premium and discount, net		(3,160)	(3,929)
Total Long-Term Debt		2,965,312	3,049,961
Less: Amounts due within one year		4,877	22,673
Long-Term Debt, Net		2,960,435	3,027,288
Total Capitalization		$5,874,814	$5,572,732

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. NU is now registered with the Federal Energy Regulatory Commission (FERC) as a public utility holding company under PUHCA 2005. 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 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.

In 2006, NU Enterprises paid $25 million to the NU Foundation, Inc. (Foundation), an independent not-for-profit charitable entity designed to invest in projects that emphasize new job creation, workforce training and education, and a clean and healthy environment. The board of directors of the Foundation is comprised of certain NU officers.

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 (which includes PSNH's generation activities), the regulated gas utility distribution segment and the regulated electric utility transmission segment.

NU Enterprises: NU Enterprises, Inc. is the parent company of Select Energy, Inc. (Select Energy), Northeast Generation Services Company (NGS), the remaining contracts of the former Woods Electrical Co., Inc. (Woods Electrical - Other), the E. S. Boulos Company (Boulos) and the Connecticut division of Select Energy Contracting, Inc. (SECI-CT), which are collectively referred to as NU Enterprises. For information regarding the exit from these businesses, see Note 3, "Assets Held for Sale and Discontinued Operations," to the consolidated financial statements. For further information regarding NU Enterprises' business segments, see Note 16, "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 2005, wholesale contract market changes, net were separately stated on the consolidated statement of income/(loss) to increase the transparency of the mark-to-market related to Select Energy's wholesale marketing portfolio. As the disclosure of this amount is currently not as meaningful as it was in 2005, $425.4 million has been reclassified to fuel, purchased and net interchange power on the accompanying consolidated statement of income/(loss) for the year ended December 31, 2005. For further information regarding Select Energy's derivatives, see Note 5, "Derivative Instruments," to the consolidated financial statements.

In the company's consolidated statements of income/(loss) for the years ended December 31, 2005 and 2004, the classification of expense amounts relating to costs not recoverable from regulated customers and certain other cost and income items previously included in other income, net was changed to a preferable presentation to no longer reflect these costs as they would appear for rate-making purposes. These amounts, which were reclassified to other operation expense and depreciation expense totaled $4.6 million and $2.2 million, respectively, for the year ended December 31, 2005. Similar amounts for the year ended December 31, 2004 totaled $0.7 million and $2.1 million, respectively. These reclassifications had no impact on results of operations, cash flows, financial condition or changes in shareholders' equity.

NU's consolidated statements of income/(loss) for the years ended December 31, 2006, 2005 and 2004 classify the operations for the following as discontinued operations:

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

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

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

The services business of Woods Electrical (Woods Electrical - Services),

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

Woods Network Services, Inc. (Woods Network).

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

Accounting Standards Issued But Not Yet Adopted

Accounting for Servicing of Financial Assets: In March of 2006, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 156, "Accounting for Servicing of Financial Assets - An Amendment of FASB Statement No. 140." SFAS No. 156 requires an entity to recognize a servicing asset or liability at fair value each time it undertakes an obligation to service a financial asset by entering into a servicing contract in a transfer of the servicer's financial assets that meets the requirements for sale accounting and in other circumstances. Servicing assets and liabilities may be subsequently measured through either amortization or recognition of fair value changes in earnings. SFAS No. 156 is required to be applied prospectively to transactions beginning in the first quarter of 2007. Implementation of SFAS No. 156 will not have an effect on the company's consolidated financial statements.

Uncertain Tax Positions: On July 13, 2006, the FASB issued FASB Interpretation No. (FIN) 48. FIN 48 addresses the methodology to be used in estimating and reporting amounts associated with uncertain tax positions, including interest and penalties. FIN 48 is required to be implemented prospectively in the first quarter of 2007 as a change in accounting principle with a cumulative effect adjustment reflected in opening retained earnings. The company is currently evaluating the potential impact of FIN 48 on its consolidated financial statements.

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 income/(loss) 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 New England Independent System Operator (ISO-NE) FERC Electric Tariff No. 3, Open Access Transmission Tariff (RNS), and Schedule 21 - NU

(LNS) to that tariff. The RNS tariff is administered by ISO-NE and is billed to all New England transmission users. RNS recovers the revenue requirements associated with facilities that are deemed to provide a regional benefit, or pool transmission facilities. The RNS rate is reset on June 1^stof each year. NU's LNS rate is reset on January 1^st and June 1^st of each year and provides for a true-up to actual costs, which ensures that NU's transmission business recovers its total transmission revenue requirements, including the allowed return on equity (ROE).

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. In 2005, CL&P began tracking its retail transmission revenues and expenses. WMECO implemented its retail transmission tracker and rate adjustment mechanism in January of 2002 as part of its 2002 rate change filing. PSNH does not currently have a retail transmission rate tracking mechanism, but the company requested such a mechanism in its 2006 energy delivery rate case. Such a mechanism was also included in the rate case settlement agreement that PSNH reached with the New Hampshire Public Utilities Commission (NHPUC) staff and the Office of Consumer Advocate that was filed with the NHPUC.

NU Enterprises: NU Enterprises' revenues are recognized at different times for its different business lines. Up to and including the first quarter of 2005, wholesale marketing revenues were recognized when energy was delivered. Subsequent to March 31, 2005, as a result of applying mark-to-market accounting, these revenues were recorded in fuel, purchased and net interchange power. This net presentation of the mark-to-market and settlement amounts is required when physical delivery of contract quantities is not probable. Service revenues were recognized as services were provided, often on a percentage of completion basis.

For further information regarding the recognition of revenue, see Note 1E, "Summary of Significant Accounting Policies - Derivative Accounting," to the consolidated financial statements.

Derivative Accounting

The accounting treatment for energy contracts entered into varies and depends on the intended use of the particular contract and on whether or not the contract is a derivative. Non-derivative contracts are recorded at the time of delivery or settlement. Most of the contracts that comprise or comprised 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 were not derivatives, while virtually all contracts entered into to supply these customers were derivatives. Those retail contracts were sold to Hess Corporation (Hess) on June 1, 2006. 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 earnings.

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 determines whether there is a notional amount 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 such updates can have a material impact on mark-to-market amounts.

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. Derivatives were accounted for as cash flow hedges only if they were designated as hedges for derivative contracts for which the company had elected the normal purchases and sales exception. If the normal exception was terminated, then the hedge designation was terminated at the same time. All cash flow hedges expired or were transferred to Hess in 2006.

From April 1, 2005 through the June 1, 2006 sale of the business, Select Energy reported the settlement of derivative and non-derivative retail sales that physically delivered in revenues and the associated derivative and non-derivative contracts to supply these contracts in fuel, purchased and net interchange power. Select Energy reported the settlement of all derivative wholesale contracts, including any remaining 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 were marked-to-market beginning in the fourth quarter of 2005 continued to be recorded in revenues until the contracts were sold or realized.

Prior to April 1, 2005, Select Energy reported the settlement of long-term derivative contracts, including full requirements sales contracts that physically delivered and were not held for trading purposes on a gross basis, generally with sales in revenues and purchases in expenses. Retail sales contracts were physically delivered and recorded in revenues. Short-term sales and purchases represented power and natural gas that was purchased to serve full requirements contracts but was ultimately not needed based on the actual load of the customers. This excess power and natural gas was sold to the independent system operator or to other counterparties. Prior to the March 9, 2005 decision to exit the wholesale marketing business, for the three months ended March 31, 2005 and for the year ended December 31, 2004, 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.

For further information regarding these contracts and their accounting, see Note 5, "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. 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. All material net regulatory assets are earning an equity return, except for securitized regulatory assets, which are not supported by equity. Amortization and deferrals of regulatory assets are included on a net basis in amortization expense on the accompanying consolidated statements of income/(loss).

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


	At December 31,
(Millions of Dollars)	2006		2005
Recoverable nuclear costs	$	13.7	$	44.1
Securitized assets		1,131.1		1,340.9
Income taxes, net		308.0		332.5
Unrecovered contractual obligations		214.4		327.5
Recoverable energy costs		5.3		193.0
CL&P CTA and SBC		100.5		-
Deferred benefit costs		407.4		-
Other regulatory assets		268.7		245.9
Totals	$	2,449.1	$	2,483.9

Additionally, the Utility Group had $11.2 million of regulatory costs at both December 31, 2006 and 2005 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 for recovery 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 which had an unamortized balance of $26.1 million at December 31, 2005 and is included in recoverable nuclear costs. On June 30, 2006, under the terms of the restructuring settlement, PSNH fully recovered these costs. Included in recoverable nuclear costs at December 31, 2006 and 2005 are $13.7 million and $18 million, respectively, primarily related to WMECO's share of Millstone 1 recoverable nuclear costs for 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 $604.5 million and $731.4 million at December 31, 2006 and 2005, 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 $102.7 million and $124.2 million at December 31, 2006 and 2005, 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 $314.7 million and $354.5 million at December 31, 2006 and 2005, 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 $10.9 million and $20.5 million at December 31, 2006 and 2005, 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 $98.3 million and $110.3 million at December 31, 2006 and 2005, respectively.

Securitized regulatory assets, which are not earning an equity return, 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 $308 million and $332.5 million at December 31, 2006 and 2005, respectively. For further information regarding income taxes, see Note 1G, "Summary of Significant Accounting Policies - Income Taxes," to the consolidated financial statements.

Unrecovered Contractual Obligations: Under the terms of contracts with the Connecticut Yankee Atomic Power Company (CYAPC), Yankee Atomic Electric Company (YAEC), and Maine Yankee Atomic Power Company (MYAPC) (Yankee Companies), CL&P, PSNH, and WMECO are responsible for their proportionate share of the remaining costs of the units, including decommissioning. A portion of these amounts, $214.4 million and $327.5 million at December 31, 2006 and 2005, 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 WMECO are being recovered along with other stranded costs. Amounts for PSNH were fully recovered by December 31, 2006.

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 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, 2006 and 2005, NU’s total D&D Assessment deferrals were $5.3 million and $9.8 million, respectively, and have been recorded as recoverable energy costs.

In conjunction with the implementation of restructuring under the restructuring settlement agreement on May 1, 2001, PSNH’s fuel and purchased power adjustment clause (FPPAC) was discontinued. At December 31, 2005, PSNH had $127.5 million of recoverable energy costs deferred under the FPPAC. Also included in PSNH’s recoverable energy costs were deferred costs totaling $44 million associated with certain contractual purchases from IPPs. On June 30, 2006, under the terms of the restructuring settlement agreement, PSNH fully recovered these costs.

The regulated rates of Yankee Gas include a purchased gas adjustment (PGA) 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. The amount recorded as recoverable energy costs was $11.7 million at December 31, 2005. At December 31, 2006, $0.7 million was over collected and is included in other regulatory liabilities.

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

CL&P CTA and SBC: 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 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. At December 31, 2006, CTA undercollections totaled $75.5 million whereas at December 31, 2005 CTA collections exceeded CTA costs by $26 million. The change in the CTA balance is due primarily to refunds to customers of approximately $100 million as ordered by the Connecticut Department of Public Utility Control (DPUC) and the absence of overcollections in 2006 that were previously anticipated. At December 31, 2006, SBC undercollections totaled $25 million and at December 31, 2005, SBC undercollections totaled $1.8 million. The increase in the undercollections is primarily due to an acceleration of the recovery of hardship protection costs. At December 31, 2005, the $1.8 million balance was included in the CL&P CTA, GSC and SBC regulatory liability.

Deferred Benefit Costs: At December 31, 2006, the company implemented SFAS No. 158, "Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans." SFAS No. 158 applies to NU’s Pension Plan, Supplemental Executive Retirement Plan (SERP), and postretirement benefits other than pension (PBOP) Plan and requires an additional benefit liability to be recorded with an offset to accumulated other comprehensive income in shareholders’ equity. However, because the Utility Group companies are cost-of-service rate regulated entities under SFAS No. 71, an offset was recorded as a regulatory asset totaling $407.4 million, as these amounts have been and continue to be recoverable in cost-of-service, regulated rates. Regulatory accounting was also applied to the portions of the NUSCO costs that support the Utility Group, as these amounts are also recoverable. The majority of the $407.4 million in regulatory assets are not in rate base. These regulatory assets will be recovered over the remaining service lives of employees.

See Note 6A, "Employee Benefits - Pension Benefits and Postretirement Benefits Other Than Pensions," for additional information regarding the implementation of SFAS No. 158.

Other Regulatory Assets: Included in other regulatory assets are the regulatory assets associated with the implementation of FIN 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143," totaling $46.4 million and $47.3 million at December 31, 2006 and 2005, respectively. Of these amounts, $13.7 million and $15.1 million, respectively, has been approved for future recovery. At this time, management believes that the remaining regulatory assets are probable of recovery.

In addition, at December 31, 2006 and 2005, other regulatory assets included $31.6 million and $32.6 million, respectively, related to losses on reacquired debt, $75.3 million and $32.7 million, respectively, which offset the fair value of derivative contracts related to the procurement of energy, $32.6 million and $30.3 million, respectively, related to environmental costs and $18.2 million and $37 million, respectively, related to the buyout and buydown of IPP contracts, and $64.6 million and $66 million, respectively, related to various other items.

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


	At December 31,
(Millions of Dollars)	2006		2005
Cost of removal	$	290.8	$	305.5
CL&P CTA, GSC and SBC		108.2		154.0
PSNH cumulative deferrals – SCRC		-		303.3
Regulatory liabilities offsetting
Utility Group derivative assets		294.5		391.2
Other regulatory liabilities		115.8		119.5
Totals	$	809.3	$	1,273.5

Cost of Removal: NU’s Utility Group companies currently recover amounts in rates for future costs of removal of plant assets. These amounts, which totaled $290.8 million and $305.5 million at December 31, 2006 and 2005, respectively, are classified as regulatory liabilities on the accompanying consolidated balance sheets. This liability is included in rate base.

CL&P CTA, GSC and SBC: As noted previously, the CTA allows CL&P to recover stranded costs while the SBC allows CL&P to recover certain regulatory and energy public policy costs. The generation service charge (GSC) allows CL&P to recover the costs of the procurement of energy for standard service. At December 31, 2006, CL&P CTA and SBC undercollections totaled $100.5 million and were recorded as regulatory assets while GSC overcollections totaling $108.2 million were recorded as regulatory liabilities. CL&P CTA, GSC and SBC overcollections totaled $154 million at December 31, 2005. These liabilities are included in rate base.

PSNH Cumulative Deferrals - SCRC: The restructuring settlement agreement between PSNH and the state of New Hampshire, which was implemented in May of 2001, requires that certain identified non-securitized stranded costs be recovered from PSNH's customers prior to a recovery end date determined in accordance with the restructuring settlement agreement or be written off. On June 30, 2006, under the terms of the restructuring settlement agreement, PSNH completed the recovery of those identified non-securitized stranded costs and offset the remaining stranded cost regulatory asset balances totaling $345.8 million against an offsetting regulatory liability, the cumulative deferral of net Stranded Cost Recovery Charge (SCRC) revenues and costs. At December 31, 2006, PSNH had $325.6 million of Part 1 securitized stranded costs and $29.9 million of Part 2 non-securitized stranded costs, including $10.7 million of SCRC costs in excess of SCRC revenues. The $10.7 million is expected to be recovered in the 2007 SCRC rate and is included in other regulatory assets at December 31, 2006.

Regulatory Liabilities Offsetting Utility Group Derivative Assets: The regulatory liabilities offsetting derivative assets relate to the fair value of contracts used to purchase power that will benefit ratepayers in the future. These amounts totaled $294.5 million and $391.2 million at December 31, 2006 and 2005, respectively. See Note 5, "Derivative Instruments," for further information. This liability is excluded from rate base.

Other Regulatory Liabilities: At December 31, 2006 and 2005, other regulatory liabilities included $22.5 million and $25 million, respectively, of prepaid pension amounts related to the purchase of Yankee Gas in March of 2000, and $25.6 million and $6.7 million, respectively, primarily related to transmission refunds to be provided to customers as a result of the FERC ROE decision, $18.3 million at December 31, 2006 related to PSNH's energy service overcollections and $49.4 million and $87.8 million related to various other items at December 31, 2006 and 2005, 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 related to continuing operations are as follows:


	For the Years Ended December 31,
	2006		2005		2004
	(Millions of Dollars)
The components of the federal and state income tax provisions are:

Current income taxes:
Federal	$	55.9	$	19.9	$	(58.6)
State		(20.5)		6.4		(8.7)
Total current		35.4		26.3		(67.3)
Deferred income taxes, net:
Federal		(49.5)		(159.8)		102.0
State		(4.3)		(50.6)		(9.1)
Total deferred		(53.8)		(210.4)		92.9
Investment tax credits, net		(63.0)		(3.7)		(3.8)
Income tax (benefit)/expense	$	(81.4)	$	(187.8)	$	21.8

A reconciliation between income tax (benefit)/expense and the expected tax expense/(benefit) at the statutory rate is as follows:


	For the Years Ended December 31,
	2006		2005		2004
	(Millions of Dollars)
Expected federal income tax expense/(benefit)	$	17.6	$	(157.1)	$	34.0
Tax effect of differences:
Depreciation		(4.0)		(3.5)		5.8
Amortization of regulatory assets		13.3		1.8		1.8
Investment tax credit amortization (including $59.3 million related to the PLR)		(63.0)		(3.7)		(3.8)
State income taxes, net of federal benefit		(17.8)		(47.8)		(9.6)
Excess deferred income taxes - PLR		(14.7)		-		-
Deferred tax adjustment - sale to affiliate		(6.0)		-		-
Medicare subsidy		(5.5)		(6.0)		(1.0)
Tax asset valuation allowance/reserve adjustments		1.3		18.5		1.9
Other, net		(2.6)		10.0		(7.3)
Income tax (benefit)/expense	$	(81.4)	$	(187.8)	$	21.8

NU and its subsidiaries file a consolidated federal income tax return and 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 separate company tax return, and subsidiaries generating tax losses are paid for their losses when utilized.

In 2000, CL&P requested from the Internal Revenue Service (IRS) a Private Letter Ruling (PLR) regarding the treatment of unamortized investment tax credits (UITC) and excess deferred income taxes (EDIT) related to generation assets that were sold. On April 18, 2006, the IRS issued a PLR to CL&P regarding the treatment of UITC and EDIT. EDIT are temporary differences between book and taxable income that were recorded when the federal statutory tax rate was higher than it is now or when those differences were expected to be resolved. The PLR holds that it would be a violation of tax regulations if the EDIT or UITC are used to reduce customers' rates following the sale of the generation assets. CL&P's UITC and EDIT balances related to generation assets that have been sold totaled $59 million and $15 million, respectively, and $74 million combined. CL&P was ordered by the DPUC to submit the PLR to the DPUC within 10 days of issuance and retain the UITC and EDIT in their existing accounts pending its receipt and review of the PLR. On July 27, 2006, the DPUC determined that the UITC and EDIT amounts were no longer required to be held in their existing accounts. As a result of this determination, the $74 million balance was reflected as a reduction to CL&P's 2006 income tax expense with an increase to CL&P's earnings by the same amount.

Included in 2006 amortization of regulatory assets above is $13 million associated with the restructuring settlement. In accordance with the provisions of the restructuring settlement, pre-tax amortization of PSNH non-deductible acquisition costs increased $32 million as compared to 2005 and 2004.

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)		2006		2005
Deferred tax liabilities - current:
Change in fair value of energy contracts	$	18.0	$	7.3
Other		42.0		35.6
Total deferred tax liabilities - current		60.0		42.9
Deferred tax assets - current:
Change in fair value of energy contracts		17.3		50.7
Other		26.5		15.9
Total deferred tax assets - current		43.8		66.6
Net deferred tax liabilities/(assets) - current		16.2		(23.7)
Deferred tax liabilities - long-term:
Accelerated depreciation and other plant-related differences		931.0		1,120.7
Employee benefits		126.7		165.0
Regulatory amounts:
Securitized contract termination costs and other		200.3		223.6
Other		238.1		159.2
Income tax gross-up		202.4		215.1
Derivative assets		99.5		-
Other		39.5		80.1
Total deferred tax liabilities - long-term		1,837.5		1,963.7
Deferred tax assets - long-term:
Regulatory deferrals		267.9		365.8
Employee benefits		308.0		112.0
Income tax gross-up		39.3		34.0
Other		146.4		175.4
Total deferred tax assets - long-term		761.6		687.2
Less: valuation allowance		23.5		29.8
Net deferred tax assets - long-term		738.1		657.4
Net deferred tax liabilities - long-term		1,099.4		1,306.3
Net deferred tax liabilities	$	1,115.6	$	1,282.6

At December 31, 2006, NU had state net operating loss carry forwards of $350 million that expire between December 31, 2008 and December 31, 2026. At December 31, 2006, NU also had state credit carry forwards of $32.8 million that expire on December 31, 2011.

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.

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 debt securities 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. In July of 2006, Acumentrics was recapitalized, and NU's debt securities were converted into equity shares. NU's cost method investment in Acumentrics totaled $0.6 million at December 31, 2006 and is included in deferred debits and other assets - other on the accompanying consolidated balance sheets.

BMC: In 2005 and 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, NU recorded pre-tax investment write-downs of $0.8 million and $2.5 million in 2005 and 2004, respectively. The remaining note receivable from BMC, which is included in deferred debits and other assets - other on the accompanying consolidated balance sheets, was $0.5 million at both December 31, 2006 and 2005.

RMS: NU had an investment in R.M. Services, Inc. (RMS), a provider of consumer collection services. On June 30, 2004, NU sold virtually all of the assets and liabilities of RMS for $3 million and recorded a pre-tax gain on the sale totaling $0.8 million.

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

Property, Plant and Equipment and Depreciation

The following table summarizes NU's investments in utility plant at December 31, 2006 and 2005 and the average depreciable life at December 31, 2006:


			At December 31,
	Average Depreciable Life		2006		2005
	(Years)		(Millions of Dollars)
Distribution		30.5	$	5,950.4	$	5,617.4
Transmission		48.8		1,460.9		1,084.3
Generation		30.4		577.2		503.0
Competitive energy		28.9		17.9		908.8
Other		14.9		281.5		254.6
Total property, plant and equipment				8,287.9		8,368.1
Less: Accumulated depreciation				(2,615.1)		(2,551.3)
Net property, plant and equipment				5,672.8		5,816.8
Construction work in progress				569.4		600.4
Total property, plant and equipment, net			$	6,242.2	$	6,417.2

The decrease in the competitive energy property, plant and equipment in 2006 was due to the sale of NGC and Mt. Tom.

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, 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 both 2006 and 2005, and 3.3 percent in 2004.

Jointly Owned Electric Utility Plant

Regional Nuclear Companies: At December 31, 2006, 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, 2006, which are accounted for on the equity method, are 49 percent of CYAPC, 38.5 percent of the YAEC, and 20 percent of the MYAPC. The total carrying value of NU's ownership interests in 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 $9.9 million and $28.6 million at December 31, 2006 and 2005, respectively. The decrease in the carrying value at December 31, 2006 is primarily related to the repurchase of CYAPC's stock owned by CL&P, PSNH and WMECO in the amount of $13.6 million in the fourth quarter of 2006. Earnings related to these equity investments are included in other income, net on the accompanying consolidated statements of income/(loss). For further information, see Note 1R, "Summary of Significant Accounting Policies - Other Income, Net," to the consolidated financial statements.

For further information, see Note 8E, "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 $7.9 million and $8.5 million at December 31, 2006 and 2005, 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 income/(loss), as follows:


	For the Years Ended December 31,
(Millions of Dollars, except percentages)	2006			2005			2004
Borrowed funds	$	13.5		$	10.1		$	3.9
Equity funds		13.6			12.3			3.8
Totals	$	27.1		$	22.4		$	7.7
Average AFUDC rates		7.5	%		7.2	%		4.1	%

The average Utility Group AFUDC rate is based on a FERC-prescribed formula that develops an average rate using the cost of a company's short-term financings as well as a company's capitalization (preferred stock, long-term debt and common equity). The average rate is applied to eligible construction work in progress (CWIP) amounts to calculate AFUDC. Fifty percent of CL&P's AFUDC is recorded in CWIP for its major transmission projects in southwest Connecticut with the other 50 percent in rate base. Once completed, the portion in CWIP is recovered in rates along with an appropriate ROE. The increase in AFUDC from borrowed and equity funds in 2006 as compared to 2005 and 2004 results from higher levels of CWIP due to CL&P's transmission projects, PSNH's Northern Wood Power Project and Yankee Gas' liquefied natural gas (LNG) project. The increase in the average AFUDC rate in 2006 is primarily due to the increased CWIP being financed by permanent capital and higher short-term debt rates.

Sale of Receivables

At December 31, 2005, CL&P had sold an undivided interest in its accounts receivable and unbilled revenue of $80 million to a financial institution with limited recourse through CL&P Receivables Corporation (CRC). At December 31, 2006, there were no such sales. CRC can sell up to $100 million of an undivided interest in its accounts receivable and unbilled revenues. At December 31, 2005, the reserve requirements calculated in accordance with the Receivables Purchase and Sale Agreement was $21 million. This reserve amount was deducted from the amount of receivables eligible for sale. 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, 2006 and 2005, amounts sold to CRC by CL&P but not sold to the financial institution totaling $375.7 million and $252.8 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 5, 2006, CRC renewed the bank commitment for the Receivables Purchase and Sale Agreement with CL&P and the financial institution through July 3, 2007 to coincide with the date this agreement terminates, unless otherwise extended. 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 Extinguishments of Liabilities - A Replacement of SFAS No. 125."

Beginning in the first quarter of 2007, NU will apply SFAS No. 156 related to the accounting for servicing of financial assets. See Note 1C, "Summary of Significant Accounting Policies - Accounting Standards Issued But Not Yet Adopted," for further information.

Asset Retirement Obligations

NU implemented FIN 47 on December 31, 2005. FIN 47 requires an entity to recognize a liability for the fair value of an asset retirement obligation (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 identified various categories of AROs, primarily certain assets containing asbestos and hazardous contamination. A fair value calculation, reflecting expected probabilities for settlement scenarios, has been performed.

For the year ended December 31, 2005, the earnings impact of this implementation was recorded as a cumulative effect of accounting change of $1 million, net of tax benefit, related to NU Enterprises. Because the Utility Group companies are cost-of-service rate regulated entities, these companies utilized regulatory accounting in accordance with SFAS No. 71, and the Utility Group companies' AROs are included in other regulatory assets at December 31, 2006 and 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 sheets at December 31, 2006 and 2005. Depreciation of the ARO asset is also included as a regulatory asset with an offsetting amount in accumulated depreciation.

The following tables present the fair value of the ARO, the related accumulated depreciation, the regulatory asset, and the ARO liabilities at December 31, 2006 and 2005:


	At December 31, 2006
(Millions of Dollars)	Fair Value of ARO Asset		Accumulated Depreciation of ARO Asset		Regulatory Asset		ARO Liabilities
Asbestos	$	3.8	$	(2.1)	$	20.1	$	(22.1)
Hazardous contamination		6.5		(1.6)		15.9		(20.7)
Other AROs		11.8		(5.5)		10.4		(16.9)
Total Utility Group AROs	$	22.1	$	(9.2)	$	46.4	$	(59.7)


	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 reconciliation of the beginning and ending carrying amounts of Utility Group AROs is as follows:


(Millions of Dollars)	2006
Balance at beginning of year	$	(60.2)
Liabilities incurred during the period		(5.7)
Liabilities settled during the period		1.6
Accretion		(0.6)
Change in assumptions		3.7
Revisions in estimated cash flows		1.5
Balance at end of year	$	(59.7)

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


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

The AROs outstanding related to NU Enterprises at December 31, 2005 were included in the sale of NGC and Mt. Tom generation assets.

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 and 2004 (millions of dollars):


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

A portion of special deposits represent amounts Select Energy has on deposit with unaffiliated counterparties and brokerage firms in the amounts of $48.5 million and $103.8 million at December 31, 2006 and 2005, respectively. SESI special deposits totaling $10.2 million were included in assets held for sale on the accompanying consolidated balance sheet at December 31, 2005.

The company also had amounts on deposit related to four special purpose entities used to facilitate the issuance of rate reduction bonds and certificates. These amounts, which totaled $102.5 million and $55.5 million at December 31, 2006 and 2005, respectively, are included in deferred debits and other assets - other on the accompanying consolidated balance sheets.

Other Taxes

Certain excise taxes levied by state or local governments are collected by NU from its customers. These excise taxes are accounted for on a gross basis with collections in revenues and payments in expenses. For the years ended December 31, 2006, 2005 and 2004, gross receipts taxes, franchise taxes and other excise taxes of $114.1 million, $112.7 million and $97 million, respectively, are included in operating revenues and taxes other than income taxes on the accompanying consolidated statements of income/(loss). Certain sales taxes are also collected by the Utility Group from its customers as agent for state and local governments and are recorded on a net basis with no impact on the accompanying consolidated statements of income/(loss).

Other Income, Net

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


	For the Years Ended December 31,
(Millions of Dollars)	2006		2005		2004
Other Income:
Investment income	$	24.9	$	19.1	$	12.2
CL&P procurement fee		11.0		17.8		11.7
AFUDC - equity funds		13.6		12.3		3.8
Conservation and load management incentive		6.5		7.7		6.7
Equity in earnings of regional nuclear generating and transmission companies		0.3		3.3		2.6
Gain on sale of RMS		-		-		0.8
Gain on sale of Globix		3.1		-		-
Other		6.3		1.4		0.9
Total Other Income		65.7		61.6		38.7
Other Loss:
Investment write-downs		-		(6.9)		(13.8)
Loss on investment in receivables		(1.1)		-		-
Rental investment expense		(0.2)		(0.2)		(2.2)
Total Other Loss		(1.3)		(7.1)		(16.0)
Total Other Income, Net	$	64.4	$	54.5	$	22.7

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

Equity in earnings relates to NU's investment in the Yankee Companies and the two Hydro-Quebec transmission companies.

The CL&P procurement fee represents compensation approved by the DPUC associated with Transitional Standard Offer (TSO) supply procurement. The conservation and load management incentive relates to incentives earned if certain energy and demand savings goals are met.

Based on developments in July of 2006, CYAPC management concluded that $10 million of CYAPC's regulatory assets were no longer probable of recovery and should be written off. NU included in 2006 other income, net its 49 percent share of CYAPC's after-tax write-off. For further information regarding CYAPC, see Note 8E, "Commitments and Contingencies - Deferred Contractual Obligations."

Supplemental Cash Flow Information


	For the Years Ended December 31,
(Millions of Dollars)	2006		2005		2004
Cash paid/(received) during the year for:
Interest, net of amounts capitalized	$	277.2	$	276.7	$	244.6
Income taxes	$	51.3	$	(56.1)	$	74.3

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, Non-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 balance sheets and statements of shareholders’ equity. NU currently maintains two trusts that hold marketable securities. The trusts are used to fund NU’s SERP, non-SERP and WMECO’s prior spent nuclear fuel liability. Realized gains and losses related to the SERP and non-SERP assets are included in other income, net, on the consolidated statements of income/(loss). 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 income/(loss).

Globix: In 2004, NEON Communications, Inc. (NEON) and Globix Corporation (Globix) announced a merger agreement in which Globix, an unaffiliated publicly owned entity, would acquire NEON for shares of Globix 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.

In connection with the merger, NU recorded a pre-tax write-down of $0.2 million in 2005. After the merger, NU recognized unrealized losses on its Globix investment in accumulated other comprehensive income. Also 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 of $5.9 million to reflect an other-than-temporary impairment. NU's investment in Globix totaled $3.7 million at December 31, 2005.

On April 6, 2006, NU sold its investment in Globix. This sale resulted in net proceeds of approximately $6.7 million and a pre-tax gain of $3.1 million in the second quarter of 2006.

For information regarding marketable securities, see Note 10, "Marketable Securities," to the consolidated financial statements.

Counterparty Deposits

Balances collected from counterparties resulting from Select Energy’s credit management activities totaled $0.1 million at December 31, 2006 and $28.9 million at December 31, 2005. These amounts are recorded as current liabilities and included as counterparty deposits on the accompanying 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 receivable 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.

In November of 2006, the DPUC issued an order allowing CL&P and Yankee Gas to accelerate the recovery of uncollectible hardship accounts receivable outstanding for greater than 90 days. In December of 2006, CL&P and Yankee Gas established reserves in the amount of $17 million and $8 million, respectively, with corresponding regulatory assets as these amounts are probable of recovery. Prior to the order, any write-offs of these amounts were deferred for recovery at the time of write-off. The CL&P reserve offsets amounts sold to CRC by CL&P but not sold to the financial institution which are classified as investments in securitizable assets on the accompanying consolidated balance sheets. The Yankee Gas reserve offsets receivables.

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 decision 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.

NU Enterprises recorded charges of $27.6 million and $69.2 million of pre-tax restructuring and impairment charges for the years ended December 31, 2006 and 2005, respectively, related to the decision to exit the merchant energy businesses and the energy services businesses. The amounts related to continuing operations are included as restructuring and impairment charges on the consolidated statements of income/(loss) with the remainder included in discontinued operations on the accompanying consolidated statements of income/(loss). These charges are included as part of the NU Enterprises reportable segment in Note 16, "Segment Information," to the consolidated financial statements. A summary of these pre-tax charges is as follows:


	Year Ended December 31, 2006		Year Ended December 31, 2005
Merchant Energy:
Wholesale Marketing:
Impairment charges	$	-	$	9.7
Restructuring charges		0.3		6.7
Subtotal		0.3		16.4
Retail Marketing:
Impairment charges		-		9.2
Restructuring charges		6.6		-
Subtotal		6.6		9.2
Competitive Generation:
Impairment charges		0.3		1.5
Restructuring charges		15.8		-
Subtotal		16.1		1.5
Subtotal - Merchant Energy		23.0		27.1
Energy Services and Other:
Impairment charges		-		39.1
Restructuring charges		4.6		3.0
Subtotal - Energy Services and Other		4.6		42.1
Total restructuring and impairment charges		27.6		69.2
Restructuring and impairment charges included in discontinued operations		17.3		25.1
Total restructuring and impairment charges included in continuing operations	$	10.3	$	44.1

For segment reporting purposes, $0.1 million of wholesale marketing restructuring charges, $3.5 million of retail marketing restructuring charges and $13.9 million of competitive generation restructuring charges for the year ended December 31, 2006 included in the table above are included in the NU Enterprises - Services and Other reportable segment as these amounts were recorded by NU Enterprises parent, primarily in connection with the sale of NU Enterprises' subsidiary NGC.

Wholesale Marketing: In 2006, $0.3 million of restructuring charges were recorded in the wholesale marketing segment for consulting fees, legal fees, employee-related and other costs.

In 2005, as a result of impairment analyses performed, $9.7 million of impairment charges were recorded related to the impairment of plant assets and the write-off of goodwill totaling $3.2 million related to Select Energy New York, Inc. operations. Restructuring charges totaling $6.7 were recorded in 2005 for consulting fees, legal fees, employee-related and other costs.

Retail Marketing: On June 1, 2006, NU Enterprises completed the sale of the retail marketing business to Hess. In 2006, NU Enterprises recorded restructuring charges of $6.6 million in the retail marketing segment for consulting fees, legal fees, employee-related costs and other costs.

In 2005, an exclusivity agreement intangible asset related to the retail marketing business totaling $7.2 million and a customer list asset totaling $2 million were written off as a result of impairment analysis performed. There were no restructuring charges recorded in 2005.

Competitive Generation: In 2006, $0.3 million of impairment charges were recorded in the competitive generation segment related to certain long-lived assets that were no longer recoverable. Restructuring charges of $15.8 million were recorded for the year ended December 31, 2006 for consulting fees, legal fees, sale-related environmental fees, employee-related and other costs.

In 2005, $1.5 million of impairment charges related to plant assets were recorded as a result of an impairment analysis performed. There were no restructuring charges recorded in 2005.

Energy Services and Other: In 2006, restructuring charges included $3.6 million related to consulting fees, legal fees, employee-related costs, and other costs as well as restructuring charges totaling $1 million related to NU Parent's guarantee of SESI's performance under government contracts. These guarantee-related charges represent estimated purchase and refinancing costs for two projects' contract payments. See Note 8H, "Commitments and Contingencies - Guarantees and Indemnifications," for further information.

In 2005, the company concluded that $29.1 million of goodwill associated with the energy services businesses and $9.2 million of intangible assets were impaired. Also in 2005, the energy services businesses and NU Enterprises parent recorded an additional impairment charge of $0.8 million due to the impairment of certain fixed assets resulting in a total impairment charge of $39.1 million for 2005. Restructuring charges totaling $3 million were recorded in 2005 for consulting fees, employee-related costs, and other costs.

The amounts described above are included in the services and other segment. See Note 16, "Segment Information," for further information.

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 sheets at December 31, 2006 and 2005:


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

In addition to the $1.2 million of severance costs included in restructuring charges above, $5.8 million of merchant energy severance costs and other employee benefits were recorded in other operating expenses on the accompanying consolidated statements of income/(loss) for the year ended December 31, 2006 because these amounts are for severance under an existing benefit arrangement. For further information, see Note 6F, "Employee Benefits - Severance Benefits."

Assets Held for Sale and Discontinued Operations

In 2005, NU decided to exit all of the NU Enterprises businesses. A summary of the NU Enterprises businesses held for sale status as of December 31, 2006 and 2005, as well as the discontinued operations status for all periods presented including date sold, is as follows:


	Held for Sale Status as of
	December 31, 2006	December 31, 2005	Discontinued Operations	Sale Date
Wholesale Marketing	No	No	No	Not Sold
Retail Marketing	Sold	No	No	June 2006
NGC (including certain components of NGS)	Sold	No	Yes	November 2006
Mt. Tom	Sold	No	Yes	November 2006
NGS	No	No	No	Not Sold
SESI	Sold	Yes	Yes	May 2006
Woods Electrical - Services	Sold	Yes	Yes	April 2006
Woods Electrical - Other	No	No	No	Not Sold
SECI-NH	Sold	Sold	Yes	November 2005
Woods Network	Sold	Sold	Yes	November 2005
Boulos	No	No	No	Not Sold
SECI-CT	No	No	No	Not Sold

Assets Held for Sale: In 2005, NU decided to exit NU Enterprises' wholesale and retail marketing and competitive generation businesses, which includes NGC and Mt. Tom, and determined that these businesses did not meet the held for sale criteria under applicable accounting guidance at December 31, 2005.

In the first quarter of 2006, management determined that the retail marketing and competitive generation businesses met held for sale criteria under applicable accounting guidance, and should be recorded at the lower of their carrying amount or fair value less cost to

sell. The retail marketing business was reduced to its fair value less cost to sell through a $53 million pre-tax charge, which was recorded in other operating expenses.

At December 31, 2006, Select Energy had current derivative assets and liabilities totaling $0.2 million and $0.1 million, respectively, related to administrative agreements for one remaining sourcing contract for which Select Energy has not yet received consent from the counterparty and a small number of retail gas sales contracts where the customer has not yet consented to the assignment to Hess.

For the years ended December 31, 2006 and 2005, NU recorded a pre-tax net gain from the sale of discontinued operations of $502.7 million and a pre-tax net loss from the sale of discontinued operations of $1.1 million, respectively. Included in the 2006 net gain is the gain on the sale of NGC and Mt. Tom of $511.1 million, partially offset by an $8.4 million loss on the sale of SESI. The sale of Woods Electrical - Services had a de minimis impact on earnings in 2006. The 2005 loss consists of a $0.8 million loss on the sale of Woods Network and a $0.3 million loss on the sale of SECI-NH.

In addition, for the year ended December 31, 2006, NU recorded a pre-tax gain on the sale of the Massachusetts service location of SECI-CT of $1.7 million and a pre-tax loss on the sale of Select Energy New York, Inc. of $0.3 million, which are recorded as other operating expenses on the consolidated statement of income/(loss).

At December 31, 2006, management continues to believe the wholesale marketing business, NGS, Woods Electrical - Other,

Boulos, and SECI-CT do not meet the held for sale criteria under applicable accounting guidance and therefore continue to be included in continuing operations.

The businesses above are included as part of the NU Enterprises reportable segment in Note 16, "Segment Information." The major classes of assets and liabilities that are held for sale at December 31, 2006 and, 2005 are as follows (amounts at December 31, 2005 are not comparable to amounts at December 31, 2006 as the assets held for sale portfolio has changed or the businesses have been sold prior to December 31, 2006):


	At December 31,
(Millions of Dollars)	2006		2005
Assets:
Retail derivative contracts	$	0.2	$	-
Other assets		-		22.3
Long-term contract receivables		-		79.5
Total assets		0.2		101.8
Liabilities:
Retail derivative contracts		0.1		-
Other liabilities		-		15.2
Long-term debt		-		86.3
Total liabilities		0.1		101.5
Net assets	$	0.1	$	0.3

Discontinued Operations: NU's consolidated statements of income/(loss) present NGC, Mt. Tom, SESI, and Woods Electrical - Services as discontinued operations for all periods presented. These businesses were sold in 2006. In addition, SECI-NH and Woods Network are presented as discontinued operations. These businesses were sold in 2005. Under discontinued operations presentation, revenues and expenses of the businesses classified as discontinued operations are classified net of tax in income from discontinued operations on the consolidated statements of income/(loss) and all prior periods are reclassified. Summarized financial information for the discontinued operations is as follows:


	For the Years Ended December 31,
(Millions of Dollars)	2006		2005		2004
Operating revenue	$	174.0	$	326.4	$	366.7
Income before income tax expense		44.8		24.3		76.8
Gain/(loss) from sale of discontinued operations		502.7		(1.1)		-
Income tax expense		203.1		9.1		30.0
Net income		344.4		14.1		46.8

Included in discontinued operations are $161 million, $222.2 million and $222 million for the years ended December 31, 2006, 2005 and 2004, respectively, of intercompany revenues that are not eliminated in consolidation due to the separate presentation of discontinued operations. Of these amounts, $160.7 million, $209.7 million and $195.4 million for the years ended December 31, 2006, 2005 and 2004, respectively, represent revenues on intercompany contracts between the generation operations of NGC and Mt. Tom and Select Energy. NGC's and Mt. Tom's revenues and earnings related to these contracts are included in discontinued operations while Select Energy's related expenses and losses are included in continuing operations. Included in discontinued operations is approximately $11 million pre-tax related to the resolution of contingencies for businesses sold.

Select Energy's obligation to NGC and Mt. Tom ended at the time of sale. See Note 8H, "Commitments and Contingencies - Guarantees and Indemnifications," for information related to an HWP coal purchase contract with a supplier and related back-to-back agreement with Energy Capital Partners (ECP). At December 31, 2006, NU does not expect that after disposal it will have significant ongoing involvement or continuing cash flows with the entities presented in discontinued operations.

The retail marketing business is not presented as discontinued operations because separate financial information is not available for this business for periods prior to the first quarter of 2006.

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 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 have no short-term borrowing limitations subsequent to February 8, 2006. CL&P and WMECO are subject to FERC jurisdiction as to issuing short-term debt subsequent to February 8, 2006 and must obtain new short-term debt authority from the FERC on or before 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 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 preferred stockholders for a ten-year period expiring in March of 2014 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. On March 18, 2004, the SEC approved this change in CL&P's charter. As of December 31, 2006, CL&P is permitted to incur $359.2 million of additional unsecured debt under this provision.

Utility Group Credit Agreement: CL&P, PSNH, WMECO, and Yankee Gas have a 5-year unsecured revolving credit facility for $400 million which expires on 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 at the request of the borrower, subject to lender approval. 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, 2006 and 2005, there were no borrowings outstanding under this facility.

NU Parent Credit Agreement: Effective December 31, 2006, NU reduced the total commitments under its 5-year unsecured revolving credit agreement from $700 million to $500 million, which may be increased at NU's request to $600 million, subject to lender approval. The decrease in the total commitment amount also resulted in a reduction in the letter of credit (LOC) commitment amount from $550 million to $500 million. Subject to the advances outstanding, LOCs may be issued for periods up to 364 days in the name of NU or any of its subsidiaries, including Select Energy. This agreement expires on November 6, 2010.

Under this facility, NU can borrow either on a short-term or a long-term basis. At December 31, 2006, there were no borrowings under this credit facility. At December 31, 2005, there were $32 million in borrowings outstanding. In addition, there were $67.5 million and $253 million in LOCs outstanding at December 31, 2006 and 2005, respectively.

Under the Utility Group and NU Parent credit agreements, NU and its subsidiaries may borrow at variable rates plus an applicable margin based upon the higher of Standard and Poor's (S&P) or Moody's Investors Service (Moody's) credit ratings. The weighted average interest rate on NU's notes payable to banks outstanding on December 31, 2005, was 7.25 percent.

Under the Utility Group and NU Parent 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 July 18, 2006, Boulos renewed its $6 million line of credit. This credit facility replaced a similar credit facility that expired on June 30, 2006 and unless extended, will expire on June 30, 2007. 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, 2006 and 2005, there were no borrowings under this credit facility.

Derivative Instruments

Contracts that are derivatives and do not meet the requirements to be treated as a cash flow hedge or normal purchases or normal sales are recorded at fair value with changes in fair value included in earnings. For those contracts that meet the definition of a

derivative and meet the cash flow hedge requirements, including those related to initial and ongoing documentation, the changes in the fair value of the effective portion of those contracts are generally recognized in accumulated other comprehensive income. Cash flow hedges impact net income when the forecasted transaction being hedged occurs, when hedge ineffectiveness is measured and recorded, when the forecasted transaction being hedged is no longer probable of occurring, or when there is accumulated other comprehensive loss and the hedge and the forecasted transaction being hedged are in a loss position on a combined basis. The ineffective portion of contracts that meet the cash flow hedge requirements is recognized currently in earnings. Derivative contracts designated as fair value hedges and the items they are hedging are both recorded at fair value with changes in fair value of both items recognized currently in earnings. Derivative contracts that meet the requirements of a normal purchase or sale, and are so designated, are recognized in revenues or expenses, as applicable, when the quantity of the contract is delivered. The change in fair value of a normal purchase or sale contract is not included in earnings.

The tables below summarize current and long-term derivative assets and liabilities at December 31, 2006 and 2005. At December 31, 2006 and 2005, derivative assets and liabilities of NU Enterprises have been segregated between wholesale, retail and generation amounts. The fair value of these contracts may not represent amounts that will be realized. On the accompanying consolidated balance sheets at December 31, 2006 and 2005, these amounts are recorded as current or long-term derivative assets or liabilities and are summarized as follows (millions of dollars):


	At December 31, 2006
	Assets				Liabilities
	Current		Long-Term		Current		Long-Term		Net Total
NU Enterprises:
Wholesale	$	43.6	$	22.3	$	(82.3)	$	(110.1)	$	(126.5)
Retail		0.2		-		(0.1)		-		0.1
Utility Group - Gas:
Non-trading		0.1		-		(0.2)		-		(0.1)
Utility Group - Electric:
Non-trading		45.0		249.5		(43.3)		(32.0)		219.2
NU Parent:
Hedging		-		-		-		(6.5)		(6.5)
		88.9		271.8		(125.9)		(148.6)		86.2
Derivative assets and liabilities held for sale		0.2		-		(0.1)		-		0.1
Totals	$	88.7	$	271.8	$	(125.8)	$	(148.6)	$	86.1


	At December 31, 2005
	Assets				Liabilities
	Current		Long-Term		Current		Long-Term		Net Total
NU Enterprises:
Wholesale	$	256.6	$	103.5	$	(369.3)	$	(220.9)	$	(230.1)
Retail		55.0		12.9		(27.2)		0.4		41.1
Generation		9.2		-		(5.1)		(15.5)		(11.4)
Utility Group - Gas:
Non-trading		0.1		-		(0.4)		-		(0.3)
Utility Group - Electric:
Non-trading		82.6		308.6		(0.5)		(31.8)		358.9
NU Parent:
Hedging		-		-		-		(5.2)		(5.2)
Totals	$	403.5	$	425.0	$	(402.5)	$	(273.0)	$	153.0

For the Utility Group, offsetting regulatory assets or liabilities are recorded for the changes in fair value of their contracts, as these contracts are part of the stranded costs, and management believes that these costs will continue to be recovered or refunded in cost-of-service, regulated rates. A summary of the mark-to-market amounts for NU Enterprises' wholesale and retail marketing and competitive generation businesses included on the accompanying consolidated statements of income/(loss) for the years ended December 31, 2006 and 2005 is as follows.


	Year Ended December 31,
(Millions of Dollars)	2006		2005
Operating revenues	$	7.4	$	17.3
Fuel, purchased and net interchange power		24.7		420.0
Other operating expenses		47.6		-
Discontinued operations		11.5		(15.5)

The business activities of NU Enterprises that result in the recognition of derivative assets result in exposures to credit risk to energy marketing and trading counterparties. At December 31, 2006, Select Energy had $66.1 million of derivative assets from wholesale and retail activities that are exposed to counterparty credit risk. At December 31, 2006, a significant portion of those assets is contracted with a creditworthy, non-rated public entity.

NU Enterprises - Wholesale: Certain electric derivative contracts are part of Select Energy's wholesale marketing business that the company is in the process of exiting. These contracts include wholesale short-term and long-term electricity supply and sales contracts, which include contracts to sell electricity to utilities under full requirements contracts, a contract to sell electricity to an agency that is comprised of municipalities with a term of seven remaining years, and two contracts to purchase the output of generating plants. The fair value of electricity contracts was determined by prices from external sources for years through 2011 and by models based on natural gas prices and a heat-rate conversion factor to electricity for subsequent periods.

The decision in March of 2005 to exit the wholesale marketing business changed management's conclusion regarding the likelihood that these wholesale marketing contracts would result in physical delivery to customers. This in turn resulted in a change in the first quarter of 2005 from accrual accounting to mark-to-market accounting for the wholesale marketing contracts. For the years ended December 31, 2006 and 2005, NU recorded pre-tax charges of $11.7 million and $425.4 million in fuel, purchased and net interchange power related to these contracts which the company is in the process of exiting. These charges are comprised of the following items and are recorded as follows:

Charges of $10.9 million and $419 million for the years ended December 31, 2006 and 2005, respectively, associated with the mark-to-market on certain long-dated wholesale electricity contracts in New England, New York and PJM and contracts to purchase generation products in New York.

A charge of $0.8 million for the year ended December 31, 2006 related to the fair value of certain asset-specific sales and forward sales of electricity at hub points for generation contracts. These contracts expired on December 31, 2006.

A benefit of $30 million for the year ended December 31, 2005 associated with contracts previously designated as wholesale that were redesignated to support the retail marketing business.

A charge of $36.4 million for the year ended December 31, 2005 for contract asset write-offs and a contract termination payment in March of 2005.

Included in the mark-to-market on long-term wholesale electricity contracts is a $12.5 million pre-tax mark-to-market charge for the year ended December 31, 2005 related to an intercompany contract between Select Energy and CL&P. This contract was included in the portfolio of contracts Select Energy assigned to a third-party wholesale power marketer, and Select Energy stopped serving CL&P on December 31, 2005. This contract was part of CL&P's stranded costs, and benefits received by CL&P under this contract were provided to CL&P's ratepayers in the form of lower-than-market standard offer service rates. A $2.8 million pre-tax mark-to-market charge in 2005 was recorded as wholesale contract market changes by Select Energy for the intercompany contract between Select Energy and WMECO for default service from April to June of 2005. WMECO's benefits under this contract were provided to its ratepayers in the form of lower-than-market default service rates. These charges were not eliminated in consolidation because on a consolidated basis NU retained the over-market obligation to the ratepayers of CL&P and WMECO.

In addition to the wholesale contract market charges described above, NU recorded additional charges to fuel, purchased and net interchange power of $4.5 million and $8.5 million related to wholesale and retail contracts, respectively, for the year ended December 31, 2006. Similar amounts for 2005 are a charge of $43.7 million and a benefit of $12.7 million for wholesale and retail contracts, respectively.

NU Enterprises - Retail: On June 1, 2006, Select Energy closed on the sale of its retail marketing business to Hess, and the related derivative assets and liabilities were transferred to Hess, except in cases where a customer has not yet consented to assignment. These remaining retail derivative assets and liabilities are recorded on the accompanying consolidated balance sheets at fair value using information from available external sources. At December 31, 2006, Select Energy had current derivative assets and liabilities totaling $0.2 million and $0.1 million, respectively, related to administrative agreements for one remaining sourcing contract for which Select Energy has not yet received consent from the counterparty and retail gas sales contracts where the customer has not yet

consented to the assignment to Hess. The net fair value position of the retail portfolio at December 31, 2005 was an asset of $17 million.

At December 31, 2005, Select Energy maintained natural gas service agreements with certain retail customers to supply gas at fixed prices for terms extending through 2010. New York Mercantile Exchange (NYMEX) futures contracts acquired to meet these commitments were recorded at fair value as derivative assets totaling $8.2 million and derivative liabilities of $0.3 million. Select Energy also maintained various financial instruments to hedge its electric and gas purchases and sales which included forwards, futures and swaps. At December 31, 2005, these hedging contracts, which were 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. These amounts were zero at December 31, 2006 because the contracts expired or were assigned to Hess.

In 2005, Select Energy hedged certain amounts of natural gas inventory with gas futures that were accounted for as fair value hedges. Changes in the fair value of hedging instruments and natural gas inventory were recorded in fuel, purchased and net interchange power. The change in fair value of the futures were included in derivative liabilities and amounted to $3.4 million at December 31, 2005. These amounts were zero at December 31, 2006 because the contracts expired or were assigned to Hess.

NU Enterprises - Generation: On November 1, 2006, NU closed on the sale of the competitive generation business, and the related derivative assets and liabilities were transferred to the buyer. At December 31, 2005, these derivative contracts included generation asset-specific sales and forward sales of electricity at hub trading points. These contracts had a net fair value position at December 31, 2005 of a liability of $11.4 million. The fair value of these contracts was determined by prices from external sources for the period of the contracts. Certain of these short-term forward purchase and sales contracts were recorded at fair value in revenues since inception. They represented market transactions at liquid points, while other generation-asset-specific sales and forward sales of electricity qualified for accrual accounting until the fourth quarter of 2005 when Select Energy marked them to market because the probability of physical delivery and the normal election could no longer be asserted. Changes in fair value of generation contracts formerly accounted for on an accrual basis were recorded in fuel, purchased and net interchange power for those contracts that were part of continuing operations. Changes in fair value of generation contracts that are held for sale were included in discontinued operations. These amounts were zero at December 31, 2006 because the contracts expired or were transferred to the buyer of the competitive generation business.

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 as these contracts are derivatives that cannot be designated as normal purchases and sales because of the optionality in the contract terms. Non-trading derivatives at December 31, 2006 included assets of $0.1 million and liabilities of $0.2 million. At December 31, 2005, non-trading derivatives included assets of $0.1 million and liabilities of $0.4 million.

Utility Group - Electric - Non-Trading: CL&P has contracts with two IPPs 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, 2006 include a derivative asset with a fair value of $289.6 million and a derivative liability with a fair value of $35.7 million. An offsetting regulatory liability and an offsetting regulatory asset were recorded, as these contracts are part of the stranded costs, and management believes that these costs will continue to be recovered or refunded in cost-of-service, regulated rates. At December 31, 2005, the fair values of these IPP non-trading derivatives included a derivative asset with a fair value of $391.2 million and a derivative liability with a fair value of $32.3 million.

CL&P has entered into Financial Transmission Rights (FTR) contracts to limit the congestion costs associated with its TSO contracts. An offsetting regulatory asset has been recorded as this contract is part of the stranded costs, and management believes that these costs will be recovered in rates. At December 31, 2006, the fair value of these contracts is recorded as a derivative asset of $4.9 million and a derivative liability of $0.4 million on the accompanying consolidated balance sheets. The fair value of CL&P's FTRs at December 31, 2005 was equal to the value when acquired as there were no changes in fair value of the FTRs through December 31, 2005.

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

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

NU Parent - Hedging: In March of 2003, to manage the interest rate characteristics of the company's long-term debt, NU Parent entered into a fixed to floating interest rate swap on its $263 million, 7.25 percent fixed rate note that matures on April 1, 2012. Under fair value hedge accounting, the changes in fair value of the swap and the hedged debt instrument are recorded in interest expense. The cumulative changes in the fair value of the swap and the debt are recorded as derivative liabilities and decreases to long-term debt of $6.5 million at December 31, 2006 and $5.2 million at December 31, 2005.

Employee Benefits

Pension Benefits and Postretirement Benefits Other Than Pensions

On December 31, 2006, NU implemented SFAS No. 158, which amends SFAS No. 87, "Employers’ Accounting for Pensions," SFAS No. 88, "Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits," SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," and SFAS No. 132(R), "Employers' Disclosures about Pensions and Other Postretirement Benefits." SFAS No. 158 applies to NU’s Pension Plan, SERP, and PBOP Plan and required NU to record the funded status of these plans based on the projected benefit obligation (PBO) for the Pension Plan and accumulated postretirement benefit obligation (APBO) for the PBOP Plan on the consolidated balance sheet at December 31, 2006. Previously, the prepaid or accrued benefit obligation was recorded in accordance with SFAS No. 87 and SFAS No. 106, which allowed for the deferral of certain items, and reconciliation to the funded status was provided in the footnotes to financial statements. These deferred items included the transition obligation, prior service costs, and net actuarial loss.

SFAS No. 158 requires the additional liability to be recorded with an offset to accumulated other comprehensive income in shareholders’ equity. NU recorded an after-tax charge totaling $4.4 million to accumulated other comprehensive income related to the impact of SFAS No. 158 on NU's unregulated subsidiaries. However, because the Utility Group companies are cost-of-service rate regulated entities under SFAS No. 71, regulatory assets were recorded in the amount of $407.4 million, as these amounts in benefits expense have been and continue to be recoverable in cost-of-service, regulated rates. Regulatory accounting was also applied to the portions of the NUSCO costs that support the Utility Group, as these amounts are also recoverable.

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


	For the Years Ended December 31,
(Millions of Dollars)	2006		2005		2004
Total pension expense	$	50.2	$	54.2	$	8.0
Amount capitalized as utility plant		(11.5)		(11.5)		2.6
Total pension expense, net of amounts capitalized	$	38.7	$	42.7	$	10.6

Total pension expense above includes pension curtailments and termination benefits benefit of $2.5 million in 2006, expense of $11.7 million in 2005, and expense of $2.1 million in 2004.

Pension Curtailments and Termination Benefits: In December of 2005, a new program was approved providing a benefit for certain employees hired on and after January 1, 2006 providing for these employees to receive retirement benefits under a new 401(k) benefit (K-Vantage Plan) rather than under the Pension Plan. The approval of the new plan resulted in the recording of an estimated pre-capitalization, pre-tax curtailment expense of $6.2 million in 2005, as a certain number of employees hired before that date were expected to elect the new 401(k) benefit as permitted, 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. Because the predicted level of elections of the new benefit did not occur, NU recorded a pre-capitalization, pre-tax reduction in the curtailment expense of $3.6 million in 2006.

In 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.

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.

SERP: NU has maintained a SERP since 1987. The SERP provides its eligible participants, who are officers 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.

For information regarding SERP investments that are used to fund the SERP liability, see Note 10, "Marketable Securities," to the consolidated financial statements.

Postretirement Benefits Other Than Pensions: NU’s subsidiaries provide certain health care benefits, primarily medical and dental, and life insurance benefits through a 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 that are tax deductible. Currently, there are no pending regulatory actions regarding postretirement benefit costs.

Impact of Medicare Changes on PBOP: On December 8, 2003, the President signed into law a bill that expanded 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 total PBOP benefit obligation by $27 million as of December 31, 2006 and 2005. 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, 2006, 2005 and 2004, this reduction in PBOP expense totaled approximately $3.6 million, including amortization of actuarial gains of $2 million and a reduction in interest cost and service cost based on a lower PBOP benefit obligation of $1.6 million. At December 31, 2006, NU had a receivable for the federal subsidy in the amount of $3.2 million related to benefit payments made in 2006. This amount is expected to be funded into the PBOP Plan.

PBOP Curtailments and Termination Benefits: NU recorded an estimated $3.7 million pre-tax curtailment expense at December 31, 2005 relating to its corporate reorganization. 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. Based on refinements to its estimates, NU recorded an adjustment to the curtailment and related termination benefits in 2006. This adjustment resulted in a combined pre-capitalization, pre-tax reduction in the curtailment expense and termination benefits of $1.9 million in 2006. There were no curtailments or termination benefits in 2004.

The following table represents information on the plans’ benefit obligations, fair values of plan assets, and funded status:


	At December 31,
	Pension Benefits				SERP Benefits				Postretirement Benefits
(Millions of Dollars)	2006		2005		2006		2005		2006		2005
Change in benefit obligation
Benefit obligation at beginning of year	$	(2,286.2)	$	(2,133.2)	$	(35.1)	$	(32.1)	$	(493.8)	$	(468.3)
Service cost		(49.4)		(48.7)		(1.1)		(1.0)		(8.3)		(8.0)
Interest cost		(129.7)		(125.6)		(1.9)		(1.9)		(27.3)		(25.2)
Actuarial gain/(loss)		58.3		(148.7)		2.1		(2.0)		23.4		(32.7)
Federal subsidy on benefits paid		-		-		-		-		(3.2)		-
Benefits paid - excluding lump sum payments		116.1		109.1		2.0		1.9		39.9		38.9
Benefits paid - lump sum payments		-		0.1		-		-		-		-
Curtailment/impact of plan changes		(41.4)		63.6		-		-		(0.3)		2.0
Termination benefits		(2.3)		(2.8)		-		-		(0.3)		(0.5)
Benefit obligation at end of year	$	(2,334.6)	$	(2,286.2)	$	(34.0)	$	(35.1)	$	(469.9)	$	(493.8)
Change in plan assets
Fair value of plan assets at beginning of year	$	2,122.6	$	2,075.5		N/A		N/A	$	222.9	$	199.8
Actual return on plan assets		349.7		156.3		N/A		N/A		33.0		12.1
Employer contribution		-		-		N/A		N/A		50.6		49.9
Benefits paid - excluding lump sum payments		(116.1)		(109.1)		N/A		N/A		(39.9)		(38.9)
Benefits paid - lump sum payments		-		(0.1)		N/A		N/A		-		-
Fair value of plan assets at end of year	$	2,356.2	$	2,122.6		N/A		N/A	$	266.6	$	222.9
Funded status at December 31^st	$	21.6	$	(163.6)	$	(34.0)	$	(35.1)	$	(203.3)	$	(270.9)
Unrecognized transition obligation				0.5				-				78.6
Unrecognized prior service cost				40.5				0.8				(4.1)
Unrecognized actuarial net loss				421.1				8.3				179.9
Prepaid/(accrued) benefit cost			$	298.5			$	(26.0)			$	(16.5)

The $63.6 million reduction in 2005 in the Pension Plan's obligation that is included in the curtailment/impact of plan changes related to the reduction in the future years of service expected to be rendered by plan participants. This reduction was the result of the expected transition of employees into the new 401(k) benefit and the company's corporate reorganization. This overall reduction in plan obligation served to reduce the previously unrecognized actuarial losses. In 2006, $41.4 million of this curtailment was reversed

because actual levels of elections of the new 401(k) benefit were much lower than expected and is reflected above as an increase to the obligation.

For the Pension Plan, the company amortizes its transition obligation over the remaining service lives of its employees as calculated on an individual operating company basis and amortizes the prior service cost and unrecognized net actuarial loss over the remaining service lives of its employees as calculated on an NU consolidated basis. For the PBOP Plan, the company amortizes its transition obligation, prior service cost, and unrecognized net actuarial loss over the remaining service lives of its employees as calculated on an individual operating company basis.

Although the SERP does not have any plan assets, NU supports the SERP with earnings on marketable securities. See Note 10, "Marketable Securities," for further information regarding these investments.

The accumulated benefit obligation for the Pension Plan was $2.096 billion and $2.061 billion at December 31, 2006 and 2005, respectively, and $31.4 million and $29.4 million for the SERP at December 31, 2006 and 2005, respectively.

Amounts recognized in the accompanying consolidated balance sheets at December 31, 2006 and 2005 are as follows:


	At December 31,
	Pension Benefits				SERP Benefits				Postretirement Benefits				Total
(Millions of Dollars)	2006		2005		2006		2005		2006		2005		2006		2005

Receivables	$	-	$	-	$	-	$	-	$	3.2	$	-	$	3.2	$	-
Regulatory assets		223.5		-		5.6		-		178.3		-		407.4		-
Prepaid pension		21.6		298.5		-		-		-		-		21.6		298.5
Total assets		245.1		298.5		5.6		-		181.5		-		432.2		298.5

Other current liabilities (2)		-		-		(2.0)		-		-		-		(2.0)		-
Deferred taxes, net		(11.7)		(108.7)		12.6		9.9		(37.1)		7.2		(36.2)		(91.6)
Accrued postretirement benefits		-		-		-		-		(203.3)		(16.5)		(203.3)		(16.5)
Other deferred credits		-		-		(32.0)		(26.0)		-		-		(32.0)		(26.0)
Total liabilities		(11.7)		(108.7)		(21.4)		(16.1)		(240.4)		(9.3)		(273.5)		(134.1)

Accumulated other comprehensive loss, net of tax	$	(1.9)	$	-	$	(0.2)	$	(0.5)	$	(2.3)	$	-	$	(4.4)	$	(0.5)

The incremental impact of implementing SFAS No. 158 on the consolidated balance sheet at December 31, 2006 is as follows:


(Millions of Dollars)	Before Adopting SFAS No. 158		Adjustments to Adopt SFAS No. 158		After Adopting SFAS No. 158
Regulatory assets (1)	$	1.6	$	405.8	$	407.4
Prepaid pension		248.3		(226.7)		21.6
Other deferred debits (1)		0.7		(0.7)		-
Total assets		250.6		178.4		429.0

Other current liabilities (2)		-		(2.0)		(2.0)
Deferred taxes, net		(97.1)		60.9		(36.2)
Accrued postretirement benefits		(14.8)		(188.5)		(203.3)
Other deferred credits		(31.7)		(0.3)		(32.0)
Total liabilities		(143.6)		(129.9)		(273.5)

Accumulated other comprehensive loss, net of tax (1)	$	(0.2)	$	(4.2)	$	(4.4)

(1)

The regulatory assets and accumulated other comprehensive loss amounts before adopting SFAS No. 158 represent the regulated and unregulated portions, respectively, of an additional minimum pension liability recorded for the SERP. The amount in other deferred debits represents an intangible asset recorded under SFAS No. 87 to account for a portion of the additional minimum pension liability recorded for the SERP. This amount was reversed as part of the adoption of SFAS No. 158.

(2)

Amounts reflected in other current liabilities above represent the short-term portion of the SERP liability related to benefit payments expected to be made in the next year.

The following is a summary of amounts recorded as regulatory assets at December 31, 2006 and the portions of those amounts expected to be recognized as portions of net periodic benefit cost in 2007, which is expected to total $26.2 million for the Pension Plan, $3.6 million for the SERP and $39.8 million for the PBOP Plan on a pre-tax basis:


	At December 31, 2006								Estimated Expense in 2007
(Millions of Dollars)	Pension		SERP		OPEB		Total		Pension		SERP		OPEB		Total
Transition obligation	$	0.7	$	-	$	67.9	$	68.6	$	0.2	$	-	$	11.3	$	11.5
Prior service cost		38.1		0.6		(3.9)		34.8		6.5		0.2		(0.3)		6.4
Net actuarial loss		184.7		5.0		114.3		304.0		26.2		0.6		8.8		35.6
Total	$	223.5	$	5.6	$	178.3	$	407.4	$	32.9	$	0.8	$	19.8	$	53.5

The following is a summary of losses recorded in accumulated other comprehensive income, net of tax, at December 31, 2006 and the portions of those amounts expected to be recognized as portions of net periodic benefit cost in 2007, which is expected to total $26.2 million for the Pension Plan, $3.6 million for the SERP and $39.8 million for the PBOP Plan on a pre-tax basis:


	At December 31, 2006								Estimated Expense in 2007
(Millions of Dollars)	Pension		SERP		OPEB		Total		Pension		SERP		OPEB		Total
Transition obligation	$	-	$	-	$	0.4	$	0.4	$	-	$	-	$	0.2	$	0.2
Prior service cost		0.4		-		-		0.4		0.1		-		-		0.1
Net actuarial loss		1.5		0.2		1.9		3.6		1.0		-		0.3		1.3
Total	$	1.9	$	0.2	$	2.3	$	4.4	$	1.1	$	-	$	0.5	$	1.6

For further information, see Note 14, "Accumulated Other Comprehensive Income/(Loss)," to the consolidated financial statements.

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


	At December 31,
	Pension Benefits and SERP				Postretirement Benefits
Balance Sheets	2006		2005		2006		2005
Discount rate	5.90	%	5.80	%	5.80	%	5.65	%
Compensation/progression rate	4.00	%	4.00	%	N/A		N/A
Health care cost trend rate	N/A		N/A		9.00	%	10.00	%

The components of net periodic expense are as follows:


	For the Years Ended December 31,
	Pension Benefits						SERP Benefits						Postretirement Benefits
(Millions of Dollars)	2006		2005		2004		2006		2005		2004		2006		2005			2004
Service cost	$	49.4	$	48.7	$	40.7	$	1.1	$	1.0	$	0.9	$	8.3	$	8.0	$	6.0
Interest cost		129.7		125.6		118.9		1.9		1.9		1.9		27.3		25.2		25.3
Expected return on plan assets		(174.0)		(172.0)		(175.1)		-		-		-		(14.0)		(12.3)		(12.5)
Net transition (asset)/obligation cost		(0.1)		(0.3)		(1.5)		-		-		-		11.6		11.8		11.9
Prior service cost		6.6		7.1		7.2		0.2		0.2		0.3		(0.3)		(0.4)		(0.4)
Actuarial loss		41.1		33.4		15.7		0.9		0.6		0.9		17.8		17.5		11.4
Net periodic expense - before curtailments and termination benefits		52.7		42.5		5.9		4.1		3.7		4.0		50.7		49.8		41.7
Curtailment (benefit)/expense		(4.8)		8.9		-		-		-		-		(2.2)		3.7		-
Termination benefits expense		2.3		2.8		2.1		-		-		-		0.3		0.5		-
Total curtailments and termination benefits		(2.5)		11.7		2.1		-		-		-		(1.9)		4.2		-
Total - net periodic expense	$	50.2	$	54.2	$	8.0	$	4.1	$	3.7	$	4.0	$	48.8	$	54.0	$	41.7

The following assumptions were used to calculate pension and postretirement benefit expense and income amounts:


	For the Years Ended December 31,
Statements of Income	Pension Benefits and SERP						Postretirement Benefits
	2006		2005		2004		2006		2005		2004
Discount rate	5.80	%	6.00	%	6.25	%	5.65	%	5.50	%	6.25	%
Expected long-term rate of return	8.75	%	8.75	%	8.75	%	N/A		N/A		N/A
Compensation/progression rate	4.00	%	4.00	%	3.75	%	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,
	2006		2005
Health care cost trend rate assumed for next year	9.00	%	10.00	%
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		2011

At December 31, 2005, 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	$	1.2	$	(1.0)
Effect on postretirement benefit obligation	$	16.9	$	(14.6)

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
	2006 and 2005		2006 and 2005
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, 2006 and 2005 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	2006	2005	2006	2005
Equity Securities:
United States	46%	46%	54%	54%
Non-United States	16%	16%	14%	14%
Emerging markets	4%	4%	1%	1%
Private	5%	5%	-	-
Debt Securities:
Fixed income	19%	19%	29%	29%
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/(received) for the Pension, SERP, and PBOP Plans:


(Millions of Dollars)
Year	Pension Benefits		SERP Benefits		Postretirement Benefits		Government Benefits
2007	$	116.4	$	2.0	$	44.6	$	(4.5)
2008		119.7		2.1		45.4		(5.0)
2009		123.4		2.2		46.0		(5.4)
2010		127.5		2.3		46.4		(5.9)
2011		132.0		2.4		46.4		(6.3)
2012-2016		758.3		13.0		230.4		(37.0)

The government benefits represent amounts expected to be received from the federal government for the new Medicare prescription drug benefit under the PBOP Plan related to the corresponding year's benefit payments.

Contributions: Currently, NU’s policy is to annually fund the Pension Plan in an amount at least equal to that which will satisfy the requirements of the Employee Retirement Income Security Act and Internal Revenue Code. For the PBOP Plan, it is currently NU's policy to annually fund an amount equal to the PBOP Plan’s postretirement benefit cost, excluding curtailment and termination benefits. NU does not expect to make any contributions to the Pension Plan in 2007 and expects to make $39.8 million in contributions to the PBOP Plan in 2007. Beginning in 2007, NU will make an additional contribution to the PBOP Plan for the amounts received from the federal Medicare subsidy. This amount is estimated at $3.2 million for 2007.

Defined Contribution Plans

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 in cash and two percent in NU common shares. The 401(k) matching contributions of cash and NU common shares made by NU were $11 million in 2006, $10.7 million in 2005 and $10.5 million in 2004.

Effective on January 1, 2006, all newly hired, non-bargaining unit employees, and effective on January 1, 2007 or as subject to collective bargaining agreements, certain newly hired bargaining unit employees participate in a new defined contribution savings plan called the K-Vantage Plan. These participants are not eligible to be participants in the existing defined benefit Pension Plan. In addition, current participants in the Pension Plan were given the opportunity to choose to become a participant in the K-Vantage Plan beginning in 2007, in which case their benefit under the Pension Plan was frozen.

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 $8.2 million in 2006, $11.2 million in 2005 and $12 million in 2004. Interest expense on the unsecured notes was $3.2 million, $3.3 million and $5.7 million in 2006, 2005 and 2004, respectively. For the years ended December 31, 2006, 2005 and 2004, NU recognized $7.4 million, $7.7 million and $7.3 million, respectively, of expense related to the ESOP, excluding the interest expense on the unsecured notes. The $75 million series B note was fully repaid in March of 2005. The $175 million series A note was fully repaid in December of 2006. As a result, no further interest expense will be incurred for the ESOP.

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 2005, NU paid a $0.1625 per share quarterly dividend. During the third quarter of 2005 through the second quarter of 2006, NU paid a $0.175 per share quarterly dividend. NU paid a $0.1875 per share dividend during the third and fourth quarters of 2006.

In 2006 and 2005, the ESOP trust issued 523,452 and 590,173 of NU common shares, respectively, to satisfy 401(k) Savings Plan obligations to employees. At December 31, 2006 and 2005, total allocated ESOP shares were 9,297,336 and 8,773,884, respectively, and total unallocated ESOP shares were 1,502,849 and 2,026,301, respectively. The fair market value of the unallocated ESOP shares at December 31, 2006 and 2005 was $42.3 million and $39.9 million, respectively.

Share-Based Payments

NU maintains an Employee Share Purchase Plan (ESPP) and other long-term equity-based incentive plans under the Northeast Utilities Incentive Plan (Incentive Plan). In the first quarter of 2006, NU adopted SFAS No. 123(R), "Share-Based Payments," under the modified prospective method. Adoption of SFAS No. 123(R) had a de minimis effect on NU's financial statements and no effect on NU's income/(loss) per share. For the year ended December 31, 2006, a tax benefit in excess of compensation cost totaling $1.1 million increased cash flows from financing activities.

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

Under SFAS No. 123(R), NU accounts for its various share-based plans as follows:

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

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

For shares granted under the ESPP, an immaterial amount of compensation expense was recorded in the first quarter of 2006, and no compensation expense was recorded in the remainder of 2006 or will be recorded in future periods as a result of a plan amendment that was effective on February 1, 2006.

Incentive Plan: Under the Incentive Plan, NU is authorized to grant new shares for various types of awards, including restricted shares, RSUs, performance units, and stock options to eligible employees and board members. At December 31, 2006, the number of shares that may be utilized for grants and awards during a given calendar year may not exceed the aggregate of one percent of the total number of NU common shares outstanding as of the first day of that calendar year plus the shares not utilized in previous years. At December 31, 2006 and 2005, NU had 570,494 and 906,154 shares of common stock, respectively, registered for issuance under the Incentive Plan.

Restricted Shares and RSUs: NU has granted restricted shares under the 2002, 2003 and 2004 incentive programs that are subject to three-year and four-year graded vesting schedules. NU has granted RSUs under the 2004, 2005 and 2006 incentive programs that are subject to three-year and four-year graded vesting schedules. RSUs are paid in shares plus cash sufficient to satisfy withholdings subsequent to vesting. A summary of restricted share and RSU transactions for the year ended December 31, 2006 is as follows:


Restricted Shares	Restricted Shares	Weighted Average Grant - Date Fair Value	Total Grant - Date Fair Value (Millions)	Remaining Compensation Cost (Millions)	Weighted Average Remaining Period (Years)
Outstanding at December 31, 2005	152,901	N/A
Granted	-	-
Vested	(74,243)	$14.52	$1.1
Forfeited	(12,984)	$14.14
Outstanding at December 31, 2006	65,674	$15.00	$1.0	$0.2	0.3

The per share and total weighted average grant date fair value for restricted shares vested was $14.60 and $1.4 million, respectively, for the year ended December 31, 2005 and $14.84 and $1.9 million, respectively, for the year ended December 31, 2004.

The total compensation cost recognized for restricted shares was $0.6 million, net of taxes of approximately $0.4 million for the year ended December 31, 2006, $0.7 million, net of taxes of approximately $0.4 million for the year ended December 31, 2005, and $0.9 million, net of taxes of approximately $0.6 million for the year ended December 31, 2004.


RSUs	RSUs (Units)	Weighted Average Grant - Date Fair Value	Total Grant - Date Fair Value (Millions)	Remaining Compensation Cost (Millions)	Weighted Average Remaining Period (Years)
Outstanding at December 31, 2005	521,273	N/A
Granted	371,134	$19.87
Issued	(120,166)	$18.50	$ 2.2
Forfeited	(56,942)	$19.31
Outstanding at December 31, 2006	715,299	$19.41	$13.9	$6.5	1.8

The per share and total weighted average grant date fair value for RSUs granted was $18.89 and $5.8 million, respectively, for the year ended December 31, 2005 and $19.07 and $7.3 million, respectively, for the year ended December 31, 2004. The weighted average grant date fair value per share for RSUs issued was $19.06 and $18.65 for the years ended December 31, 2005 and 2004, respectively. The total weighted average fair value of RSUs issued was $1.9 million for the year ended December 31, 2005. The total weighted average fair value of RSUs issued in 2004 was de minimis.

The total compensation cost recognized for RSUs was $2.8 million, net of taxes of approximately $1.9 million for the year ended December 31, 2006, $1.9 million, net of taxes of approximately $1.3 million for the year ended December 31, 2005, and $1.4 million, net of taxes of approximately $1 million for the year ended December 31, 2004.

Stock Options: Prior to 2003, NU granted stock options to certain employees. These options were fully vested as of December 31, 2005. The fair value of each stock option grant was estimated on the date of grant using the Black-Scholes option pricing model. The weighted average remaining contractual lives for the options outstanding at December 31, 2006 is 3.8 years. A summary of stock option transactions is as follows:


		Exercise Price Per Share
	Options	Range			Weighted Average	Intrinsic Value
						(Millions)
Outstanding - December 31, 2003	3,123,322	$ 9.6250	-	$22.2500	$17.1270
Exercised	(612,666)				$12.3181	$3.2
Forfeited and cancelled	(516,914)				$16.6139
Outstanding - December 31, 2004	1,993,742	$14.9375	-	$22.2500	$18.7370
Exercised	(368,192)				$12.7262	$0.7
Forfeited and cancelled	(503,009)				$18.1703
Outstanding and Exercisable - December 31, 2005	1,122,541	$14.9375	-	$22.2500	$18.4484
Exercised	(331,943)				$18.3579	$2.0
Forfeited and cancelled	(18,750)				$20.8885
Outstanding and Exercisable - December 31, 2006	771,848	$14.9375	-	$22.2500	$18.4245	$7.5
Exercisable - December 31, 2003	2,027,413				$16.6969
Exercisable - December 31, 2004	1,877,595				$18.7778

A summary of the ranges of exercise prices of stock options outstanding and exercisable as of December 31, 2006 is as follows:


	Exercise Price Per Share
Options	Range	Weighted Average	Contractual Term (Years)
156,516	$14.9375 - $16.6800	$15.6198	1.7
615,332	$16.6900 - $22.2500	$19.1380	4.3
771,848	$14.9375 - $22.2500	$18.4245	3.8

Cash received for options exercised during the years ended December 31, 2006 and 2005 totaled $6.1 million and $7.4 million, respectively. The tax benefit realized from stock options exercised totaled $0.8 million and $0.3 million for the years ended December 31, 2006 and 2005, respectively.

Employee Share Purchase Plan: NU maintains an ESPP for all eligible employees. Prior to February 1, 2006, NU common shares were purchased by employees at six-month intervals at 85 percent of the lower of the price on the first or last day of each six-month period. Employees were permitted to purchase shares having a value not exceeding 25 percent of their compensation as of the beginning of the purchase period. Effective February 1, 2006, the ESPP was amended to change the discount rate to 5 percent of the closing market price on the last day of the purchase period. As a result, the ESPP qualifies as a non-compensatory plan under SFAS No. 123(R), and no compensation expense was or will be recorded for ESPP purchases.

During 2006 and 2005, employees purchased 113,404 and 209,184 shares, respectively, at discounted prices of $16.90 and $21.28 in 2006 and $15.85 and $15.90 in 2005. At December 31, 2006 and 2005, 1,067,815 shares and 1,181,219 shares remained registered for future issuance under the ESPP, respectively.

Pro Forma Impact: The following table illustrates the pro forma effect if NU had applied the recognition provisions of SFAS No. 123 to share-based compensation in 2005 and 2004:


	For the Years Ended December 31,
(Millions of Dollars, except share information)		2005		2004
Net (loss)/income as reported	$	(253.5)	$	116.6
Add: Equity-based employee compensation expense included in the reported net (loss)/income, net of related tax effects		2.6		2.3
Net (loss)/income before equity-based compensation		(250.9)		118.9
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)
Pro forma net (loss)/income		(252.1)		116.2
EPS:
Basic and diluted - as reported	$	(1.93)	$	0.91
Basic and diluted - pro forma	$	(1.92)	$	0.91

The total equity-based employee compensation expense of $1.2 million and $2.7 million above includes offsetting amounts of $2.2 million and $0.7 million, related to forfeitures of stock options made for the years ended December 31, 2005 and 2004, respectively.

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

Other Retirement Benefits

NU provides benefits for retirement and other benefits for certain current and past company officers. The actuarially-determined liability for these benefits which is included in deferred credits and other liabilities - other on the accompanying consolidated balance sheets was $46.5 million and $37.4 million at December 31, 2006 and 2005, respectively. During 2006, 2005 and 2004, $5.6 million, $4.5 million and $4.5 million, respectively, was expensed related to these benefits. These benefits, which do not meet the definition of a pension plan under SFAS No. 87 or SFAS No. 158, are accounted for on an accrual basis and expensed as services are recorded in accordance with the Accounting Principles Board Opinion (APB) No. 12, "Deferred Compensation Contracts."

Severance Benefits

As a result of its corporate reorganization, in 2005 NU recorded severance and related expenses totaling $14.1 million relating to expected terminations of Utility Group and NUSCO employees. These severance benefits were recorded in other operating expenses and were excluded from restructuring charges as described in Note 2, "Restructuring and Impairment Charges," because these amounts were for severance benefits under an existing benefit arrangement. In 2006, NU updated its prior estimates of Utility Group and NUSCO severance benefits based upon actual termination data and updated its estimates of expected personnel reductions. A total reduction in severance and related expenses of $2.4 million was recorded and is included in other operating expenses on the accompanying consolidated statements of income/(loss) for the year ended December 31, 2006, primarily due to a reduction in the expected number of terminated Utility Group and NUSCO employees.

Severance benefits for employees in the retail marketing and competitive generation businesses were not recorded in 2005, as management expected to sell these businesses as going concerns with the employees being transferred to the buyers. In 2006, NU recorded $7 million for severance and other employee benefits, as these benefits became probable and estimable as a result of the sales of the retail marketing business and NGC and Mt. Tom. Of this amount, $1.2 million was for enhanced minimum benefits and was included in restructuring charges, with the remaining $5.8 million included in other operating expenses on the accompanying consolidated statements of income/(loss) for the year ended December 31, 2006 because these amounts were for benefits under an existing benefit arrangement.

Goodwill and Other Intangible Assets

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

NU’s reporting unit that maintains goodwill is consistent with the operating segments underlying the reportable segments identified in Note 16, "Segment Information," to the consolidated financial statements. The only 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. The goodwill balance held by the Yankee Gas reporting unit at December 31, 2006 and 2005 is $287.6 million.

NU completed its impairment analysis of the Yankee Gas goodwill balance as of October 1, 2006 and 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 and transactions.

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 these businesses were determined to be impaired in their entirety, and $32.3 million 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. The charges related to continuing operations are included in restructuring and impairment charges on the accompanying consolidated statements of income/(loss) and in the NU Enterprises reportable segment in Note 16, "Segment Information," to the consolidated financial statements, with the remainder included in discontinued operations.

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

At December 31, 2006, NU Enterprises remaining intangible assets relating to an energy services business which has not yet been sold were insignificant.

Commitments and Contingencies

Regulatory Developments and Rate Matters

Connecticut:

Income Taxes: In 2000, CL&P requested from the IRS a PLR regarding the treatment of UITC and EDIT related to generation assets that were sold. On April 18, 2006, the IRS issued a PLR to CL&P regarding the treatment of UITC and EDIT. EDIT are temporary differences between book and taxable income that were recorded when the federal statutory tax rate was higher than it is now or when those differences were expected to be resolved. The PLR holds that it would be a violation of tax regulations if the EDIT or UITC are used to reduce customers' rates following the sale of the generation assets. CL&P's UITC and EDIT balances related to generation assets that have been sold totaled $59 million and $15 million, respectively, and $74 million combined. CL&P was ordered by the DPUC to submit the PLR to the DPUC within 10 days of issuance and retain the UITC and EDIT in their existing accounts pending its receipt and review of the PLR. On July 27, 2006, the DPUC determined that the UITC and EDIT amounts were no longer required to be held in their existing accounts. As a result of this determination, the $74 million balance was reflected as a reduction to CL&P's 2006 income tax expense with an increase to CL&P's earnings by the same amount.

CTA and SBC Reconciliation: The CTA allows CL&P to recover stranded costs, such as securitization costs associated with its 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.

Purchased Gas Adjustment: On September 9, 2005, the DPUC issued a draft decision regarding Yankee Gas PGA clause charges for the period of September 1, 2003 through August 31, 2004. The draft decision disallowed approximately $9 million in previously recovered PGA revenues associated with two separate Yankee Gas unbilled sales and revenue adjustments. At the request of Yankee Gas, the DPUC reopened the PGA hearings on September 20, 2005 and requested that Yankee Gas file supplemental information regarding the two adjustments. Yankee Gas complied with this request. The DPUC issued a new decision on April 20, 2006 requiring an audit of Yankee Gas' previously recovered PGA costs and deferred any conclusion on the $9 million of previously recovered revenues until the completion of the audit. In a recent draft decision regarding Yankee Gas PGA charges for the period September 1, 2004 through August 31, 2005, an additional $2 million related to previously recovered revenues was also identified, bringing the total maximum amount at issue with regard to PGA clause charges under audit to $11 million.

The DPUC has hired a consulting firm who has begun an audit of Yankee Gas' previously recovered PGA costs. The company expects that the audit will be completed in the first half of 2007. Management believes the unbilled sales and revenue adjustments and resulting charges to customers through the PGA clause for both periods were appropriate. Based on the facts of the case and the supplemental information provided to the DPUC, management believes the appropriateness of the PGA charges to customers for the time period under review will be approved, and has not reserved for any loss.

New Hampshire:

SCRC Reconciliation and SCRC Rates: On an annual basis, PSNH files with the NHPUC an SCRC reconciliation filing for the preceding calendar year. The NHPUC reviews the filing, including a prudence review of the operations within PSNH‘s generation business. On May 1, 2006, PSNH filed its 2005 SCRC reconciliation with the NHPUC. On October 25, 2006, PSNH, the NHPUC staff and the OCA filed a settlement agreement with the NHPUC which resolved all outstanding issues associated with the 2005 reconciliation. After the NHPUC hearings held in October of 2006, the NHPUC issued its order affirming the settlement agreement. The terms of the settlement agreement had virtually no impact on PSNH's financial statements.

undertaken, primarily as a result of changes in commodity prices and labor costs. NU expects that this project will have a positive impact on NU’s earnings, as state law and PSNH's restructuring settlement agreement provide for the recovery of its generation costs from its customers, including the cost to comply with state environmental regulations.

Massachusetts:

Transition Cost Reconciliation: On October 24, 2006, the Massachusetts Department of Telecommunications and Energy (DTE) issued its decision in WMECO's 2003 and 2004 transition cost reconciliation filing. The DTE decision in this combined docket resolves all outstanding issues through 2004 for transition, retail transmission, standard offer and default service costs/revenues and did not have a significant impact on WMECO's earnings, financial position or cash flows.

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, 2006 and 2005, NU had $26.8 million and $30.7 million, respectively, recorded as environmental reserves. A reconciliation of the activity in these reserves at December 31, 2006 and 2005 is as follows:


	For the Years Ended December 31,
(Millions of Dollars)	2006		2005
Balance at beginning of year	$	30.7	$	38.7
Additions and adjustments		8.3		4.2
Payments and adjustments		(12.2)		(12.2)
Balance at end of year	$	26.8	$	30.7

Of the 51 sites NU has currently included in the environmental reserve, 25 sites are in the remediation or long-term monitoring phase, 19 sites have had some level of site assessments completed and the remaining 7 sites are in the preliminary stages of site assessment.

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, 2006, in addition to the 51 sites, 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.

Manufactured Gas Plant (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, 2006 and 2005, $24.8 million and $25.3 million, respectively, represent amounts for the site assessment and remediation of MGPs. At December 31, 2006 and 2005, the five largest MGP sites comprise approximately 65 percent and 64 percent, respectively, of the total MGP environmental liability.

Of the 51 sites that are included in the company’s liability for environmental costs, for 7 of these sites, the information known and nature of the remediation options at those sites allow for an estimate of the range of losses to be made. These sites primarily relate to MGP sites. At December 31, 2006, $4.5 million of the $26.8 million total liability 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 zero to $19 million as management utilizes the probabilistic model approach to make its estimate of the liability for environmental costs. For the 44 remaining sites for which an estimate is based on the probabilistic model approach, determining an estimated range of loss is not possible at this time.

On January 19, 2005, the DPUC issued a final decision approving the sale of a former MGP site. 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 after-tax). 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. Of the 51 sites, four are 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 separate regulatory mechanism to recover environmental costs from its customers, and changes in WMECO’s environmental reserves also impact WMECO’s earnings. HWP does not have the ability to recover environmental costs in rates, and changes in HWP's environmental reserves impact HWP'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, prior to the sale of their ownership in the Millstone and Seabrook nuclear power stations.

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 Spent Nuclear 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. After the sale of Millstone, CL&P and WMECO remain responsible for their share of the prior period spent nuclear fuel. Until such payment is made, the outstanding balance will continue to accrue interest at the 3-month treasury bill yield rate. At December 31, 2006 and 2005, fees due to the DOE for the disposal of Prior Period Spent Nuclear Fuel are included in long-term debt and were $280.8 million and $268 million, respectively, including interest costs of $198.7 million and $185.7 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 Spent Nuclear Fuel. For further information on this trust, see Note 10, "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 $32.2 million in 2006, $25.7 million in 2005 and $26.8 million in 2004.

Electricity Procurement Contracts: CL&P, PSNH and WMECO have entered into various arrangements that extend through 2024 for the purchase of electricity, including payment obligations resulting from the buydown of electricity purchase contracts. The total cost of purchases and obligations under these arrangements amounted to $331.9 million in 2006, $275.3 million in 2005 and $323.3 million in 2004. These amounts relate to IPP contracts and do not include contractual commitments related to CL&P’s standard service or transitional standard offer service, PSNH’s short-term power supply management or WMECO’s basic and default service. The majority of the contracts expire in 2014.

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 of supplies to meet its actual sales commitments. These contracts extend through 2016. The total cost of Yankee Gas’ procurement portfolio, including these contracts, amounted to $275.1 million in 2006, $321.2 million in 2005 and $250.5 million in 2004.

Wood, Coal and Transportation Contracts: PSNH has entered into various arrangements for the purchase of wood, coal and the transportation services for fuel supply to its electric generating assets in 2007 and 2008. PSNH’s fuel costs, excluding emissions allowances, amounted to approximately $149.1 million in 2006, $193.4 million in 2005 and $183 million in 2004.

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 $1.4 million in 2006, $1.6 million in 2005 and $2 million in 2004. These costs are not recovered from PSNH's retail customers.

Hydro-Quebec: Along with other New England utilities, CL&P, PSNH and WMECO have entered into agreements to support transmission and terminal facilities to import electricity from the Hydro-Quebec system in Canada. CL&P, PSNH and WMECO 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 $20.5 million in 2006, $21.2 million in 2005 and $23.7 million in 2004.

Transmission Business Project Commitments: These amounts represent commitments for various services and materials associated with CL&P's Middletown to Norwalk, Glenbrook Cables and Norwalk to Northport-Long Island, New York projects and other projects.

Yankee Gas LNG Storage Facility: In 2004, Yankee Gas signed a contract for the design and building of its 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 $8 million are not included in the contract signed to build the LNG facility and are not included in the following table of estimated future annual Utility Group costs.

Yankee Companies Billings: 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. The following table of estimated future annual Utility Group costs includes the estimated decommissioning and closure costs for CYAPC, MYAPC and YAEC.

See Note 8E, "Commitments and Contingencies - Deferred Contractual Obligations," to the consolidated financial statements for information regarding the collection of the Yankee Companies' decommissioning costs.

Estimated Future Annual Utility Group Costs: The estimated future annual costs of the Utility Group's significant long-term contractual arrangements at December 31, 2006 are as follows:


(Millions of Dollars)	2007		2008		2009		2010		2011		Thereafter		Totals
VYNPC	$	27.6	$	27.9	$	30.3	$	29.2	$	29.9	$	7.2	$	152.1
Electricity procurement contracts		283.6		241.2		207.1		184.7		180.5		807.8		1,904.9
Natural gas procurement contracts		50.8		38.0		37.5		37.1		34.8		38.3		236.5
Wood, coal and transportation contracts		107.0		66.2		-		-		-		-		173.2
PNGTS pipeline commitments		1.5		2.0		2.0		2.0		2.0		13.9		23.4
Hydro-Quebec		21.0		21.2		21.0		21.0		20.8		188.0		293.0
Transmission business project commitments		474.7		278.2		40.6		0.1		-		-		793.6
Yankee Gas LNG storage facility		5.0		-		-		-		-		-		5.0
Yankee Companies billings		44.0		35.1		28.4		31.7		27.2		105.2		271.6
Totals	$	1,015.2	$	709.8	$	366.9	$	305.8	$	295.2	$	1,160.4	$	3,853.3

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. Most purchase commitments are recorded at their mark-to-market value with the exception of one non-derivative contract which is accounted for on the accrual basis.

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 contractual conditions are met, these payments could be accelerated.

Hess Commitments: On June 1, 2006, Select Energy sold its competitive retail marketing business to Hess. Under the terms of the agreement, Select Energy paid Hess approximately $11.5 million at closing, $12.9 million in December of 2006, and will pay $14.8 million by the end of 2007.

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


(Millions of Dollars)	2007		2008		2009		2010		2011		Thereafter		Totals
Select Energy purchase agreements	$	656.7	$	193.2	$	29.7	$	32.1	$	31.3	$	20.6	$	963.6
Contract assignment agreement		18.3		19.1		-		-		-		-		37.4
Hess commitment		14.8		-		-		-		-		-		14.8
Totals	$	689.8	$	212.3	$	29.7	$	32.1	$	31.3	$	20.6	$	1,015.8

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

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

Deferred Contractual Obligations


	CYAPC		YAEC		MYAPC
CL&P		34.5%		24.5%		12.0%
PSNH		5.0%		7.0%		5.0%
WMECO		9.5%		7.0%		3.0%
Totals		49.0%		38.5%		20.0%

On June 10, 2004, the DPUC and the Office of Consumer Counsel (OCC) filed a petition with the FERC seeking a declaratory order that CYAPC be allowed to recover all decommissioning costs from its wholesale purchasers, including CL&P, PSNH and WMECO, but that such purchasers may not be allowed to recover in their retail rates any costs that the FERC might determine to have been imprudently incurred. The FERC rejected the DPUC's and OCC's petition, whereupon the DPUC filed an appeal of the FERC's decision with the D.C. Circuit Court of Appeals (Court of Appeals).

NRG Energy, Inc. Exposures

Certain subsidiaries of NU, including CL&P and Yankee Gas, entered into transactions with NRG Energy, Inc. (NRG) and certain of its subsidiaries. On May 14, 2003, NRG and certain subsidiaries of NRG filed voluntary bankruptcy petitions, and on December 5, 2003, NRG emerged from bankruptcy. NU's NRG-related exposures as a result of these transactions relate to 1) the refunding of approximately $28 million of congestion charges previously withheld from NRG prior to the implementation of standard market design on March 1, 2003, which is still pending before the court, 2) the recovery of approximately $25.8 million of CL&P's station service billings from NRG, which is currently the subject of an arbitration, and 3) the recovery of, among other claimed damages, approximately $17.5 million of capital costs and expenses incurred by Yankee Gas related to an NRG subsidiary's generating plant construction project that has ceased. While it is unable to determine the ultimate outcome of these issues, management does not expect their resolution will have a material adverse effect on NU's consolidated earnings, financial position or cash flows.

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 related litigation.

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

In a 2005 opinion, a panel of three judges at the Second Circuit held that the shareholders of NU had no right to sue Con Edison for its alleged breach of the parties' Merger Agreement. NU's request for a rehearing was denied in 2006. This ruling left intact the remaining claims between NU and Con Edison for breach of contract, which include NU's claim for recovery of costs and expenses of approximately $32 million and Con Edison's claim for damages. NU opted not to seek review of this ruling by the United States Supreme Court. In April of 2006, NU filed its motion for partial summary judgment on Con Edison's damage claim. NU's motion asserts that NU is entitled to a judgment in its favor with respect to this claim based on the undisputed material facts and applicable law. The matter is fully briefed and awaiting a decision. At this time, NU cannot predict the outcome of this matter or its ultimate effect on NU.

Guarantees and Indemnifications

NU provides credit assurances on behalf of subsidiaries in the form of guarantees and LOCs in the normal course of business. In addition, NU has provided guarantees and various indemnifications on behalf of external parties as a result of the second quarter sales of SESI to Ameresco, Inc. and the retail marketing business to Hess and the fourth quarter sale of the competitive generation business to ECP.

The following table summarizes NU's maximum exposure at December 31, 2006, in accordance with FIN 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others," expiration dates, and fair value of amounts recorded:


Company	Description	Maximum Exposure (in millions)		Expiration Date(s)	Fair Value of Amounts Recorded (in millions)
On behalf of external parties:

SESI	General indemnifications in connection with the sale of SESI including completeness and accuracy of information provided, compliance with laws, and various claims	Not Specified	(1)	None	$ -

	Specific indemnifications in connection with the sale of SESI for estimated costs to complete or modify specific projects	Not Specified	(1)	Through project completion	0.2

	Indemnifications to lenders for payment of shortfalls in the event of early termination of government contracts	$2.8		2017-2018	0.1

	Surety bonds covering certain projects	$89.5		Through project completion	-

Hess (Retail Marketing)	General indemnifications in connection with the sale including compliance with laws, validity of contract information, completeness and accuracy of information provided, absence of default on contracts, and various claims	Not Specified	(1)	None	-

ECP	General indemnifications in connection with the sale of the generating assets of NGC and Mt. Tom including compliance with laws, validity of contract information, completeness and accuracy of information provided, absence of default on contracts, and various claims	Not Specified	(1)	None	-


Company	Description	Maximum Exposure (in millions)		Expiration Date(s)	Fair Value of Amounts Recorded (in millions)
On behalf of subsidiaries:

Utility Group	Surety bonds, primarily for self-insurance	$11.7		None	N/A
	Letters of credit	55.5		2007-2008	N/A

Rocky River Realty Company	Lease payments for real estate	11.8		2024	N/A

NUSCO	Lease payments for fleet of vehicles	8.5		None	N/A

SECI-CT and Boulos	Surety bonds covering ongoing projects	72.0		Through project completion	N/A

NGS	Insurance bonds and lease payment guarantees	2.1		None	N/A

Select Energy	Performance guarantees for retail marketing contracts not yet assigned to Hess	7.2	(2)	None (3)	N/A

	Performance guarantees for wholesale marketing contracts	170.2	(2)	None	N/A

	Letters of credit	12.0		2007	N/A

HWP	Performance and payment guarantee related to coal purchase contract	Not Specified	(4)	2009	N/A

(1)

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

(2)

Maximum exposure is as of December 31, 2006; however, exposures vary with underlying commodity prices and for certain contracts are essentially unlimited.

(3)

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

(4)

There is no specified maximum exposure included in this guarantee agreement. NU has guaranteed the performance of HWP, a subsidiary of NU, under a back-to-back agreement with ECP relating to an HWP coal supply contract. The maximum exposure to loss under very unlikely circumstances is estimated at approximately $70 million. NU would have recourse to ECP for approximately $50 million, of which $2 million is secured by an LOC.

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

In July 2006, under its former SESI guarantee, NU was required to purchase for $10.4 million the contract payments relating to the only guaranteed SESI project that was behind schedule. In 2006, NU recorded losses totaling $1.1 million to reduce the carrying value of the contract payments purchased to the amount expected to be received from refinancing through SESI's completion of the project. The carrying value of these assets is $9.3 million at December 31, 2006 and is included in other deferred debits on the accompanying consolidated balance sheets. NU may record additional losses associated with this transaction, the amount of which will depend on changes in interest rates used to determine SESI's refinancing proceeds, the amount of project cash available to offset NU's costs, and other factors.

In the third quarter of 2006, NU eliminated its former guarantees of SESI's performance under certain government contracts at a cost of $1 million.

Other Litigation and Legal Proceedings

NU and its subsidiaries are involved in other legal, tax and regulatory proceedings regarding matters arising in the ordinary course of business, some of which involve management’s best estimate of probable loss as defined by SFAS No. 5, "Accounting for Contingencies." The company records and discloses losses when these losses are probable and reasonably estimable in accordance with SFAS No. 5 and expenses legal costs related to the defense of loss contingencies as incurred.

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 and Non-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 $59.7 million and $54 million as of December 31, 2006 and 2005, respectively, held for benefit of the SERP and non-SERP were recorded at their fair market values of $65 million and $58.1 million at December 31, 2006 and 2005, respectively. For further information regarding the SERP liabilities and related investments, see Note 6A, "Employee Benefits - Pension Benefits and Postretirement Benefits Other Than Pensions," and Note 10, "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 $53.4 million and $51.1 million for 2006 and 2005, respectively, were recorded at their fair market value of $53.4 million and $50.8 million at December 31, 2006 and 2005, respectively. For further information regarding these investments, see Note 10, "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 quoted market prices 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, 2006
(Millions of Dollars)	Carrying Amount		Fair Value
Preferred stock not subject to mandatory redemption	$	116.2	$	92.4
Long-term debt -
First mortgage bonds		1,240.6		1,268.8
Other long-term debt		1,734.4		1,775.9
Rate reduction bonds		1,177.2		1,235.4


	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

Other long-term debt includes $280.8 million and $268 million of fees and interest due for spent nuclear fuel disposal costs at December 31, 2006 and 2005, 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.

10.

Marketable Securities

The following is a summary of NU’s available-for-sale securities related to NU's SERP and non-SERP assets, WMECO's prior spent nuclear fuel trust assets and NU's investment in Globix, which are recorded at their fair 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)	2006		2005
SERP and non-SERP securities	$	65.0	$	58.1
WMECO prior spent nuclear fuel trust		53.4		50.8
Globix investment		-		3.7
Totals	$	118.4	$	112.6

For 2005, the decline in the value of the Globix investment was determined to be other than temporary in nature and recorded pre-tax charges totaling $6.1 million in other income, net on the accompanying consolidated statements of income/(loss). 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. On April 6, 2006, NU sold its investment in Globix. This sale resulted in net proceeds of approximately $6.7 million and a pre-tax gain of $3.1 million, which was also included in other income, net on the accompanying consolidated statements of income/(loss).

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


	At December 31, 2006
(Millions of Dollars)	Amortized Cost		Pre-Tax Gross Unrealized Gains		Pre-Tax Gross Unrealized Losses		Estimated Fair Value
United States equity securities	$	21.2	$	5.0	$	(0.3)	$	25.9
Non-United States equity securities		7.2		0.7		-		7.9
Fixed income securities		84.7		0.4		(0.5)		84.6
Totals	$	113.1	$	6.1	$	(0.8)	$	118.4


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

At December 31, 2006 and 2005, NU evaluated the securities in an unrealized loss position and has determined that none of the related unrealized losses are deemed to be other-than-temporary in nature. At December 31, 2006 and 2005, the gross unrealized losses and fair value of NU's investments that have been in a continuous unrealized loss position for less than 12 months and 12 months or greater were as follows:


	At December 31, 2006
	Less than 12 Months				12 Months or Greater				Total
(Millions of Dollars)	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	$	1.8	$	(0.1)	$	0.2	$	-	$	2.0	$	(0.1)
Non-United States equity securities		-		-		-		-		-		-
Fixed income securities		23.0		(0.5)		9.1		(0.2)		32.1		(0.7)
Totals	$	24.8	$	(0.6)	$	9.3	$	(0.2)	$	34.1	$	(0.8)


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

For information related to the change in net unrealized holding gains and losses included in accumulated other comprehensive income, see Note 14, "Accumulated Other Comprehensive Income/(Loss)," to the consolidated financial statements.

For the years ended December 31, 2006, 2005, and 2004, 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)
2006	$	5.2	$	(1.3)	$	3.9
2005		1.3		(7.1)		(5.8)
2004		0.9		(0.3)		0.6

For the years ended December 31, 2006 and 2005, net realized losses of $0.3 million and $0.4 million, respectively, relating to the WMECO spent nuclear fuel trust are included in fuel, purchased and net interchange power on the accompanying consolidated statements of income/(loss). There were no realized losses relating to the WMECO spent nuclear fuel trust in 2004. For the years ended December 31, 2006, 2005 and 2004, all other net realized gains/(losses) of $4.2 million, $(5.4) million and $0.6 million, respectively, are included in other income, net on the accompanying consolidated statements of income/(loss).

NU utilizes the specific identification basis method for SERP and non-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 $193.5 million, $137.1 million and $106.2 million for the years ended December 31, 2006, 2005 and 2004, respectively.

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


(Millions of Dollars)		Amortized Cost		Estimated Fair Value
Less than one year	$	33.7	$	33.8
One to five years		23.2		23.2
Six to ten years		7.8		7.7
Greater than ten years		20.1		20.0
Subtotal		84.8		84.7
Equity securities		28.3		33.7
Total	$	113.1	$	118.4

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

11.

Leases

Various NU subsidiaries have 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 $3.3 million in 2006, $3.4 million in 2005 and $3.3 million in 2004. Interest included in capital lease rental payments was $1.9 million in 2006, $1.9 million in 2005 and $2 million in 2004. Capital lease asset amortization was $0.9 million in 2006, $0.8 million in 2005 and $0.7 million in 2004.

Operating lease rental payments charged to expense were $10.9 million in 2006, $15.6 million in 2005 and $16.3 million in 2004. These amounts include $0.7 million, $1.1 million, and $1.1 million included in income from discontinued operations on the accompanying consolidated statements of income/(loss) for the years ended December 31, 2006, 2005 and 2004, respectively. The capitalized portion of operating lease payments was approximately $10 million, $9.4 million and $8.2 million for the years ended December 31, 2006, 2005 and 2004, 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, 2006 are as follows:


(Millions of Dollars)	Capital Leases		Operating Leases
2007	$	2.8	$	31.0
2008		2.4		27.8
2009		2.2		24.8
2010		1.7		21.4
2011		1.7		16.6
Thereafter		15.7		65.3
Future minimum lease payments		26.5	$	186.9
Less amount representing interest		(12.1)
Present value of future minimum lease payments	$	14.4

12.

Long-Term Debt

Long-term debt maturities and cash sinking fund requirements on debt outstanding at December 31, 2006, for the years 2007 through 2011 and thereafter, which include fees and interest due for spent nuclear fuel disposal costs, net unamortized premiums or discounts and other fair value adjustments at December 31, 2006, are as follows (millions of dollars):


Year
2007	$	4.9
2008		154.3
2009		54.3
2010		4.3
2011		4.3
Thereafter		2,472.0
Fees and interest due for spent nuclear fuel disposal costs		280.8
Net unamortized premiums and discounts and other fair value adjustments		(9.6)
Total	$	2,965.3

Essentially all utility plant of CL&P, PSNH and Yankee Gas 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 secured by 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, 2006 and 2005, $407.3 million of the PCRBs were outstanding. PSNH’s obligation to repay each series of PCRBs is secured by bond insurance and by PSNH's 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 had a maturity of 13 months, with such borrowings being classified as long-term debt. The new facility provided a total commitment of $310 million in borrowings and LOCs. This facility was terminated on June 29, 2006.

The weighted average effective interest rate on PSNH's Series A variable-rate pollution control notes was 3.50 percent for 2006 and 2.51 percent for 2005. PSNH's Series B variable-rate pollution control notes were converted to a fixed rate of 4.75 percent in June of 2006. 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.

Long-term debt - first mortgage bonds on the accompanying consolidated statements of capitalization at December 31, 2006 includes $250 million of long-term debt issued in 2006 related to CL&P.

Liabilities 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 8C, "Commitments and Contingencies - Spent Nuclear Fuel Disposal Costs," to the consolidated financial statements.

The change in fair value totaling a negative $6.5 million and $5.2 million at December 31, 2006 and 2005, 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 that 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 liabilities for the change in fair value of the fixed to floating interest rate swap.

13.

Dividend Restrictions

14.

Accumulated Other Comprehensive Income/(Loss)

The accumulated balance for each other comprehensive income/(loss) item is as follows:


(Millions of Dollars, Net of Tax)	December 31, 2005		Current Period Change		December 31, 2006
Qualified cash flow hedging instruments	$	18.2	$	(12.3)	$	5.9
Unrealized gains on securities		2.3		0.7		3.0
Minimum SERP liability (1)		(0.5)		0.5		-
Adjustment to record funded status of pension, SERP and other postretirement plans (SFAS No. 158)		-		(4.4)		(4.4)
Accumulated other comprehensive income/(loss)	$	20.0	$	(15.5)	$	4.5


(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 SERP liability		(0.9)		0.4		(0.5)
Accumulated other comprehensive (loss)/income	$	(1.2)	$	21.2	$	20.0

The changes in the components of other comprehensive income/(loss) are reported net of the following income tax effects:


(Millions of Dollars)	2006		2005		2004
Qualified cash flow hedging instruments	$	6.9	$	(13.4)	$	14.4
Unrealized gains on securities		(0.5)		0.6		(0.7)
Minimum SERP liability		(0.3)		(0.3)		0.1
Adjustment to adopt SFAS No. 158		6.1		-		-
Accumulated other comprehensive income/(loss)	$	12.2	$	(13.1)	$	13.8

(1)

The current period change of $0.5 million related to the minimum SERP liability includes $0.3 million to adjust the additional minimum SERP liability before the adoption of SFAS No. 158 and $0.2 million to reverse the remaining balance as part of the adoption of SFAS No. 158. See Note 6A, "Pension Benefits and Postretirement Benefits Other Than Pensions," for additional information regarding the adoption of SFAS No. 158.

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)	2006		2005
Balance at beginning of year	$	18.2	$	(3.5)
Hedged transactions recognized into earnings		2.3		5.6
Amount reclassified into earnings due to the discontinuation of cash flow hedges		(14.1)		-
Change in fair value of hedged transactions delivered in 2006		(4.5)		11.0
Cash flow transactions entered into for the period		4.0		5.1
Net change associated with the current period hedging transactions		(12.3)		21.7
Total fair value adjustments included in accumulated other comprehensive income	$	5.9	$	18.2

For the year ended December 31 2006, $1.3 million, net of tax, was reclassified from accumulated other comprehensive income in connection with the consummation of the underlying hedged transactions and recognized into earnings in revenues and fuel, purchased, and net interchange power and $1 million was reclassified into earnings related to the amortization of interest rate hedges. This $1 million includes the amortization of the remaining balance of the NGC rate lock which was sold to ECP. In the first quarter of 2006, $14.1 million was reclassified from accumulated other comprehensive income into earnings (specifically included in other operation expense) due to discontinuation of cash flow hedge accounting because the retail marketing contracts hedged beyond June 1, 2006 were no longer probable of physical delivery due to the retail business being sold.

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

At December 31, 2006, it is estimated that a pre-tax $1.6 million included in the accumulated other comprehensive income balance will be reclassified as a decrease to earnings in 2007 related to pension and PBOP expenses and a pre-tax benefit of $0.2 million will be reclassified into earnings in 2007 related to the amortization of interest rate locks.

15.

Earnings Per Share

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 2006, 2005 and 2004, 2,500 options, 1,122,541 options, and 696,994 options, respectively, were excluded from the following table as these options were antidilutive. The weighted average common shares outstanding at December 31, 2006 and 2005 include the impact of the issuance of 23 million common shares on December 12, 2005. The following table sets forth the components of basic and diluted EPS:


(Millions of Dollars, except share information)	2006		2005		2004
Income/(loss) from continuing operations	$	126.2	$	(266.6)	$	69.8
Income from discontinued operations		344.4		14.1		46.8
Income/(loss) before cumulative effect of accounting change		470.6		(252.5)		116.6
Cumulative effect of accounting change, net of tax benefit		-		(1.0)		-
Net income/(loss)	$	470.6	$	(253.5)	$	116.6

Basic common shares outstanding (average)		153,767,527		131,638,953		128,245,860
Dilutive effect		379,142		N/A		150,216
Fully diluted common shares outstanding (average)		154,146,669		131,638,953		128,396,076

Basic EPS:
Income/(loss) from continuing operations	$	0.82	$	(2.03)	$	0.54
Income from discontinued operations		2.24		0.11		0.37
Cumulative effect of accounting change, net of tax benefit		-		(0.01)		-
Net income/(loss)	$	3.06	$	(1.93)	$	0.91

Fully Diluted EPS:
Income/(loss) from continuing operations	$	0.82	$	(2.03)	$	0.54
Income from discontinued operations		2.23		0.11		0.37
Cumulative effect of accounting change, net of tax benefit		-		(0.01)		-
Net income/(loss)	$	3.05	$	(1.93)	$	0.91

Restricted shares are issued and outstanding on their grant date and are included in basic common shares outstanding. These shares are subject to vesting requirements and are excluded from basic shares outstanding if forfeited.

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

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

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

16.

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 in the first quarter of 2006, separate financial information was prepared and used by management for each of the NU Enterprises merchant energy businesses that NU is exiting. Accordingly, separate detailed information is presented for the wholesale and retail marketing and competitive generation businesses for the year ended December 31, 2006. It is not practicable to prepare comparable detailed information for any periods prior to 2006 due to the manner in which the merchant energy business operated prior to 2006. Effective January 1, 2005, the portion of NGS' business that supported 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. Cash flows for total investments in plant included in the segment information below are cash capital expenditures that do not include cost of removal, AFUDC related to equity funds, and the capitalized portion of pension expense or income. Segment information for all periods presented has been reclassified to conform to the current period presentation, except as indicated.

The Utility Group segment, including the regulated electric distribution, generation and transmission businesses, as well as the gas distribution business comprised of Yankee Gas, represents approximately 87 percent, 74 percent, and 70 percent of NU’s total revenues for the years ended December 31, 2006, 2005 and 2004, respectively, and includes the operations of the regulated electric utilities, CL&P, PSNH and WMECO, whose complete consolidated financial statements (net of eliminations) 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: 1) Select Energy, consisting of the wholesale and retail marketing businesses; and 2) NGC, Mt. Tom, and a portion of NGS, collectively referred to as the competitive generation business. The NU Enterprises services and other business segment includes the remainder of NGS, SESI, Woods Electrical - Services, Woods Electrical - Other, SECI-NH, Woods Network, Boulos and SECI-CT, and intercompany eliminations between the energy services businesses and merchant energy businesses. The results of NU Enterprises parent are also included within services and other. Certain of those businesses were sold during 2006 and 2005.

Other in the tables includes the results for Mode 1 Communications, Inc., the results of the non-energy-related subsidiaries of Yankee (Yankee Energy Services Company, Yankee Energy Financial Services Company, and NorConn Properties, Inc.), the non-generation operations of HWP, and the results of NU's parent and service companies. Interest expense included in other primarily relates to the debt of NU Parent. Other includes pre-tax investment write-downs totaling $6.9 million and $13.8 million in 2005 and 2004, respectively.

NU's consolidated statements of income/(loss) for the years ended December 31, 2006, 2005 and 2004 present the operations for NGC, Mt. Tom, SESI, Woods Electrical - Services, SECI-NH and Woods Network as discontinued operations. For further information and information regarding the exit from these businesses, see Note 3, "Assets Held for Sale and Discontinued Operations," to the consolidated financial statements.

Intercompany Transactions: Select Energy served a portion of CL&P’s TSO or standard offer load for 2004. Total Select Energy revenues from CL&P for CL&P’s TSO or standard offer load and for other transactions with CL&P, represented approximately $6.1 million for the year ended December 31, 2006, $53.4 million for the year ended December 31, 2005, and $611.3 million for the year ended December 31, 2004 of total NU Enterprises’ revenues. Total CL&P purchases from Select Energy related to nontraditional standard offer contracts are eliminated in consolidation.

Total Select Energy revenues from transactions with WMECO represented $0.9 million, $36.3 million, and $108.5 million of total NU Enterprises’ revenues for the years ended December 31, 2006, 2005 and 2004, respectively. Total WMECO purchases from Select Energy are eliminated in consolidation.

Select Energy purchases from NGC and Mt. Tom represented $160.7 million, $209.7 million and $195.4 million for the years ended December 31, 2006, 2005 and 2004, respectively. On November 1, 2006, NU completed the sale of its 100 percent ownership in NGC stock and Mt. Tom.

Customer Concentrations: Select Energy revenues related to contracts with NSTAR companies represented $296.7 million and $300.2 million of total NU Enterprises’ revenues for the years ended December 31, 2005 and 2004, respectively. There were no sales to NSTAR for the year ended December 31, 2006. Select Energy also provided basic generation service in the New Jersey and Maryland market. Select Energy revenues related to these contracts represented $404.4 million, $530 million and $334.2 million of total NU Enterprises’ revenues for the years ended December 31, 2006, 2005 and 2004. No other individual customer represented in excess of 10 percent of NU Enterprises’ revenues for the years ended December 31, 2006, 2005, or 2004.

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

NU’s segment information for the years ended December 31, 2006, 2005 and 2004 is as follows (some amounts may not agree between segment schedules due to rounding):


	For the Year Ended December 31, 2006
	Utility Group
	Distribution (1)
(Millions of Dollars)	Electric		Gas		Transmission		NU Enterprises		Other		Eliminations		Total
Operating revenues	$	5,336.0	$	453.9	$	216.0	$	908.5	$	355.0	$	(385.0)	$	6,884.4
Restructuring and impairment charges		-		-		-		(10.3)		-		-		(10.3)
Depreciation and amortization		(387.2)		(22.7)		(29.8)		(0.7)		(18.8)		14.1		(445.1)
Other operating expenses		(4,652.5)		(401.0)		(93.6)		(1,085.2)		(335.9)		363.1		(6,205.1)
Operating income/(loss)		296.3		30.2		92.6		(187.7)		0.3		(7.8)		223.9
Interest expense, net of AFUDC		(160.1)		(16.5)		(22.4)		(26.7)		(37.1)		24.8		(238.0)
Interest income		8.4		-		0.4		5.1		32.8		(28.3)		18.4
Other income/(loss), net		31.9		1.4		6.8		0.1		205.2		(199.4)		46.0
Income tax benefit/(expense)		13.4		(3.2)		(16.4)		83.2		5.0		(0.6)		81.4
Preferred dividends		(4.3)		-		(1.2)		-		-		-		(5.5)
Income/(loss) from continuing operations		185.6		11.9		59.8		(126.0)		206.2		(211.3)		126.2
Income from discontinued operations		-		-		-		337.3		-		7.1		344.4
Net income/(loss)	$	185.6	$	11.9	$	59.8	$	211.3	$	206.2	$	(204.2)	$	470.6
Total assets (2)	$	9,223.3	$	1,212.6	$	-	$	276.8	$	5,100.2	$	(4,509.7)	$	11,303.2
Cash flows for total investments in plant	$	305.8	$	87.6	$	430.9	$	25.8	$	22.1	$	-	$	872.2


	For the Year Ended December 31, 2005
	Utility Group
	Distribution (1)
(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
Restructuring and impairment charges		-		-		-		(44.1)		-		-		(44.1)
Depreciation and amortization		(549.2)		(22.0)		(24.0)		(5.2)		(17.8)		13.7		(604.5)
Other operating expenses		(4,012.8)		(441.7)		(80.7)		(2,549.9)		(355.1)		426.8		(7,013.4)
Operating income/(loss)		274.5		39.6		62.8		(635.6)		(19.9)		14.3		(264.3)
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		41.7		0.6		6.6		0.3		150.6		(152.4)		47.4
Income tax (expense)/benefit		(41.1)		(6.1)		(12.5)		237.4		18.4		(8.3)		187.8
Preferred dividends		(4.2)		-		(1.4)		-		-		-		(5.6)
Income/(loss) from continuing operations		105.0		17.3		41.1		(411.3)		131.2		(149.9)		(266.6)
Income from discontinued operations		-		-		-		14.1		-		-		14.1
Income/(loss) before cumulative effect of accounting change		105.0		17.3		41.1		(397.2)		131.2		(149.9)		(252.5)
Cumulative effect of accounting change, net of tax benefit		-		-		-		(1.0)		-		-		(1.0)
Net income/(loss)	$	105.0	$	17.3	$	41.1	$	(398.2)	$	131.2	$	(149.9)	$	(253.5)
Total assets (2)	$	8,923.3	$	1,195.3	$	-	$	2,424.7	$	4,795.1	$	(4,770.5)	$	12,567.9
Cash flows for total investments in plant	$	400.9	$	74.6	$	247.0	$	23.2	$	29.7	$	-	$	775.4

(1)

Includes PSNH generation activities.

(2)

Information for segmenting total assets between electric distribution and transmission is not available at December 31, 2006 or 2005. On a NU consolidated basis, these distribution and transmission assets are disclosed in the electric distribution columns above.


	For the Year Ended December 31, 2004
	Utility Group
	Distribution (1)
(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		(458.6)		(26.1)		(21.6)		(9.2)		(16.4)		13.7		(518.2)
Other operating expenses		(3,276.8)		(348.3)		(70.6)		(2,793.0)		(283.8)		1,038.1		(5,734.4)
Operating income/(loss)		304.6		33.4		48.5		(92.9)		(10.6)		6.4		289.4
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		24.1		0.2		1.9		(3.2)		84.8		(95.7)		12.1
Income tax (expense)/benefit		(56.8)		(3.0)		(8.9)		44.2		15.3		(12.6)		(21.8)
Preferred dividends		(4.3)		-		(1.3)		-		-		-		(5.6)
Income/(loss) from continuing operations		113.3		14.1		28.2		(61.9)		80.2		(104.1)		69.8
Income from discontinued operations		-		-		-		46.8		-		-		46.8
Net income/(loss)	$	113.3	$	14.1	$	28.2	$	(15.1)	$	80.2	$	(104.1)	$	116.6
Cash flows for total investments in plant	$	408.7	$	59.5	$	172.3	$	17.6	$	13.4	$	-	$	671.5

(1)

Includes PSNH generation activities.

NU Enterprises' segment information for the years ended December 31, 2006, 2005, and 2004 is as follows. Eliminations are included in the services and other columns.


	NU Enterprises – For the Year Ended December 31, 2006
(Millions of Dollars)	Wholesale		Retail		Generation		Total Merchant Energy		Services and Other		Total
Operating revenues	$	20.2	$	583.8	$	258.2	$	862.2	$	46.3	$	908.5
Restructuring and impairment charges		(0.2)		(3.1)		-		(3.3)		(7.0)		(10.3)
Depreciation and amortization		(0.1)		(0.1)		(0.1)		(0.3)		(0.4)		(0.7)
Other operating expenses		(26.2)		(682.2)		(290.6)		(999.0)		(86.2)		(1,085.2)
Operating loss		(6.3)		(101.6)		(32.5)		(140.4)		(47.3)		(187.7)
Interest expense		(10.3)		(7.6)		(8.4)		(26.3)		(0.4)		(26.7)
Interest income		0.8		1.6		1.7		4.1		1.0		5.1
Other (loss)/income, net		(0.4)		(0.1)		0.6		0.1		-		0.1
Income tax benefit		25.2		37.4		6.4		69.0		14.2		83.2
Income/(loss) from continuing operations		9.0		(70.3)		(32.2)		(93.5)		(32.5)		(126.0)
Income/(loss) from discontinued operations		-		-		362.3		362.3		(25.0)		337.3
Net income/(loss)	$	9.0	$	(70.3)	$	330.1	$	268.8	$	(57.5)	$	211.3


	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
Restructuring and impairment charges		(27.1)		(17.0)		(44.1)
Depreciation and amortization		(4.4)		(0.8)		(5.2)
Other operating expenses		(2,450.6)		(99.3)		(2,549.9)
Operating loss		(613.3)		(22.3)		(635.6)
Interest expense		(17.8)		(0.5)		(18.3)
Interest income		3.7		1.2		4.9
Other income, net		0.3		-		0.3
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)


	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		(8.4)		(0.8)		(9.2)
Other operating expenses		(2,680.5)		(112.5)		(2,793.0)
Operating loss		(89.7)		(3.2)		(92.9)
Interest expense		(11.4)		(0.2)		(11.6)
Interest income		1.2		0.4		1.6
Other loss, net		(0.2)		(3.0)		(3.2)
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)


Consolidated Statements of Quarterly Financial Data (Unaudited)

	Quarter Ended (a) (b) (c)
(Thousands of Dollars, except per share information)	March 31,		June 30,		September 30,		December 31,
2006
Operating Revenues	$	2,147,388	$	1,661,060	$	1,592,784	$	1,483,156
Operating Income		7,652		73,312		76,383		66,577
(Loss)/Income from Continuing Operations		(20,675)		14,300		102,652		29,873
Income from Discontinued Operations		10,569		7,942		8,797		317,120
Net (Loss)/Income		(10,106)		22,242		111,449		346,993
Basic (Loss)/Earnings Per Common Share:
(Loss)/Income from Continuing Operations		(0.13)		0.09		0.67		0.19
Income from Discontinued Operations		0.06		0.05		0.05		2.06
Net (Loss)/Income	$	(0.07)	$	0.14	$	0.72	$	2.25
Fully Diluted (Loss)/Earnings Per Common Share:
(Loss)/Income from Continuing Operations		(0.13)		0.09		0.67		0.19
Income from Discontinued Operations		0.06		0.05		0.05		2.05
Net (Loss)/Income	$	(0.07)	$	0.14	$	0.72	$	2.24


2005
Operating Revenues	$	2,232,964	$	1,531,613	$	1,754,942	$	1,878,224
Operating Loss		(129,077)		(16,295)		(86,954)		(31,953)
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 Per Common Share:
Loss from Continued Operations	$	(0.86)	$	(0.30)	$	(0.77)	$	(0.11)
(Loss)/Income from Discontinued Operations		(0.03)		0.09		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)

(a)

The summation of quarterly earnings per share data may not equal annual data due to rounding.

(b)

Operating revenue amounts totaling $9.5 million and $1.3 million for the quarters ended June 30, 2006 and September 30, 2006, respectively, were reclassified to operating expenses as a result of the change in classification of certain revenues and associated expenses from a gross presentation to a net presentation.

(c)

Quarterly operating income/(loss) amounts differ from those previously reported as a result of the change in classification of certain amounts previously presented in other income, net, that have been reclassified to operating expenses. These differences are summarized as follows (thousands of dollars):


Quarter Ended	2006		2005
March 31,	$	215	$	(2,840)
June 30,		(1,945)		(204)
September 30,		(867)		(1,282)

Selected Consolidated Financial Data (Unaudited)


(Thousands of Dollars, except percentages and share information)	2006			2005			2004			2003			2002
Balance Sheet Data:
Property, Plant and Equipment, Net	$	6,242,186		$	6,417,230		$	5,864,161		$	5,429,916		$	5,049,369
Total Assets		11,303,236			12,567,875			11,638,396			11,216,487			10,764,880
Total Capitalization (a)		5,879,691			5,595,405			5,293,644			4,926,587			4,670,771
Obligations Under Capital Leases (a)		14,425			13,987			14,806			15,938			16,803
Income Data:
Operating Revenues	$	6,884,388		$	7,397,743		$	6,542,038		$	5,943,358		$	5,159,552
Income/(Loss) from Continuing Operations		126,150			(266,576)			69,776			77,266			116, 645
Income from Discontinued Operations		344,428			14,093			46,812			43,886			35,464
Income/(Loss) Before Cumulative Effects of Accounting Changes, Net of Tax Benefits		470,578			(252,483)			116,588			121,152			152,109
Cumulative Effects of Accounting Changes, Net of Tax Benefits		-			(1,005)			-			(4,741)			-
Net Income/(Loss)	$	470,578		$	(253,488)		$	116,588		$	116,411		$	152,109
Common Share Data:
Basic Earnings/(Loss) Per Common Share:
Income/(Loss) from Continuing Operations	$	0.82		$	(2.03)		$	0.54		$	0.61		$	0.90
Income from Discontinued Operations		2.24			0.11			0.37			0.34			0.28
Cumulative Effects of Accounting Changes, Net of Tax Benefits		-			(0.01)			-			(0.04)			-
Net Income/(Loss)	$	3.06		$	(1.93)		$	0.91		$	0.91		$	1.18
Fully Diluted Earnings/(Loss) Per Common Share:
Income/(Loss) from Continuing Operations	$	0.82		$	(2.03)		$	0.54		$	0.61		$	0.90
Income from Discontinued Operations		2.23			0.11			0.37			0.34			0.28
Cumulative Effects of Accounting Changes, Net of Tax Benefits		-			(0.01)			-			(0.04)			-
Net Income/(Loss)	$	3.05		$	(1.93)		$	0.91		$	0.91		$	1.18
Basic Common Shares Outstanding (Average)		153,767,527			131,638,953			128,245,860			127,114,743			129,150,549
Fully Diluted Common Shares Outstanding (Average)		154,146,669			131,638,953			128,396,076			127,240,724			129,341,360
Dividends Per Share	$	0.73		$	0.68		$	0.63		$	0.58		$	0.53
Market Price - Closing (high) (b)	$	28.81		$	21.79		$	20.10		$	20.17		$	20.57
Market Price - Closing (low) (b)	$	19.24		$	17.61		$	17.30		$	13.38		$	13.20
Market Price - Closing (end of year) (b)	$	28.16		$	19.69		$	18.85		$	20.17		$	15.17
Book Value Per Share (end of year)	$	18.14		$	15.85		$	17.80		$	17.73		$	17.33
Tangible Book Value Per Share (end of year)	$	16.28		$	13.98		$	15.17		$	15.05		$	14.62
Rate of Return Earned on Average Common Equity (%)		18.0			(10.7)			5.1			5.2			7.0
Market-to-Book Ratio (end of year)		1.6			1.2			1.1			1.1			0.9
Capitalization:
Common Shareholders’ Equity		48	%		43	%		44	%		46	%		47	%
Preferred Stock (a) (c)		2			2			2			2			3
Long-Term Debt (a)		50			55			54			52			50
		100	%		100	%		100	%		100	%		100	%

(a)

Includes portions due within one year.

(b)

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

(c)

Excludes $100 million of Monthly Income Preferred Securities.


Consolidated Sales Statistics (Unaudited)

	2006			2005			2004			2003			2002
Revenues: (Thousands)
Utility Group:
Residential	$	2,409,414		$	2,080,395		$	1,707,434		$	1,669,199		$	1,512,397
Commercial		1,977,444			1,727,278			1,429,608			1,411,881			1,298,939
Industrial		589,742			577,834			513,999			514,076			485,591
Wholesale		388,635			411,361			344,254			405,120			567,608
Streetlighting and Railroads		52,853			47,769			41,976			44,977			43,679
Miscellaneous and eliminations		133,925			159,402			143,431			(61,564)			(84,513)
Total Electric		5,552,013			5,004,039			4,180,702			3,983,689			3,823,701
Total Gas		453,894			503,303			407,812			361,470			281,206
Total - Utility Group	$	6,005,907		$	5,507,342		$	4,588,514		$	4,345,159		$	4,104,907
NU Enterprises:
Retail	$	583,829		$	1,212,176		$	857,355		$	660,145		$	508,734
Wholesale		20,163			644,541			1,722,603			1,684,448			1,108,370
Generation		258,178			210,833			196,191			185,493			170,143
Services		46,588			153,844			178,854			143,403			220,638
Miscellaneous and eliminations		(243)			(257,750)			(245,745)			(223,440)			(207,062)
Total - NU Enterprises	$	908,515		$	1,963,644		$	2,709,258		$	2,450,049		$	1,800,823
Other miscellaneous and eliminations		(30,034)			(73,243)			(755,734)			(851,694)			(668,730)
Total	$	6,884,388		$	7,397,743		$	6,542,038		$	5,943,514		$	5,237,000

Utility Group Sales: (KWH - Millions)
Residential		14,652			15,518			14,866			14,824			13,923
Commercial		14,886			15,234			14,710			14,471			14,103
Industrial		5,750			6,023			6,274			6,223			6,265
Wholesale		8,777			4,856			5,787			6,813			15,915
Streetlighting and Railroads		332			348			348			348			344
Total		44,397			41,979			41,985			42,679			50,550

Utility Group Customers: (Average)
Residential		1,686,169			1,674,563			1,659,419			1,631,582			1,614,239
Commercial		188,281			195,844			194,233			186,792			183,577
Industrial		7,406			7,638			7,752			7,644			7,763
Wholesale		3,873			3,912			3,930			3,858			3,949
Total Electric		1,885,729			1,881,957			1,865,334			1,829,876			1,809,528
Gas		199,377			196,870			194,212			192,816			190,855
Total		2,085,106			2,078,827			2,059,546			2,022,692			2,000,383

Utility Group - Average Annual Use Per Residential Customer (KWH)		8,689			9,267			8,960			9,087			8,611
Utility Group - Average Annual Bill Per Residential Customer	$	1,428.91		$	1,242.38		$	1,028.97		$	1,024.20		$	934.90

Utility Group - Average Revenue Per KWH:
Residential		16.44	¢		13.41	¢		11.48	¢		11.27	¢		10.86	¢
Commercial		13.26			11.34			9.70			9.74			9.18
Industrial		10.26			9.59			8.19			8.26			7.75

100