The Connecticut Light and Power Company 10K 2004 Annual report | CNLTP Filing

Management’s Discussion and Analysis

Financial Condition and Business Analysis

Executive Summary

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

Results and Outlook:

Northeast Utilities (NU or the company) reported earnings of $116.6 million in 2004 compared with earnings of $116.4 million in 2003 and $152.1 million in 2002.

After the payment of preferred dividends, earnings at the Utility Group increased by $23.1 million to $155.6 million, or $1.21 per share, in 2004 compared with $132.5 million, or $1.04 per share, in 2003.

Included in 2004 earnings is an after-tax loss of $48.3 million associated with mark-to-market accounting for certain natural gas positions established to mitigate the risk of electricity purchased in anticipation of winning certain levels of wholesale electric load in New England. Results in 2004 also include after-tax investment write-downs totaling $8.8 million, primarily associated with NU’s investments in a fuel cell development company and a telecommunications company.

Results in 2003 included a $36.9 million after-tax loss associated with the implementation of Standard Market Design (SMD) in Connecticut and a negative cumulative effect of an accounting change of $4.7 million from the adoption of Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46, "Consolidation of Variable Interest Entities."

On March 9, 2005, NU completed its previously announced comprehensive review of its competitive energy businesses and decided that NU Enterprises will exit the wholesale marketing business. NU also concluded that NU Enterprises' energy services businesses are not central to NU's long-term strategy and do not meet the company's expectations of profitability. As a result, the company will explore ways to divest those businesses in a manner that maximizes their value. NU will retain its competitive generation and retail energy marketing businesses, because it believes that the generation assets and retail business are competitively positioned to create significant opportunities for those businesses over the next several years.

The Utility Group estimates that it will earn between $1.22 per share and $1.30 per share in 2005. Parent and other costs, primarily related to interest expense, are estimated to total between $0.08 per share and $0.13 per share in 2005. Because of the variety of methods the company could use to implement its decisions concerning the wholesale marketing and energy services businesses, NU will not provide a 2005 earnings range for its NU Enterprises businesses or for NU consolidated.

Regulatory Items:

NU resolved a number of outstanding regulatory issues, providing the company with more ratemaking certainty than it has had in a number of years. Among the most important items were:

Transmission:

On August 19, 2004, a Connecticut Superior Court dismissed the City of Norwalk’s appeal of the Connecticut Siting Council’s (CSC) approval of a 345 kilovolt (kV) transmission line between Bethel, Connecticut and Norwalk, Connecticut.

On September 16, 2004, the Federal Energy Regulatory Commission (FERC) approved a settlement agreement with the states of Connecticut, New Hampshire and Massachusetts that allowed the transmission business to implement a formula rate with an 11.0 percent return on equity (ROE).

CL&P:

On June 28, 2004, the FERC approved a settlement agreement to resolve the dispute over the implementation of SMD in Connecticut. Under the settlement, The Connecticut Light and Power Company (CL&P) returned to its customers and suppliers, including affiliate Select Energy, Inc. (Select Energy), approximately $158 million of revenues collected from customers in 2003 and early 2004.

The Connecticut Department of Public Utility Control (DPUC) issued a final decision on August 4, 2004 on CL&P's petition for reconsideration of the DPUC's December 2003 rate order. The decision had a positive earnings impact of $6.9 million in 2004.

On August 1, 2003, CL&P filed with the DPUC to establish transitional standard offer (TSO) rates equal to December 31, 1996 total rate levels. On December 19, 2003, the DPUC issued a final decision setting the average TSO rate at $0.1076 per kilowatt-hour (kWh) effective January 1, 2004.

As a result of higher supply charges, higher federally mandated congestion charges (FMCC) and a $25.1 million distribution rate increase approved by the DPUC in CL&P's rate case, on November 24, 2004, CL&P requested the DPUC to increase its TSO rate for 2005. On December 22, 2004, the DPUC approved a 10.4 percent rate increase effective January 1, 2005 and allowed for the recovery of the remainder of the requested increase through existing and new refunds and overrecoveries.

On February 1, 2005, CL&P filed an application with the DPUC to obtain approval to defer for future recovery in its retail transmission rate the increased transmission costs that CL&P is incurring as of February 1, 2005.

On February 1, 2005, CL&P filed for approval for a 1.6 percent increase to TSO rates ($29.2 million) to collect additional FMCC from customers effective May 1, 2005. The increase is necessary to collect costs related to an additional Reliability Must Run (RMR) contract related to two generating plants located in southwest Connecticut. The RMR contract has preliminary approval for billing from the FERC and is subject to a future review by the FERC prior to final approval.

Yankee Gas:

On September 3, 2004, the DPUC approved the application of Yankee Gas Services Company (Yankee Gas) to construct a liquefied natural gas (LNG) storage facility in Waterbury, Connecticut capable of storing 1.2 billion cubic feet of natural gas with an estimated cost of $108 million.

The DPUC approved the Yankee Gas rate case settlement agreement on December 8, 2004. The approval resulted in a $14 million increase in rates beginning January 1, 2005.

PSNH:

In October 2004, Public Service Company of New Hampshire (PSNH) received the approvals necessary to begin construction related to the conversion of one of three 50-megawatt units at the coal-fired Schiller Station to burn wood.

On September 2, 2004, the New Hampshire Public Utilities Commission (NHPUC) approved the negotiated settlement of the PSNH rate case that was filed in 2003. The settlement agreement resulted in an annualized delivery rate increase of $3.5 million beginning October 1, 2004 and approval of another rate increase of $10 million on June 1, 2005.

On September 24, 2004, PSNH filed a petition with the NHPUC requesting a change in the transition energy service rate for residential and small commercial customers and the default energy service rate (TS/DS) for large commercial and industrial customers for the period February 1, 2005 through January 31, 2006. PSNH files for updated TS/DS rates periodically to ensure timely recovery of its costs. The NHPUC issued its order approving PSNH's proposed TS/DS rate of $0.0649 per kWh on January 28, 2005.

WMECO:

On December 29, 2004, the Massachusetts Department of Telecommunications and Energy (DTE) approved a settlement agreement to increase Western Massachusetts Electric Company's (WMECO) electricity distribution rates by $6 million annually effective January 1, 2005 and by an additional $3 million annually beginning January 1, 2006. The settlement also reduced WMECO’s transition charge by approximately $13 million annually.

Liquidity:

During 2004, the Utility Group issued a total of $505 million of fixed-rate bonds and notes with maturities ranging from 10 years to 30 years. The debt was issued primarily to fund capital expenditure programs, repay higher cost debt and fund prior spent nuclear fuel obligations.

NU’s capital expenditures totaled $643.8 million in 2004, compared with $563.6 million in 2003 and $510.5 million in 2002. The increase resulted from increased spending on new electric transmission projects. NU projects capital expenditures of approximately $740 million in 2005.

NU’s net cash flows from operations totaled $517.1 million in 2004, compared with $593.4 million in 2003 and $615.8 million in 2002.

Overview

Consolidated: NU reported 2004 earnings of $116.6 million, or $0.91 per share, compared with earnings of $116.4 million, or $0.91 per share, in 2003 and $152.1 million or $1.18 per share in 2002. All earnings per share amounts are reported on a fully diluted basis.

Earnings in 2004 of $116.6 million, or $0.91 per share, include an after-tax loss of $48.3 million, or $0.38 per share, associated with mark-to-market accounting for certain natural gas positions established to mitigate the risk of electricity purchased in anticipation of winning certain levels of wholesale electric load in New England. Also included in 2004 earnings are after-tax investment write-downs of approximately $8.8 million ($13.8 million on a pre-tax basis), or $0.07 per share, primarily related to NU’s investments in a fuel cell development company and a telecommunications company. NU's 2004 earnings were essentially unchanged from 2003. Utility Group earnings increased by $23.1 million due to increased rates and other positive regulatory developments. That increase was offset by increased losses at NU Enterprises and higher parent and other costs. Increased NU Enterprises losses were due primarily to a 2004 negative mark-to-market loss on certain natural gas contracts. Higher parent and other costs were due to higher investment write-downs in 2004.

NU's 2003 earnings of $116.4 million or $0.91 per share include a charge of $36.9 million, or $0.29 per share, associated with a loss recorded for the settlement of a wholesale power contract dispute between CL&P and its three 2003 standard offer power suppliers, including an NU subsidiary, Select Energy. Also included in 2003 earnings was a negative $4.7 million after-tax cumulative effect of an accounting change as a result of the

adoption of FIN 46. 2003 earnings decreased by $35.7 million compared to 2002. Earnings at the Utility Group decreased significantly in 2003 due to lower pension income and the absence of earnings related to the Seabrook nuclear unit (Seabrook). These decreases were partially offset by lower Utility Group controllable operation and maintenance costs. NU’s 2003 results benefited from lower corporate-wide interest costs and improved performance at NU Enterprises from improved margins on Select Energy’s energy supply contracts, higher volumes, improved operation of NU Enterprises’ generating facilities, and the absence of natural gas trading losses that occurred in the first half of 2002.

A summary of NU's earnings/(losses) by major business line for 2004, 2003 and 2002 is as follows:

	For the Years Ended December 31,
(Millions of Dollars)	2004	2003	2002
Utility Group	$155.6	$132.5	$198.3
NU Enterprises	(15.1)	(3.4)	(53.2)
Parent and Other	(23.9)	(12.7)	7.0
Net Income	$116.6	$116.4	$152.1

NU’s revenues during 2004 increased to $6.7 billion from $6.1 billion in 2003 and from $5.2 billion in 2002. The increase in 2004 revenues was due to increased revenues from NU Enterprises totaling $0.4 billion primarily as a result of higher merchant energy retail sales volumes and higher prices. The remainder of the increase in 2004 revenues related to higher Utility Group transmission and distribution revenues as a result of higher rates and higher FMCC revenues.

The increase in 2003 revenues was due to increased revenues from NU Enterprises totaling $0.6 billion as a result of higher wholesale and retail sales volumes and higher prices. The remainder of the increase in 2003 revenues was due to increases in electric sales at the Utility Group in 2003 as compared to 2002.

Utility Group: The Utility Group is comprised of CL&P, PSNH, WMECO, and Yankee Gas, including their transmission, distribution and generation businesses. After the payment of preferred dividends, earnings at the Utility Group increased by $23.1 million to $155.6 million, or $1.21 per share, in 2004 compared with $132.5 million, or $1.04 per share, in 2003. Earnings at the Utility Group were $198.3 million in 2002. The increase in Utility Group earnings during 2004 was primarily due to increases in CL&P’s retail rates. CL&P's earnings increased in 2004 compared to 2003 by approximately $12 million due to amounts disallowed in the December 2003 rate case decision and subsequently allowed in the reconsideration decision. Those improvements were partially offset by lower pension income and higher interest and depreciation expense. A su mmary of Utility Group earnings by company for 2004, 2003 and 2002 is as follows:

	For the Years Ended December 31,
(Millions of Dollars)	2004	2003	2002
CL&P *	$ 82.5	$ 63.4	$ 80.1
PSNH	46.6	45.6	62.9
WMECO	12.4	16.2	37.7
Yankee Gas	14.1	7.3	17.6
Net Income	$155.6	$132.5	$198.3

*After preferred dividends.

CL&P earned $82.5 million in 2004 after preferred dividends of $5.6 million, compared with $63.4 million in 2003 after preferred dividends of $5.6 million. CL&P’s improved earnings resulted primarily from a retail rate increase that took effect January 1, 2004. These higher retail rates were offset by higher operating expenses, lower pension income and a higher effective tax rate. CL&P also benefited from the final decision on the reconsideration of CL&P’s rate case, which had a positive after-tax impact of $6.9 million in 2004. In 2003, after-tax write-offs of approximately $5 million were recorded based on the DPUC's December 2003 rate case order. The higher effective tax rate was due to higher reversal of prior flow-through depreciation and other adjustments to tax expense totaling a negative $3.2 million recorded in the third quarter of 2004 as opposed to a posi tive $5.5 million recorded in 2003.

PSNH earned $46.6 million in 2004, compared with $45.6 million in 2003. PSNH earnings were higher primarily due to a lower effective tax rate and an increase in retail sales of 3.1 percent. The lower effective tax rate and increase in sales were largely offset by higher operating expenses and higher pension expense. The lower effective tax rate was due to other adjustments to tax expense totaling a positive $5.4 million recorded in the third quarter of 2004.

WMECO earned $12.4 million in 2004, compared with $16.2 million in 2003. WMECO's 2004 earnings were lower due to lower pension income and higher interest and depreciation expense, offset by a 1.6 percent increase in retail sales.

Yankee Gas earned $14.1 million in 2004, compared with $7.3 million in 2003. Yankee Gas' 2004 results benefited from the absence of a negative $6.2 million adjustment to the estimate of unbilled revenues in 2003 and a lower effective tax rate. The lower effective tax rate was due to other adjustments to tax expense totaling a positive $4.3 million recorded in the second and third quarters of 2004.

Included in Utility Group company earnings are the results of the transmission business. Transmission business earnings were $29.5 million in 2004 as compared to $28.2 million in 2003. Transmission business earnings in 2004 are higher than 2003 primarily due to higher revenues resulting from the implementation of a FERC approved formula rate resulting in increased rates and $123 million of transmission projects that were placed in service. This forward-looking formula rate allows NU to place capital investments in rates immediately upon being placed in service. The formula rate took effect on October 28, 2003.

NU Enterprises: NU Enterprises, Inc. is the parent company of Northeast Generation Company (NGC), Northeast Generation Services Company (NGS), Select Energy, Select Energy Services, Inc. (SESI) and their respective subsidiaries, and Woods Network Services, Inc. (Woods Network), all of which are collectively referred to as "NU Enterprises." The generation operations of Holyoke Water Power Company (HWP) are also included in the results of NU Enterprises. The companies included in the NU Enterprises segment are grouped into two business segments: the merchant energy segment and the energy services business segment. The merchant energy business segment is comprised of Select Energy’s wholesale marketing business, Select Energy's retail marketing business, and approximately 1,296 megawatts (MW) of pumped storage and hydroelectric generation assets owned by NGC and 147 MW of coal-fired generation assets owned by HWP. The energy services business consists of the operations of NGS, SESI and Woods Network.

NU Enterprises had a loss of $15.1 million in 2004, or $0.12 per share, compared with a loss of $3.4 million, or $0.03 per share in 2003, and a loss of $53.2 million, or $0.41 per share, in 2002.

NU Enterprises 2004 loss includes an after-tax loss of $48.3 million, or $0.38 per share, associated with mark-to-market accounting for certain natural gas positions established to mitigate the risk of electricity purchased in anticipation of winning certain levels of wholesale electric load in New England.

A summary of NU Enterprises’ earnings/(losses) by business for 2004, 2003 and 2002 is as follows:

	For the Years Ended December 31,
(Millions of Dollars)	2004	2003	2002
Merchant Energy	$(12.1)	$ (5.5)	$(52.4)
Energy Services, Parent and Other	(3.0)	2.1	(0.8)
Net Loss	$(15.1)	$(3.4)	$(53.2)

The mark-to-market loss on natural gas contracts was the primary reason for increased NU Enterprises losses in 2004. This loss was in the wholesale marketing portion of the merchant energy segment. However, merchant energy earnings benefited from improved results in the retail marketing portion of the merchant energy segment from increased commercial and industrial electric and natural gas sales. Retail marketing earned $4.9 million in 2004, compared to a loss of $1.8 million in 2003. Energy services earnings decreased by $4.9 million in 2004 from 2003 due primarily to losses on a construction contract.

Parent and Other: Losses unrelated to the Utility Group and NU Enterprises totaled $23.9 million in 2004, compared with a loss of $12.7 million in 2003 and income of $7 million in 2002. The higher losses in 2004 were mostly attributable to investment write-downs related to NU’s investments in a fuel cell development company and a telecommunications company and due to higher interest expenses. The higher losses in 2003 were mostly attributable to the negative $4.7 million cumulative effect of an accounting change associated with the adoption of FIN 46 recorded in 2003 and to Seabrook related gains recorded in 2002.

Future Outlook

Utility Group: The Utility Group estimates that it will earn between $1.22 per share and $1.30 per share in 2005. That range reflects earnings of between $0.96 per share and $1.00 per share in the regulated distribution and generation business and between $0.26 per share and $0.30 per share in the transmission business.

NU Enterprises: The earnings of NU Enterprises will be impacted by many factors, including the amount of asset impairments or losses on disposals that could result from the decision to exit the wholesale marketing business and explore ways to divest the energy services segment, the mark-to-market loss that may result from the application of mark-to-market accounting to certain wholesale marketing contracts until those contracts are sold or until the commodities are delivered, and other closure costs. Accordingly, NU will not be providing NU Enterprises or NU consolidated 2005 earnings guidance.

Parent and Other:Parent and other costs, primarily related to interest expense, are estimated to total between $0.08 per share and $0.13 per share in 2005.

Strategic Overview

The company has identified significant investment requirements in the Utility Group transmission and distribution businesses and expects to invest more than $3.7 billion in regulated electric and natural gas infrastructure from 2005 through 2009.

Based on current projections, NU expects that the need to invest heavily in regulated infrastructure to meet reliability requirements and customer growth will cause NU’s Utility Group distribution and generation rate base to rise from $2.5 billion in 2004 to nearly $3.9 billion by the end of 2009. Based on currently projected expenditures and capital project completion dates, NU expects that the same factors will increase NU’s Utility Group transmission rate base from approximately $460 million in 2004 to approximately $1.7 billion by the end of 2009.

NU Enterprises Business Review: On March 9, 2005, NU completed its previously announced comprehensive review of each of NU Enterprises' businesses, in which a full range of alternative strategies was considered. That review considered:

The impact of the increase in competition in the New England wholesale energy markets over the last six months of 2004, which has affected Select Energy's profitability by reducing the number of bids won and by reducing the margins on the bids that are won;

The potential growth of the retail business, which had a significant improvement in earnings in 2004 and which serves a market that NU believes to be growing;

The competitiveness and opportunities for increased value for the 1,443 MW of generation currently owned by NU Enterprises;

The strategic fit of the energy services businesses; and

The impact of any significant changes on NU as a whole.

As a result of the comprehensive review, NU has decided that NU Enterprises will exit the wholesale marketing business. NU also concluded that NU Enterprises' energy services businesses are not central to NU's long-term strategy and do not meet the company's expectations of profitability. As a result, the company will explore ways to divest those businesses in a manner that maximizes their value. Those businesses include electrical, mechanical, telecommunications, commercial plumbing, and performance contracting companies. NU will retain its competitive generation and retail energy marketing businesses, because it believes that the generation assets and retail business are competitively positioned to create significant opportunities for those businesses over the next several years.

NU has concluded that the wholesale merchant energy sector in the power pools between Maine and Maryland is becoming increasingly competitive and that NU Enterprises' wholesale marketing business will be unable to attain the profit margins necessary to generate acceptable returns and cash flows. As a result, NU Enterprises will explore a number of alternatives for exiting the wholesale marketing business, including selling the wholesale franchise, selling existing contracts, restructuring longer term contracts, and allowing shorter-term contracts to expire without being renewed. In the interim, NU Enterprises will only bid on new full requirements wholesale contracts to improve the value of its book of business by reducing existing electric positions.

NU Enterprises' marketing subsidiary, Select Energy, has built a very strong retail energy marketing franchise in the Northeast and Middle Atlantic states, and the company expects to build on that market presence. Additionally, the number of commercial and industrial customers buying their electricity and natural gas from competitive suppliers is continuing to rise. Select Energy's retail marketing revenues in 2004 were approximately $850 million on sales of approximately 10 million megawatt-hours of electricity and 40 billion cubic feet of natural gas. Select Energy's retail marketing business serves approximately 30,000 commercial and industrial locations in the New England, New York and PJM power pools. Select Energy's retail marketing business projects revenues to grow to approximately $1 billion in 2005 because of a continued expansion of the retail market and its high customer retention rate of a pproximately 85 percent.

NU will retain its 1,443 MW of competitive generating assets because it expects that their value could increase significantly in the coming years. The competitive generating assets, which include pumped storage, hydroelectric, and coal-fired units, are contained within NGC and HWP subsidiaries. NU Enterprises also will retain its NGS subsidiary, which operates the NGC and HWP plants.

NU Enterprises accounted for approximately $2.1 billion of NU's revenue in 2004, excluding sales to affiliated regulated companies. The wholesale marketing business accounted for approximately $1 billion of that revenue, and NU Enterprises' energy services businesses accounted for approximately $275 million. The energy services businesses include E.S. Boulos Company and Woods Electrical Co., Inc., both electrical contractors; Woods Network, a telecommunications contracting firm; Select Energy Contracting, Inc., an electrical, mechanical, and plumbing contractor; and SESI, a performance contracting subsidiary that specializes in upgrading the energy efficiency of large governmental and institutional facilities.

NU expects to record a charge in the first quarter of 2005 associated with the wholesale marketing and energy services business. The level of that charge will depend on a number of factors, including how the disposition of those businesses is accomplished.

The company expects that implementation of its decisions will have an impact on employment levels in those businesses but that the actual impact is not known at this time because the disposition process has just begun. It is the company's goal to minimize layoffs by using, to the extent possible, open positions within NU or by a possible sale of both the wholesale marketing franchise and the energy services businesses in which the buyers may offer positions to existing employees.

Liquidity

Consolidated: NU continues to maintain an adequate level of liquidity. At December 31, 2004, NU had $47 million of cash and cash equivalents on hand compared with $43.4 million at December 31, 2003. As discussed in Note 16, "Restatement of Previously Issued Financial Statements," the December 31, 2003 amount of cash and cash equivalents has been restated.

Cash flows from operations decreased by $76.3 million from $593.4 million in 2003 to $517.1 million in 2004. Changes in current assets and liabilities were consistent from year to year and were decreases of approximately $91 million in 2003 and approximately $86 million in 2004. Increases in cash flows related to deferred taxes were offset by decreases related to regulatory refunds.

The decrease in year over year cash flows from regulatory (refunds)/overrecoveries is primarily due to lower Competitive Transition Assessment (CTA) and Generation Service Charge (GSC) collections in 2004 as CL&P refunds amounts to its ratepayers for past over collections or uses those amounts to recover current costs. These refunds are also the primary reason for the positive change in year over year deferred income taxes, which has increased operating cash flows as refunded amounts were currently deducted for tax purposes. Lower taxes paid also benefited cash flows from operations in 2004 due to bonus tax depreciation on newly completed plant assets.

NU paid common dividends of $80.2 million in 2004, compared with $73.1 million in 2003 and $67.8 million in 2002. The increase reflects increases in quarterly common dividends of $0.0125 per share declared in the third quarters of 2002, 2003, and 2004. Management expects to continue to recommend that the NU Board of Trustees increase the common dividend on an annual basis, subject to the company’s future earnings and cash requirements. On January 31, 2005, the Board of Trustees approved a quarterly dividend of $0.1625 per share, payable March 31, 2005 to shareholders of record as of March 1, 2005.

Capital expenditures described herein are cash capital expenditures and exclude cost of removal, AFUDC, and the capitalized portion of pension income. NU’s capital expenditures, totaled $643.8 million in 2004, compared with $563.6 million in 2003 and $510.5 million in 2002. NU's 2004 capital expenditures included $370.8 million by CL&P, $143.6 million by PSNH, $56.6 million by Yankee Gas, $38.6 million by WMECO, and $34.2 million by other NU subsidiaries, including $17.6 million by NU Enterprises. The increase in capital expenditures was primarily the result of higher transmission capital expenditures, which totaled $163.9 million in 2004, compared with $96.3 million in 2003 and $57.9 million in 2002. The company projects capital expenditures of approximately $3.7 billion over the five-year period from 2005 through 2009, including approximately $740 million in 2005. Capital spending proj ections are highly dependent on regulatory approval of major projects, particularly transmission investments.

Management projects that NU will need in excess of $4 billion from 2005 through 2009 to meet its capital expenditure requirements, common and preferred dividends, and other cash requirements. NU expects to fund approximately half of this need through operating cash flows with the remainder expected to be funded through external financings and the sale of common shares. Management believes that the majority of the external financing will be debt but that NU will need to raise several hundred million dollars through the sale of its common shares. The timing and amount of those equity issuances will depend greatly on the timing of major transmission investments and the level of dividends and equity capital that will be paid to NU by its subsidiaries. Over the next five years, management expects the Utility Group to continue to issue debt annually while debt levels at NU parent and NGC continue to decline.

To maintain a capital structure that includes approximately 55 percent of total debt at each of the Utility Group companies, NU continues to infuse common equity. NU parent made a total of $94.5 million of common equity contributions to the Utility Group companies in 2004, including $88 million to CL&P. At December 31, 2004, NU parent had loaned on a temporary basis approximately $110 million to other NU companies, most of which was loaned to the Utility Group companies through the NU money pool. Over the course of 2005, these subsidiaries are expected to repay most of that amount to NU parent, which will use those proceeds and subsidiary dividends to fund NU's common dividend, meet NU parent interest and sinking fund obligations, and infuse additional common equity into the Utility Group companies, particularly CL&P. NU expects to continue to infuse additional equity into the regulated co mpanies for several years beyond 2005. To raise that additional equity, NU expects to sell common shares to the public as early as 2006.

The significant capital requirements of the Utility Group, particularly at CL&P, were one reason that the credit rating outlooks on various NU and subsidiary securities were lowered in 2004. Standard and Poor’s (S&P) reduced the outlook on all NU securities it rates to "negative" from "stable." In 2004, S&P lowered its ratings on NGC's debt to BB+, below investment grade, and Moody's Investors Service (Moody's) lowered its ratings on NGC debt to Baa3, its lowest investment grade rating. Fitch Ratings changed the outlook on NU and CL&P debt to "negative" in January 2005. In February 2005, Moody's reduced by one level the ratings of NU, CL&P, Yankee Gas, and NGC. It lowered by two levels the ratings on WMECO and affirmed with no change the ratings of PSNH. The ratings changes will result in modest increases in future borrowing costs for N U, CL&P and WMECO on their respective revolving credit agreements. The changes are not expected to have a material impact on borrowing costs when the Utility Group seeks long-term financing to support its capital investment plans. NGC did not issue new debt in 2004 and is not expected to issue new debt in the near future. All ratings of NU and subsidiary securities remain investment grade with the exception of Moody's and S&P ratings on NGC's bonds. As a result, those downgrades had no impact on the company's financial results.

On November 8, 2004, NU entered into a 5-year unsecured revolving credit and letter of credit (LOC) facility for $500 million on a short-term basis. This facility is intended to provide liquidity, LOCs and necessary capital for NU Enterprises. At December 31, 2004, there were $100 million of borrowings and $48.9 million of LOCs outstanding under this credit facility. For more information regarding the NU parent revolving credit facility, see Note 2, "Short-Term Debt," to the consolidated financial statements.

Utility Group: On November 8, 2004, the Utility Group entered into a 5-year unsecured revolving credit facility for $400 million. Under this credit facility, CL&P is able to borrow up to $200 million, and PSNH, WMECO, and Yankee Gas will be able to borrow up to $100 million each on a short-term basis. There were $80 million in borrowings outstanding under this credit facility at December 31, 2004. For more information regarding the Utility Group revolving credit facility, see Note 2, "Short-Term Debt" to the consolidated financial statements.

In addition to its revolving credit line, CL&P has an arrangement with a financial institution under which CL&P can sell up to $100 million of accounts receivable and unbilled revenues. At December 31, 2004, CL&P had sold accounts receivable totaling $90 million to that financial institution. For more information regarding the sale of receivables, see Note 1O, "Summary of Significant Accounting Policies - Sale of Receivables" to the consolidated financial statements.

On September 17, 2004, CL&P issued $150 million of 10-year first mortgage bonds at a fixed interest rate of 4.8 percent and also issued $130 million of 30-year first mortgage bonds at a fixed interest rate of 5.75 percent. CL&P used the proceeds from these issuances to repay short-term and redeem long-term debt.

During 2004, as part of the approved SMD settlement agreement, CL&P paid $83 million to its suppliers, of which $40.5 million was paid to affiliate Select Energy, and refunded $75 million to its customers. Of the combined payment and refund amount totaling $158 million, $124 million was funded from an escrow fund that was established during 2003 and 2004 as these SMD costs were being collected from customers. Additionally, the DPUC ordered a refund of $88.5 million in CTA/System Benefits Charge (SBC) overcollections over a seven-month period beginning with October 2004 consumption. The combination of the SMD and CTA/SBC refunds, when combined with CL&P’s proposed capital expenditures, will negatively impact CL&P’s liquidity. However, CL&P expects no difficulty in meeting these additional cash requirements.

Under FERC policy, transmission owners may capitalize debt and equity costs during the construction period through an allowance for funds used during construction (AFUDC). Debt costs capitalized offset interest expense with no impact on net income, while equity costs capitalized increase net income. CL&P expects to fund its construction expenditures with approximately 45 percent equity and 55 percent debt.

On July 22, 2004, PSNH issued $50 million of 10-year first mortgage bonds at a fixed interest rate of 5.25 percent. Proceeds were used to repay short-term debt and fund PSNH’s capital expenditure program. In October 2004, PSNH received the approvals necessary to begin the construction related to the conversion of one of the coal-fired units at Schiller Station to burn wood. The NHPUC approved the project, but the NHPUC's approval has been appealed to the New Hampshire Supreme Court. This project is expected to cost approximately $75 million.

On September 23, 2004, WMECO issued $50 million of 30-year senior unsecured notes at a fixed interest rate of 5.9 percent. Proceeds were used to finance a trust fund that will be used to meet WMECO's prior spent nuclear fuel liability of $49.3 million at December 31, 2004 which is recorded in long-term debt on the consolidated balance sheets. At December 31, 2004, the prior spent nuclear fuel trust totaled $49.3 million.

On January 30, 2004, Yankee Gas issued $75 million of 10-year first mortgage bonds carrying an interest rate of 4.8 percent. Yankee Gas issued an additional $50 million of 15-year first mortgage bonds with an interest rate of 5.26 percent on November 15, 2004. The proceeds from the issuance of these bonds were primarily used to repay short-term debt incurred to redeem long-term debt.

NU Enterprises: During 2004 NGC repaid approximately $32 million of long-term debt and is scheduled to meet $37.5 million of sinking fund maturities in 2005. SESI borrowed a total of $7.8 million during 2004 to finance the implementation of energy saving improvements at customer facilities. In 2004, SESI sold $30 million of receivables related to the energy savings contract projects. The transfer of receivables to the unaffiliated third party qualified as a sale under Statement of Financial Accounting Standards (SFAS) No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities - A Replacement of SFAS No. 125." Accordingly, the $30 million sold at December 31, 2004 is not included as debt in the consolidated financial statements. At December 31, 2004 and 2003, SESI had $93.2 million and $118 million of long-term debt outstanding, re spectively. Funds to repay these borrowings are provided by SESI's energy savings contract project revenues. Performance of these energy savings contract projects is guaranteed by NU.

For information regarding SESI's off-balance sheet arrangements, see "Off-Balance Sheet Arrangements," included in this Management's Discussion and Analysis.

Nuclear Decommissioning and Plant Closure Costs

The Connecticut Yankee Atomic Power Company (CYAPC) is currently in litigation with Bechtel Power Corporation (Bechtel) over the termination of its decommissioning contract. On June 13, 2003, CYAPC gave notice of the termination of its contract with Bechtel for the decommissioning of its nuclear power plant. CYAPC terminated the contract due to Bechtel's incomplete and untimely performance and refusal to perform the remaining decommissioning work. Bechtel has departed the site, and the decommissioning responsibility has been transitioned to CYAPC, which has recommenced the decommissioning process.

CYAPC's estimated decommissioning and plant closure costs for the period 2000 through 2023 have increased by approximately $395 million over the April 2000 estimate of $436 million approved by the FERC in a 2000 rate case settlement. The revised estimate reflects the increases in the projected costs of spent fuel storage, increased security and liability and property insurance costs, and the fact that CYAPC is now self-performing all work to complete the decommissioning of the plant due to the termination of the decommissioning contract with Bechtel in July 2003. NU's share of CYAPC's increase in decommissioning and plant closure costs is approximately $194 million. On July 1, 2004, CYAPC filed with the FERC for recovery of these increased costs. In the filing, CYAPC sought to increase its annual decommissioning collections from $16.7 million to $93 million for a six-year period beginning on Janua ry 1, 2005. On August 30, 2004, the FERC issued an order accepting the rates, with collection beginning on February 1, 2005 subject to refund, and scheduled hearings for May 2005. In total, NU's estimated remaining decommissioning and plant closure obligation for CYAPC is $308.7 million at December 31, 2004.

On June 10, 2004, the DPUC and Office of Consumer Counsel (OCC) filed a petition seeking a declaratory order that CYAPC be allowed to recover all decommissioning costs from its wholesale purchasers, including CL&P, PSNH and WMECO, but that such purchasers may not be allowed to recover in their retail rates any costs that the FERC might determine to have been imprudently incurred. On August 30, 2004, the FERC denied this petition. On September 29, 2004, the DPUC and OCC asked the FERC to reconsider the petition. On October 29, 2004, the FERC issued an order granting further consideration regarding the DPUC's and OCC's petition for reconsideration. No hearing date has been established for this reconsideration.

On February 22, 2005, the DPUC filed testimony with the FERC. In its filed testimony, the DPUC argues that approximately $215 million to $225 million of CYAPC’s requested increase is due to CYAPC’s imprudence in managing the decommissioning project while Bechtel was the contractor. Therefore, the DPUC recommends a total disallowance of between $225 million to $234 million. Hearings are scheduled to begin on June 1, 2005. NU’s share of the DPUC’s recommended disallowance is between $110 million to $115 million.

On June 23, 2003, Bechtel filed a complaint against CYAPC asserting a number of claims and seeking a variety of remedies, including monetary and punitive damages and rescission of the contract. Bechtel has since amended its complaint to add claims for wrongful termination. On August 22, 2003, CYAPC filed its answer and counterclaims, including counts for breach of contract, negligent misrepresentation and breach of duty of good faith and fair dealing. Discovery is currently underway, and a trial has been scheduled for May 2006.

In the prejudgment remedy proceeding before the Connecticut Supreme Court (the Court), Bechtel sought garnishment of the CYAPC decommissioning trust and related payments. In October 2004, Bechtel and CYAPC entered into an agreement under which Bechtel waived its right to seek garnishment of the decommissioning trust and related payments in return for the potential attachment of CYAPC's real property in Connecticut and the escrowing of $41.7 million the sponsors are scheduled to pay to CYAPC through June 30, 2007 with respect to CYAPC's common equity. This stipulation is subject to approval of the Court and would not be implemented until the Court found that such assets were subject to attachment. CYAPC has contested the attachability of such assets. The DPUC is an intervener in this proceeding.

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

The Yankee Companies filed litigation in 1998 charging that the federal government breached contracts it entered into with each company in 1983 under the Nuclear Waste Policy Act of 1982 (the Act). Under the Act, the United States Department of Energy (DOE) was to begin removing spent nuclear fuel from the nuclear plants of Yankee Atomic Electric Company (YAEC), Maine Yankee Atomic Power Company (MYAPC) and CYAPC no later than January 31, 1998 in return for payments by each company into the nuclear waste fund. No fuel has been collected by the DOE, and spent nuclear fuel is stored on the sites of the Yankee Companies' plants. YAEC, MYAPC and CYAPC collected the funds for payments into the nuclear waste fund from wholesale utility customers under FERC-approved contract rates. The wholesale utility customers in turn collect these payments from their retail electric customers. The Yankee Companies' individual damage claims attributed to the government's breach totaling $548 million are specific to each plant and include incremental storage, security, construction and other costs through 2010, which is the earliest date the DOE projects that it will begin removing nuclear fuel. The YAEC damage claim is $191 million, the MYAPC claim is $160 million and the CYAPC claim is $197 million.

The DOE trial ended on August 31, 2004, and a verdict has not been reached. The current Yankee Companies' rates do not include an amount for recovery of damages in this matter. Management can predict neither the outcome of this matter nor its ultimate impact on NU.

Business Development and Capital Expenditures

Consolidated: In 2004, NU’s capital expenditures totaled $643.8 million, compared with depreciation of $224.9 million. In 2003 and 2002, capital expenditures totaled $563.6 million and $510.5 million, respectively, compared with depreciation of $204.4 million and $205.6 million, respectively. In 2005, capital expenditures are projected to total approximately $740 million, compared with projected depreciation of approximately $240 million. The increasing level of capital expenditures is driven primarily by a need to improve the capacity and reliability of NU’s regulated energy delivery system. That increased level of capital expenditures, compared with depreciation levels, also is increasing the amount of plant in service and the regulated companies’ earnings base, provided NU’s Utility Group companies achieve timely recovery of their investment.

Utility Group:

CL&P: In December 2003, the DPUC approved $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 2004, CL&P’s distribution capital expenditures totaled $241.8 million, compared with $258.7 million in 2003 and $219.7 million in 2002. In 2005, CL&P projects distribution capital expenditures of approximately $230 million.

CL&P’s transmission capital expenditures totaled $128.1 million in 2004, compared with $63.5 million in 2003 and $39.1 million in 2002. In 2005, CL&P’s transmission capital expenditures are projected to total approximately $190 million. The primary reason for the increase projected for 2005 is the expectation that construction will increase in the spring of 2005 on a new 21-mile, 345 kV transmission project between Bethel, Connecticut and Norwalk, Connecticut. The CSC initially approved that project in July 2003.

On August 19, 2004, a Connecticut Superior Court judge dismissed an appeal by the City of Norwalk of the permit granted to CL&P by the CSC to construct a 345 kV transmission project from Bethel, Connecticut to Norwalk, Connecticut. Based upon a recently completed estimate, the project is currently projected to cost between $300 million and $350 million. The project is expected to begin to alleviate identified reliability issues in southwest Connecticut and to help offset rising customer costs for all of Connecticut. Work on the related substations has begun, and work on the transmission lines is expected to start in March 2005 after receiving permits from the towns and the Connecticut Department of Transportation. The major line construction contracts were signed in early March 2005. Management estimates a project completion date of December 2006. At December 31, 2004, CL&P has capi talized $65 million of costs associated with this project.

On October 9, 2003, CL&P and The United Illuminating Company (UI) filed for approval at the CSC for a separate 69-mile 345 kV transmission line from Middletown, Connecticut to Norwalk, Connecticut. Construction is expected to commence after the final route and configuration are determined by CSC. CL&P and UI initially estimated a cost of $620 million for the total project. In June 2004, after the New England Independent

System Operator (ISO-NE) raised concerns over the amount of underground line that had been proposed, the CSC requested that a committee comprised of representatives of CL&P, UI and ISO-NE study various alternatives and reach a consensus on the proposed project configuration. The report was filed on December 20, 2004 and recommended a maximum of 24 miles of underground line. On December 28, 2004 CL&P and UI filed updated cost estimates with the CSC which reflect changes needed to address technical issues introduced by the extensive amount of underground transmission being proposed and a two-year delay in the project in-service date from 2007 to 2009. The new estimates place the cost of the project between $840 million and $990 million. The variation in the cost range is due to unknown conditions that may be encountered during construction and a provision for other conti ngencies. Additional steps being considered by the CSC to lower magnetic fields along the overhead portion of the proposed route would add between $70 million and $80 million to the estimated cost. The CSC completed hearings on the proposal and the alternatives on February 17, 2005, and a ruling on the proposed project is expected by April 7, 2005. At December 31, 2004, CL&P has capitalized $18 million associated with this project.

On October 1, 2004, CL&P and the Long Island Power Authority (LIPA) jointly filed plans with the Connecticut Department of Environmental Protection to replace an undersea 13-mile electric transmission line between Norwalk, Connecticut and Northport - Long Island, New York, consistent with a comprehensive settlement agreement reached on June 24, 2004. This project is estimated to cost in the range of $114 million to $135 million with CL&P and LIPA each owning approximately 50 percent of the line. The cost range reflects that vendor contracts have not yet been signed. The project has received CSC approval, and federal and New York state approvals are expected in 2005. Pending final approval, construction activities are scheduled to begin in the fall of 2006. Management expects the line to be in service by the middle of 2008. At December 31, 2004, CL&P has capitalized $7 milli on of costs related to this project.

In May 2004, CL&P applied to the CSC to construct two 115 kV 9-mile underground transmission lines between Norwalk, Connecticut and Stamford, Connecticut. The project is expected to cost approximately $120 million and will help meet the growing electric demands in the area. Management expects the lines to be in service by 2008. At December 31, 2004, CL&P has capitalized $3 million of costs related to this project.

During 2004, NU placed in service $123 million of electric transmission projects. These projects included CL&P's $38 million upgrade of a transmission substation in Stamford, Connecticut that will allow additional electricity to be imported into southwest Connecticut.

Yankee Gas:On September 3, 2004, the DPUC approved the application by Yankee Gas to construct a LNG storage facility in Waterbury, Connecticut, at an expected cost of $108 million that is capable of storing the equivalent of 1.2 billion cubic feet of natural gas. On October 15, 2004, Yankee Gas signed a contract for the design and building of the facility, which will be filled through both liquefaction of natural gas on-site and the transportation of LNG from off-site locations. Formal groundbreaking for the project occurred on January 27, 2005, and management expects the facility to become operational in time for the 2007/2008 heating season. At December 31, 2004, Yankee Gas has capitalized $12.9 million of costs related to this project.

On November 1, 2004, Yankee Gas placed in service a new nine-mile gas line to connect its system in southeast Connecticut to the New England Gas Company (NEGASCO) system in Rhode Island. The construction project and a 20-year contract between Yankee Gas and NEGASCO were previously approved by the DPUC and related interstate transportation services by the FERC.

PSNH: In 2004, PSNH’s capital expenditures totaled $143.6 million, compared with $105.4 million in 2003 and $107 million in 2002. PSNH’s capital expenditures are projected to increase to approximately $150 million in 2005, primarily as a result of the conversion of one of three 50 megawatt units at the coal-fired Schiller Station to burn wood (Northern Wood Power Project). Construction of the $75 million Northern Wood Power Project has begun and is expected to be completed by late 2006. The NHPUC’s 2004 approval of the project has been appealed to the New Hampshire Supreme Court brought by some of New Hampshire’s existing wood-fired generating plant owners. Management does not believe that the appeal will negatively affect PSNH’s ability to complete the Northern Wood Power Project.

In addition to the Northern Wood Power Project, PSNH’s capital spending in 2005 will be driven in part by its agreement in its delivery charge 2004 rate case settlement to invest approximately $60 million annually in its distribution capital improvement program.

WMECO: In 2004, WMECO's capital expenditures totaled $38.6 million, compared with $33.3 million in 2003 and $26.5 million in 2002. As part of WMECO’s rate settlement approved by the DTE on December 29, 2004, WMECO agreed to invest not less than $24 million in capital expenditures in 2005 and 2006 related to reliability improvements.

For further information regarding rate matters associated with business development and capital expenditures, see "Utility Group Regulatory Issues and Rate Matters," in this Management's Discussion and Analysis.

NU Enterprises: In 2004, capital expenditures totaled $11.8 million at NGC, $1.5 million at HWP, and $4.3 million at other NU Enterprises businesses. Capital expenditures at NGC in 2004 included the final work on a $25 million project to increase the capacity of the Cabot conventional hydroelectric station in Massachusetts by 9 MW to 62 MW. HWP is evaluating spending approximately $14 million in 2005 and 2006 to meet new Massachusetts clean air requirements without which HWP’s Mt. Tom coal-fired generating station would be required to cease operation in October 2006. NGC’s capital expenditures in 2005 are projected to total approximately $10 million.

Transmission Access and FERC Regulatory Changes

NU companies CL&P, WMECO and PSNH are members of the New England Power Pool (NEPOOL) and, since 1997, have provided regional open access transmission service over their combined transmission system under the NEPOOL Open Access Transmission Tariff, which is administered by ISO-NE and local open access transmission service under the NU Companies Open Access Tariff No. 10, which the NU companies administer.

On October 31, 2003, ISO-NE, along with NU and six other New England transmission owning companies, filed a proposal with the FERC to create a Regional Transmission Organization (RTO) for New England in compliance with a 1999 FERC order calling on all transmission owners to voluntarily join RTOs (Order 2000). The RTO is intended to strengthen the independent and efficient management of the region’s power system

while ensuring that customers in New England continue to have highly reliable service and realize the benefits of a competitive wholesale energy market.

In a separate filing made on November 4, 2003, the New England transmission owning companies requested, consistent with the FERC’s proposed pricing policy for RTOs, that the FERC approve a single ROE for regional and local transmission service rates that would consist of a proposed 12.8 percent base ROE as well as incentive adders of 0.5 percent for joining a RTO and 1.0 percent for constructing new transmission facilities approved by the RTO.

On March 24, 2004, the FERC issued an order conditionally accepting the New England RTO proposal but set for hearing the determination of the appropriate base ROE for transmission rates under the RTO and the clarification as to which facilities the 1.0 percent incentive adder should apply. The 0.5 percent ROE adder was accepted for regional rates.

On November 3, 2004, the FERC issued an order that 1) determined that the New England transmission owners' methodology used to calculate the proposed ROE is appropriate, 2) clarified the application of the 0.5 percent incentive adder for joining a RTO for regional assets and reaffirmed the appropriateness of the 1.0 percent incentive adder for new investments; however, it left still unresolved the type of investments to which the 1.0 percent incentive adder should apply, and 3) approved certain compliance items that were required by the FERC's March 24, 2004 order.

While the order approved the methodology that had been proposed by the transmission owners for calculating the base ROE, it determined that the actual base ROE would be determined following the conclusion of an ordered hearing, which commenced on January 25, 2005. As part of the hearing procedures, the New England transmission owners submitted supplemental testimony supporting their ROE proposal on January 10, 2005 that, among other things, updated the ROE calculations submitted with the November filing. The decision on the ROE incentive adders could result in a different ROE being utilized in the calculation of Regional Network Service (RNS) tariffs than the ROE utilized in the calculation of Local Network Service (LNS) tariffs. An initial administrative law judge decision on these issues is expected in May 2005, and a final ruling regarding these issues is expected by the first quarter of 2006. & nbsp;

In January 2005, the New England transmission owners voted affirmatively to approve activation of the RTO, which occurred on February 1, 2005. As of February 1, 2005, transmission rates were adjusted to reflect the ROEs proposed by the New England transmission owners in the original RTO filing (12.8 percent plus the requested 0.5 percent), subject to refund to reflect the ROE resulting from the ultimate outcome of the hearings. Management cannot at this time predict the ultimate ROE that will be determined following the hearings.

Utility Group Regulatory Issues and Rate Matters

Transmission: Wholesale transmission revenues are based on rates and formulas that are approved by the FERC. Most of NU’s wholesale transmission revenues are collected through a combination of the RNS tariff and NU’s LNS tariff. NU’s LNS tariff is reset on June 1st of each year to coincide with the change in RNS rates. Additionally, NU’s LNS tariff provides for a true-up to actual costs, which ensures that NU recovers its total transmission revenue requirements, including the allowed ROE. Through December 31, 2004, this true-up has resulted in the recognition of a $4.6 million regulatory liability for refund to electric distribution companies, including CL&P, PSNH and WMECO.

On June 14, 2004, the transmission segment reached a settlement agreement with the parties to its rate case, which allows NU to implement formula-based rates as proposed with an allowed ROE of 11.0 percent. On September 16, 2004, the FERC approved the settlement agreement. The retroactive impact of the change in ROE from 11.75 percent to 11.0 percent reduced earnings by $1 million and $0.1 million, in 2004 and 2003, respectively. Effective February 1, 2005, the 11.0 percent ROE was increased to the aforementioned 12.8 percent ROE.

On February 1, 2005, consistent with its tariff, NU’s transmission segment implemented an increase to its transmission tariff that is expected to increase 2005 revenues by approximately $8 million over 2004 transmission revenues.

A significant portion of NU's transmission businesses' revenue is from charges to NU's electric distribution companies CL&P, PSNH and WMECO. These companies recover transmission charges through rates charged to their retail customers. WMECO has a rate tracking mechanism to track transmission costs charged in distribution rates to the actual amount of transmission charges incurred. The 2004 rates set in the CL&P distribution rate case contained a level of transmission revenue sufficient to recover CL&P's 2004 transmission costs. On February 1, 2005, CL&P filed an application with the DPUC to obtain approval to defer for future recovery in its retail transmission rate the increased transmission costs that CL&P is incurring as of February 1, 2005. The June 1, 2005 PSNH retail rate increase includes revenues to recover expected transmission costs. Neither CL&P nor PSNH currently have transmission rate tracking mechanisms that track transmission costs.

LICAP: In March 2004, ISO-NE filed a proposal at the FERC to implement locational installed capacity (LICAP) requirements. LICAP is an administratively determined electric generation asset capacity pricing mechanism intended to provide a revenue stream sufficient to maintain existing generation assets and encourage the construction of new generation assets at levels sufficient to serve peak load, plus a reserve margin and a cushion. In June 2004, the FERC ordered the creation of five LICAP zones and accepted ISO-NE’s demand curve methodology. The FERC ordered LICAP to be implemented by January 1, 2006, and set certain issues pertaining to the demand curve for hearings. Hearings began at the end of February 2005. A FERC decision is anticipated in the fall of 2005. Management cannot at this time predict the outcome of this FERC proceeding.

CL&P, PSNH and WMECO will incur LICAP charges. Because southwest Connecticut is a constrained area with insufficient generation assets, CL&P could incur LICAP costs totaling several hundred million dollars. These costs would be recovered from CL&P's customers through the FMCC mechanism. PSNH and WMECO will also recover these costs from customers.

Connecticut - CL&P:

Public Act No. 03-135 and Rate Proceedings: On June 25, 2003, the Governor of Connecticut signed into law Public Act No. 03-135 (the Act) which amended Connecticut's 1998 electric utility industry legislation. The Act required CL&P to file a four-year transmission and distribution plan with the DPUC. On December 17, 2003, the DPUC issued its final decision in the rate case.

CL&P filed a petition for reconsideration of certain items in the final decision on December 31, 2003. The DPUC issued a final decision on the petition on August 4, 2004. The final decision authorized CL&P to use existing CTA overrecoveries in lieu of an increase in rates to recover approximately $24 million, which is the net present value of the $32 million sought in the reconsideration. The final decision had a 2004 positive pre-tax impact of $11.5 million ($6.9 million after-tax) on CL&P. The remaining amount of $12.5 million is being amortized over four years beginning August 1, 2004 as an increase to revenues as the related costs to be recovered are incurred.

Under the Act, CL&P is allowed to collect a fixed procurement fee of 0.50 mills per kWh from customers who purchase TSO. One mill is equal to one-tenth of a cent. That fee can increase to 0.75 mills if CL&P outperforms certain regional benchmarks. The fixed portion of the procurement fee amounted to approximately $12 million (approximately $7 million after-tax) for 2004. On September 15, 2004, CL&P submitted to the DPUC its proposed methodology to calculate the variable portion (incentive portion) of the procurement fee. On November 18, 2004 the DPUC suspended this proceeding and has not indicated when the schedule will be resumed. The variable portion of the procurement fee has not yet been reflected in earnings.

Retail Transmission Rate Filing:On February 1, 2005, CL&P filed an application with the DPUC to obtain approval to defer for future recovery in its retail transmission rate the increased transmission costs that CL&P is incurring as of February 1, 2005. If the DPUC does not approve this deferral, CL&P’s application provides for an alternate proposal to increase its retail transmission rate to recover an additional $7.6 million on an annual basis, effective February 1, 2005. Under this proposal the increase would equal $0.00031 per kWh, and would represent approximately a 0.2 percent increase in overall rates as of February 1, 2005. Hearings in this docket have not been scheduled.

CTA and SBC Reconciliation: The CTA allows CL&P to recover stranded costs, such as securitization costs associated with the rate reduction bonds, amortization of regulatory assets, and independent power producer (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.

On April 1, 2004, CL&P filed its 2003 CTA and SBC reconciliation with the DPUC, which compares CTA and SBC revenues to revenue requirements. A final decision in the 2003 CTA and SBC docket was issued on August 4, 2004 and ordered a refund to customers of $88.5 million over a seven-month period beginning with October 2004 consumption.

In the 2001 CTA and SBC reconciliation filing, and subsequently in a September 10, 2002 petition to reopen related proceedings, CL&P requested that a deferred intercompany tax liability associated with the intercompany sale of generation assets be excluded from the calculation of CTA revenue requirements. On September 10, 2003, the DPUC issued a final decision denying CL&P's request, and on October 24, 2003, CL&P appealed the DPUC's final decision to the Connecticut Superior Court. The appeal has been fully briefed and argued. A decision from the court is not expected to be issued until the second quarter of 2005. If CL&P's request is granted through these court proceedings, then there could be additional amounts due to CL&P from its customers. The 2004 impact of including the deferred intercompany tax liability in CTA revenue requirements has been a reduction in revenue of ap proximately $19 million.

Application for Issuance of Long-Term Debt: On September 9, 2004, CL&P filed an application with the DPUC requesting approval to issue long-term debt in the amount of $600 million during the period February 1, 2005 to December 31, 2007. Additionally, CL&P requested approval to enter into hedging transactions from time to time through December 31, 2007 in connection with any prospective or outstanding long-term debt in order to reduce the interest rate risk associated with the debt or debt issuances. A final decision from the DPUC was issued on January 26, 2005. The final decision approved CL&P's request to issue $600 million in long-term debt through December 31, 2007. Additionally, the final decision approved CL&P's request to enter into hedging transactions in connection with any prospective or outstanding long-term debt in order to reduce the interest rate risk associate d with the debt or debt issuances. CL&P plans to issue up to $200 million in long-term debt by the middle of 2005.

CL&P TSO Rates: The vast majority of CL&P’s customers buy their energy through CL&P’s TSO, rather than buying energy directly from competitive suppliers. On August 1, 2003, CL&P filed with the DPUC to establish TSO rates equal to December 31, 1996 total rate levels. In October 2003, CL&P requested bids from wholesale energy marketers to supply its TSO requirements from 2004 through 2006. Five wholesale marketers supplied CL&P’s TSO requirements in 2004, including Select Energy. On December 19, 2003, the DPUC issued a final decision setting the average TSO rate of $0.1076 per kWh effective January 1, 2004. In November 2004, CL&P requested bids from wholesale marketers to supply the TSO requirements in 2005 and 2006 that were not filled in the 2003 solicitation. Due to higher energy prices, the bids received and accepted by CL& amp;P were significantly higher than those accepted in 2003. As a result of the higher supply costs, higher FMCC and a $25.1 million distribution rate increase approved by the DPUC in CL&P's rate case, on November 24, 2004, CL&P requested the DPUC to increase its TSO rate by 16.7 percent in 2005. On December 22, 2004, the DPUC approved the increase of 16.2 percent effective January 1, 2005, although the impact was partially offset by a continuation of the CTA refund. The DPUC also ordered that projected 2004 and 2005 CTA overrecoveries and half of projected 2004 distribution overrecoveries be used to moderate increases for customers that otherwise would occur when the current CTA refund expires on May 1, 2005. Overall, the final decision approved an increase to the January 2004 TSO rates of approximately 10.4 percent, including the effects of existing and new refunds and overrecoveries. The DPUC denied requests by the Connecticut Attorney General and OCC to defer th e recovery of higher supplier costs into future years. On February 3, 2005, the OCC filed an appeal with the Connecticut Superior Court challenging this decision. This appeal is identical to the appeal filed with the same court in February 2004 challenging the DPUC's December 2003 decision. Management believes that this appeal will not impact the DPUC's December 22, 2004 order.

Also, pursuant to state law, on December 19, 2003, the DPUC set CL&P’s TSO rates for January 1, 2004 through December 31, 2004 and confirmed that state law exempted FMCC, Energy Adjustment Clause (EAC) charges and certain other charges from the statutorily imposed rate cap. The OCC filed appeals of this decision with the Connecticut Superior Court. The OCC claims that the decision improperly implements an EAC charge under

Connecticut law, fails to properly define and identify the fees that CL&P will be allowed to collect from customers and improperly calculates base rates for purposes of determining the rate cap. Management believes that these appeals will not impact the TSO rates approved by the DPUC.

On February 1, 2005, CL&P filed for a 1.6 percent increase to rates ($29.2 million) to collect additional FMCC from customers effective May 1, 2005. The increase is necessary to collect costs related to an additional RMR contract related to two generating plants located in southwest Connecticut. The RMR contract has preliminary approval for billing from the FERC and is subject to a future review by the FERC prior to final approval.

Connecticut - Yankee Gas:

Rate Case Filing: On July 2, 2004, Yankee Gas filed a rate case with the DPUC to increase retail rates by $26.5 million, or 7.2 percent, effective January 1, 2005. Yankee Gas also requested an authorized ROE of 10.75 percent in the rate case filing. The requested increase in rates was based on increased costs of distribution delivery services such as pension and healthcare, as well as the cost of additional investments needed to maintain a safe and reliable gas distribution system.

On October 14, 2004, Yankee Gas filed a settlement agreement with the DPUC. Parties to the settlement agreement included the OCC and the Prosecutorial Division of the DPUC. The settlement agreement increases customer rates by $14 million annually, allows a ROE of 9.9 percent and reduces Yankee Gas' annual expense for plant taken out of service by $5.7 million. As part of the settlement agreement, Yankee Gas agreed not to file a new rate increase application to be effective prior to the earlier of the in-service date of its new LNG facility or July 1, 2007. On December 8, 2004, the DPUC issued a final decision approving the settlement agreement as filed. The rate increase took effect on January 1, 2005.

New Hampshire:

Delivery Rate Case: PSNH's delivery rates were fixed, effective May 1, 2001, by the "Agreement to Settle PSNH Restructuring" (Restructuring Settlement) until February 1, 2004. Consistent with the requirements of the Restructuring Settlement and state law, PSNH filed a delivery service rate case and tariffs with the NHPUC on December 29, 2003 to increase electricity delivery rates by approximately $21 million, or 2.6 percent, effective February 1, 2004.

On July 14, 2004, PSNH filed with the NHPUC a revenue requirements settlement agreement among several parties, including the NHPUC staff and the Office of Consumer Advocate (OCA). The terms of the proposed settlement agreement allowed for increases in PSNH's delivery rates totaling $3.5 million annually, effective prospectively beginning October 1, 2004, and an incremental $10 million annual increase effective prospectively on June 1, 2005, for a total rate increase of $13.5 million. On July 29, 2004, PSNH filed with the NHPUC a rate design settlement agreement among several parties, including the NHPUC staff. These proposed revenue requirements and rate design settlement agreements together resolved all delivery service rate case issues. On September 2, 2004, the NHPUC issued an order approving both settlement agreements, and new delivery service rates went into effect on October&n bsp;1, 2004.

Transition Energy Service and Default Energy Service: In accordance with the Restructuring Settlement and state law, PSNH files for updated TS/DS rates periodically to ensure timely recovery of its costs. The TS/DS rate recovers PSNH's generation and purchased power costs, including a return on PSNH's generation investment. PSNH defers for future recovery or refund any difference between its TS/DS revenues and the actual costs incurred.

On September 24, 2004, PSNH filed a petition with the NHPUC requesting a change in the TS/DS rate for the period February 1, 2005 through January 31, 2006. In December 2004, PSNH petitioned for a TS/DS rate of $0.0649 per kWh based on updated market information. The NHPUC issued its order approving a TS/DS rate of $0.0649 per kWh on January 28, 2005. This TS/DS rate includes an 11 percent ROE on PSNH's generation assets, which is subject to further review by the NHPUC.

SCRC Reconciliation Filings: The Stranded Cost Recovery Charge (SCRC) allows PSNH to recover its stranded costs. On an annual basis, PSNH files with the NHPUC a SCRC reconciliation filing for the preceding calendar year. This filing includes the reconciliation of stranded cost revenues billed with stranded costs, and TS/DS revenues billed with TS/DS costs. The NHPUC reviews the filing, including a prudence review of PSNH's generation operations. The cumulative deferral of SCRC revenues in excess of costs was $208.6 million at December 31, 2004. This cumulative deferral will decrease the amount of non-securitized stranded costs that will have to be recovered from PSNH's customers in the future from $411.3 million to $202.7 million.

The 2003 SCRC reconciliation filing was filed with the NHPUC on April 30, 2004, and a stipulation and settlement agreement between PSNH, the OCA and NHPUC staff was filed with the NHPUC on October 4, 2004. Under the terms of the settlement agreement, no costs related to the recovery of stranded costs or the cost of providing transition energy service were disallowed, and the NHPUC staff agreed to accept the 2003 SCRC filing without change. On October 29, 2004, the NHPUC issued an order accepting the settlement agreement as filed.

The 2004 SCRC reconciliation filing is expected to be filed with the NHPUC by May 2, 2005. Management does not expect the NHPUC's review of the 2004 SCRC filing to have a material impact on PSNH's net income or financial position.

The SCRC and TS/DS rate mechanisms currently reconcile accrued expenses with billed revenues on a monthly basis. On May 2, 2005, PSNH expects to file its annual 2004 SCRC and TS/DS reconciliation that will include a request to include unbilled revenues as part of the reconciliation process. This request will allow for the reconciliation of revenues on an accrual basis with the current accrued expenses recovered through the SCRC and TS/DS rate mechanisms, consistent with accrual accounting. At December 31, 2004, the PSNH unbilled revenue balance related to SCRC and TS/DS was $11.7 million and $16.7 million, respectively. If approved, this change will allow for the inclusion of accrued unbilled revenue balances in the recovery of SCRC and TS/DS costs. Management believes that the unbilled revenue balance related to SCRC and TS/DS is probable of being recovered from PSNH's customers.

Wholesale Distribution Rate Case: PSNH is planning to file a wholesale distribution rate case with the FERC in late March 2005. This FERC filing is necessary due to the reclassification of certain assets from PSNH's transmission business to distribution business. PSNH plans to file a revenue requirements analysis in order to recover certain delivery costs arising from the provision of wholesale delivery service to another New Hampshire utility.

Massachusetts:

Transition Cost Reconciliation: On March 31, 2004, WMECO filed its 2003 transition cost reconciliation with the DTE. This filing reconciled the recovery of generation-related stranded costs for calendar year 2003. The DTE has not initiated its investigation into this filing. WMECO expects to file its 2004 transition cost reconciliation with the DTE on March 31, 2005. The DTE combined the 2003 transition cost reconciliation filing and the 2004 transition cost reconciliation filing into a single proceeding. The timing of this decision in the combined proceeding is uncertain, but management does not expect the outcome to have a material adverse impact on WMECO's net income or financial position.

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

NU Enterprises

Business Segments: NU Enterprises aligns its businesses into two business segments: the merchant energy business segment and the energy services and other business segment. The merchant energy business segment includes Select Energy's wholesale and retail marketing businesses. Also currently included in the merchant energy segment are 1,443 MW of generation assets, including 1,296 MW of pumped storage and hydroelectric generation assets at NGC and 147 MW of coal-fired generation assets at HWP. The wholesale business primarily serves full requirements sales to LDCs and bilateral sales to other load serving counterparties. To serve these customers, Select Energy relies on its own generation and an inventory of energy contracts.

The energy services business segment includes the operations of SESI, NGS, and Woods Network. SESI performs energy management services for large commercial customers, institutional facilities and the United States government and energy-related construction services. NGS operates and maintains NGC's and HWP's generation assets and provides third-party electrical services. Woods Network is a network design, products and services company.

Results: NU Enterprises lost $15.1 million in 2004. This loss includes a $48.3 million mark-to-market loss associated with certain wholesale natural gas positions. In 2003, NU Enterprises lost $3.4 million. This loss includes a $35.6 million charge associated with SMD. NU Enterprises' merchant energy retail marketing business earnings improved to net income of $4.9 million in 2004, compared with a loss of $1.8 million in 2003.

NU Enterprises’ energy services business segment lost $2.3 million in 2004 compared with earnings of approximately $2.6 million in 2003. The 2004 earnings decrease is the result of losses recorded on a major construction contract.

Outlook: On March 9, 2005, NU completed its previously announced comprehensive review of its competitive energy businesses and decided that NU Enterprises will exit the wholesale marketing business. NU also concluded that NU Enterprises' energy services businesses are not central to NU's long-term strategy and do not meet the company's expectations of profitability. As a result, the company will explore ways to divest those businesses in a manner that maximizes their value. NU will retain its competitive generation and retail energy marketing businesses because it believes that the generation assets and retail business are competitively positioned to create significant opportunities for those businesses over the next several years.

NU Enterprises’ 2005 earnings will be impacted by many factors, including the amount of asset impairments or losses on disposals that could result from the decision to explore divesting the services segment, the mark-to-market loss that may result from the application of mark-to-market accounting to certain wholesale marketing contracts until those contracts are sold or until the commodities are delivered, and other closure costs.

Intercompany Transactions: CL&P's standard offer purchases from Select Energy represented $502 million for the year ended December 31, 2004, compared with $558 million during the same period in 2003. Other energy purchases between CL&P and Select Energy totaled $109.3 million for the year ended December 31, 2004 and $130 million during the same period in 2003. Additionally, WMECO's purchases from Select Energy represented $108.5 million for the year ended December 31, 2004, compared with $143 million during the same period in 2003. These amounts are eliminated in consolidation.

NU Enterprises’ Market and Other Risks

Overview: The decision to exit the wholesale marketing business will change the risk profile of NU Enterprises in 2005. Subsequent to the sale of the wholesale marketing business, NU Enterprises will continue to be exposed to certain market risks; however, management believes that those risks will be reduced. The merchant energy business segment will be comprised of generation assets and the retail marketing segment, which will enter into contracts of varying lengths of time to buy and sell energy commodities, including electricity, natural gas, and oil to retail customers. Market risk represents the loss that may affect the merchant energy business segment’s financial results, primarily Select Energy, due to adverse changes in commodity market prices.

Risk management within Select Energy has been organized to address the market, credit and operational exposures arising from the merchant energy business segment. The framework for managing these risks is set forth in NU's risk management policies and procedures, which are reviewed by the

NU Board of Trustees on an as needed basis.

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

The pricing terms of full requirement contracts and of supply contracts can affect the timing of Select Energy's margins. Many full requirements contracts have higher prices in certain months, while many supply contracts have one price for the entire contract term. Accordingly, Select Energy's margins will tend to be higher in the months when the full requirements contract price is higher and lower or could be negative when the full requirements contract price is lower.

Energy Sourcing Activities: In June 2004, Select Energy began purchasing fixed-price electricity and some electricity with prices indexed to gas for 2005 and 2006 in anticipation of winning full requirements contract sales and sales to load-serving entities. Purchasing electricity in advance creates the risk of electricity price decreases before the full requirement quantities are contracted and before contract prices are known.

To mitigate the risk of electricity price decreases on the fixed-price electricity that was purchased, Select Energy in June 2004 began selling wholesale natural gas contracts for 2005 and 2006. The intended result of this risk mitigation strategy was that decreases in the value of the fixed-price electricity purchase contracts would be offset in part by increases in the value of the gas contracts, and vice versa. Select Energy intended to purchase natural gas when quantities and prices of electricity are secured by full requirements contracts or sales contracts with load-serving entities. Natural gas was sold in this risk mitigation strategy due to the high liquidity of the natural gas market compared to the low liquidity of electricity in New England.

The electricity contracts were accounted for on the accrual basis through 2004, which would have resulted in earnings recognition when the electricity would have been delivered to customers in 2005 and 2006. These electricity purchase contracts were to be used to meet electricity sales contract requirements, which was a key component of the merchant energy wholesale business. Until the decision to cease wholesale marketing activities was made, management believed that this electricity would be delivered to its customers. The decision on March 9, 2005 to exit the wholesale marketing business changed management’s conclusion regarding the likelihood that many wholesale marketing contracts would result in delivery to customers. This in turn resulted in a change in March 2005 from accrual accounting to fair value accounting for the wholesale marketing contracts that will be sold. Under fair value accounting, changes in the fair value of these contracts will impact 2005 earnings until the contracts are completed or sold.

The natural gas contracts are recorded at current fair value with changes in fair value impacting earnings. At December 31, 2004 the fair value of the natural gas contracts was a negative $77.7 million. The changes in fair values totaling a negative $77.7 million increased fuel, purchased and net interchange power in 2004. Of the total fair value of negative $77.7 million, approximately negative $68 million relates to 2005 with approximately negative $10 million related to 2006.

The use of fair value accounting for the aforementioned natural gas and electricity contracts has exposed and will continue to expose Select Energy’s and NU’s earnings to future changes in natural gas and electricity prices, which could be significant. This has and can reasonably be expected to create uncertainty in 2005 regarding Select Energy’s and NU’s earnings and earnings trends.

The natural gas contracts are included in non-trading derivative assets and liabilities in the table in Note 3, "Derivative Instruments," to the consolidated financial statements.

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

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

Hedging and Other Non-Trading: For information on derivatives used for hedging purposes and non-trading derivatives, see Note 3, "Derivative Instruments," to the consolidated financial statements.

Wholesale Contracts Defined as "Energy Trading": Historically, energy trading transactions at Select Energy include financial transactions and physical delivery transactions for electricity, natural gas and oil in which Select Energy attempted to profit from changes in market prices. Energy trading contracts are recorded at fair value, and changes in fair value affect net income.

At December 31, 2004, Select Energy had trading derivative assets and trading derivative liabilities as follows:

(Millions of Dollars)

2004

Current trading derivative assets	$49.6
Long-term trading derivative assets	31.7
Current trading derivative liabilities	(46.2)
Long-term trading derivative liabilities	(5.5)
Portfolio position	$29.6

There can be no assurances that Select Energy will realize cash corresponding to the present positive net fair value of its trading positions. Numerous factors could either positively or negatively affect the realization of the net fair value amount in cash. These include the sales price to be received on the sale of these contracts, the volatility of commodity prices until the contracts are sold, the outcome of future transactions, the performance of counterparties, and other factors.

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

The methods used to determine the fair value of energy trading contracts are identified and segregated in the table of fair value of contracts at December 31, 2004. A description of each method is as follows: 1) prices actively quoted primarily represent New York Mercantile Exchange futures and options that are marked to closing exchange prices; and 2) prices provided by external sources primarily include over-the-counter forwards and options, including bilateral contracts for the purchase or sale of electricity or natural gas, and are marked to the mid-point of bid and ask market prices. Currently, Select Energy has one contract for which a portion of the contract's fair value is determined based on a model or other valuation method. The model utilizes natural gas prices and a conversion factor to electricity. Management recorded a modeling reserve to reduce the value of the contract for those years t hat do not have liquid prices to zero. Broker quotes for electricity at locations that Select Energy has entered into deals are available through the year 2007. For all natural gas positions, broker quotes extend through 2013.

Generally, valuations of short-term contracts derived from quotes or other external sources are more reliable should there be a need to liquidate the contracts, while valuations for longer-term contracts are less certain. Accordingly, there is a risk that contracts will not be realized at the amounts recorded. However, Select Energy has obtained corresponding purchase or sale contracts for a large portion of the trading contracts that have maturities in excess of one year.

Because these trading contracts are sourced, changes in the value of these contracts due to fluctuations in commodity prices are not expected to significantly affect Select Energy's earnings.

As of and for the years ended December 31, 2004 and 2003, the sources of the fair value of trading contracts and the changes in fair value of these trading contracts are included in the following tables. Intercompany transactions are eliminated and not reflected in the amounts below.

(Millions of Dollars)	Fair Value of Trading Contracts at December 31, 2004
Sources of Fair Value	Maturity Less Than One Year	Maturity of One to Four Years	Maturity in Excess of Four Years	Total Fair Value
Prices actively quoted	$0.7	$ -	$ -	$ 0.7
Prices provided by external sources	2.8	13.6	12.5	28.9
Totals	$3.5	$13.6	$12.5	$29.6

(Millions of Dollars)	Fair Value of Trading Contracts at December 31, 2003
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	$0.2	$0.1	$ -	$ 0.3
Prices provided by external sources	6.9	9.6	15.7	32.2
Totals	$7.1	$9.7	$15.7	$32.5

The fair value of energy trading contracts decreased to $29.6 million at December 31, 2004 from $32.5 million at December 31, 2003. The change in the fair value of the trading portfolio is primarily attributable to contracts being settled in 2004, offset by changes in the fair value of contracts. The change in fair value attributable to changes in valuation techniques and assumptions of $2.3 million in 2003 resulted from a change in the discount rate management uses to determine the fair value of trading contracts. In the second quarter of 2003, the rate was changed from a fixed rate of 5 percent to a market-based LIBOR discount rate to better reflect current market conditions.

	Years Ended December 31,
	2004	2003
(Millions of Dollars)	Total Portfolio Fair Value
Fair value of trading contracts outstanding at the beginning of the year	$32.5	$41.0
Contracts realized or otherwise settled during the period	(10.5)	(10.7)
Changes in fair values attributable to changes in valuation techniques and assumptions	-	2.3
Changes in fair value of contracts	7.6	(0.1)
Fair value of trading contracts outstanding at the end of the year	$29.6	$32.5

For further information regarding Select Energy's derivative contracts, see Note 3, "Derivative Instruments," and Note 12, "Accumulated Other Comprehensive Income/(Loss)," to the consolidated financial statements.

Changing Market: In general, the market for energy products has become shorter term in nature with less liquidity, market pricing information is less readily available and participants are sometimes unable to meet Select Energy's credit standards without providing cash or LOC support. Select Energy is being adversely affected by these factors, and there could be a continuing adverse impact on Select Energy's business.

In addition, NU Enterprises has concluded that competition has increased significantly in the wholesale power market in New England over the last six months of 2004. This increase in competition may affect Select Energy's profitability by reducing the number of bids won and by reducing the margins on those bids which are won.

Changes are occurring in the administration of transmission systems in territories in which Select Energy does business. As the market continues to evolve, there could be additional challenges or opportunities that management cannot determine at this time.

In March 2004, ISO-NE filed a proposal at the FERC to implement LICAP requirements. LICAP is an administratively determined electric generation asset capacity pricing mechanism intended to provide a revenue stream sufficient to maintain existing generation assets and encourage the construction of new generation assets at levels sufficient to serve peak load, plus a reserve margin and a cushion. In June 2004, the FERC ordered the creation of five LICAP zones and accepted ISO-NE’s demand curve methodology. The FERC ordered LICAP to be implemented by January 1, 2006, and set certain issues pertaining to the demand curve for hearings. Hearings began at the end of February 2005. A FERC decision is anticipated in the fall of 2005. Management cannot at this time predict the outcome of this FERC proceeding.

Depending on the pricing curves that are ultimately implemented LICAP could produce significant benefits for generation assets either owned or leased by NU Enterprises. NU Enterprises owned or leased approximately 300 MW of generation assets in Connecticut and approximately 1,300 MW of generation assets in western Massachusetts.

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 written credit policies with regard to its counterparties to minimize overall credit risk. These policies require an evaluation of potential counterparties' financial condition (including credit ratings), collateral requirements under certain circumstances (including cash advances, LOCs, and parent guarantees), and the use of standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. This evaluation results in establishing credit limits prior to Select Energy's entering into contracts. The appropriateness of these limits is subject to continuing review. Concentrations among these counter parties 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, 2004, approximately 77 percent of Select Energy's counterparty credit exposure to wholesale and trading counterparties was collateralized or rated BBB- or better. Select Energy was provided $57.7 million and $46.5 million of counterparty deposits at December 31, 2004 and December 31, 2003, respectively. For further information, see Note 1Y, "Summary of Significant Accounting Policies - Counterparty Deposits," to the consolidated financial statements.

Select Energy's Credit: A number of Select Energy's contracts require the posting of additional collateral in the form of cash or LOCs in the event NU's ratings were to decline and in increasing amounts dependent upon the severity of the decline. At NU's present investment grade ratings, Select Energy has not had to post any collateral based on credit downgrades. Were NU's unsecured ratings to decline two levels to sub-investment grade, Select Energy could, under its present contracts, be asked to provide at December 31, 2004 approximately $361 million of collateral or LOCs to various unaffiliated counterparties and approximately $140 million to several independent system operators and unaffiliated LDCs, which management believes NU would currently be able to provide, subject to the Securities and Exchange Commission (SEC) limits. NU's credit ratings outlooks are currently stable or negativ e, but management does not believe that at this time there is a significant risk of a ratings downgrade to sub-investment grade levels.

Consolidated Edison, Inc. Merger Litigation

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

On May 11, 2001, Con Edison filed an amended complaint seeking damages for breach of contract, fraudulent inducement and negligent misrepresentation in an unspecified amount, but which Con Edison’s Chief Financial Officer has testified is at least $314 million. NU disputes both Con Edison’s entitlement to any damages as well as its method of computing its alleged damages.

The companies completed discovery in the litigation and submitted cross motions for summary judgment. The court denied Con Edison’s motion in its entirety, leaving intact NU's claim for breach of the Merger Agreement, and partially granted NU's motion for summary judgment by eliminating Con Edison’s claims against NU for fraud and negligent misrepresentation.

An intervener in this litigation has made the claim that NU shareholders at March 5, 2001 are entitled to damages from Con Edison, if any, and not current NU shareholders.

Appeals on this and other issues are now pending and no trial date has been set. At this stage of the litigation, management can predict neither the outcome of this matter nor its ultimate effect on NU.

Off-Balance Sheet Arrangements

Utility Group: The CL&P Receivables Corporation (CRC) was incorporated on September 5, 1997, and is a wholly owned subsidiary of CL&P. CRC has an agreement with CL&P to purchase and has an arrangement with a highly-rated financial institution under which CRC can sell up to $100 million of an undivided interest in accounts receivable and unbilled revenues. At December 31, 2004 and 2003, CRC had sold an undivided interest in its accounts receivable and unbilled revenues of $90 million and $80 million, respectively, to that financial institution with limited recourse.

CRC was established for the sole purpose of selling CL&P’s accounts receivable and unbilled revenues and is included in the consolidated NU financial statements. On July 7, 2004, CRC renewed its Receivables Purchase and Sale Agreement with CL&P and the financial institution through July 6, 2005, and the termination date of the facility was extended to July 3, 2007. Management plans to renew this agreement prior to its expiration. 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. Accordingly, the $90 million and $80 million outstanding under this facility are not reflected as debt or included in the consolidated financial statements at December 31, 2004 and 2003, respectively.

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

NU Enterprises: During 2001, SESI created HEC/CJTS Energy Center, LLC (HEC/CJTS) which is a special purpose entity (SPE). SESI created HEC/CJTS for the sole purpose of providing a bankruptcy remote entity for the financing of a construction project. The construction project was the construction of an energy center to serve the Connecticut Juvenile Training School (CJTS). The owner of CJTS, the State of Connecticut, entered into a 30-year lease with HEC/CJTS for the energy center. Simultaneously, HEC/CJTS transferred its interest in the lease with the State of Connecticut to investors who are unaffiliated with NU in exchange for the issuance of $19.2 million of Certificates of Participation. The transfer of HEC/CJTS’s interest in the lease was accounted for as a sale under SFAS No. 140. The debt of $19.2 million created in relation to the transfer of interest and issuance o f the Certificates of Participation was derecognized and is not reflected as debt or included in the consolidated financial statements. No gain or loss was recorded. HEC/CJTS does not provide any guarantees or on-going services, and there are no contingencies related to this arrangement.

SESI has a separate contract with the State of Connecticut to operate and maintain the energy center. The transaction was structured in this manner to obtain tax-exempt rate financing and therefore to reduce the State of Connecticut’s lease payments.

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

SESI entered into a master purchase agreement with an unaffiliated third party on April 30, 2002 under which SESI may sell certain receivables that are due or become due under delivery orders issued pursuant to federal energy savings performance contracts. At December 31, 2004, SESI had sold $30 million of receivables related to the installation of the energy efficiency projects under this arrangement. The transfer of receivables to the unaffiliated third party under this arrangement qualified as a sale under SFAS No. 140. Accordingly, the $30 million sold at December 31, 2004 is not included as debt in the consolidated financial statements. Under the delivery order with the United States government, SESI is responsible for

on-going maintenance and other services related to the energy efficiency project installation. SESI receives payment for those services in addition to the amounts sold under the master purchase agreement.

SESI has entered into assignment agreements to sell an additional $26.5 million of receivables. This sale will be complete upon customer acceptance of the project installation. Until construction is completed, the advances under the purchase agreement are included in long-term debt in the consolidated financial statements.

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.

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

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

NU had a preferred stock investment in R. M. Services, Inc. (RMS). Upon adoption of FIN 46, management determined that NU was the primary beneficiary of RMS and subsequently consolidated RMS into its financial statements. The consolidation of RMS resulted in a negative $4.7 million after-tax cumulative effect of an accounting change in the third quarter of 2003. On June 30, 2004, the assets and liabilities of RMS were sold. For more information on RMS, seeNote 1I, "Summary of Significant Accounting Policies - Accounting for R.M. Services, Inc." to the consolidated financial statements.

In December 2003, the FASB issued a revised version of FIN 46 (FIN 46R). FIN 46R has resulted in fewer NU investments meeting the definition of a VIE. FIN 46R was effective for NU for the first quarter of 2004 and did not have an impact on NU's consolidated financial statements.

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

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

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

Wholesale transmission revenues are based on rates and formulas that are approved by the FERC. Most of NU's wholesale transmission revenues are collected through a combination of the RNS tariff and NU's LNS tariff. The RNS tariff, which is administered by ISO-NE, recovers the revenue requirements associated with transmission facilities that are deemed by the FERC to be Pool Transmission Facilities. The LNS tariff, which was accepted by the FERC on October 22, 2003, provides for the recovery of NU's total transmission revenue requirements, net of revenue credits received from various rate components, including revenues received under the RNS rates.

NU Enterprises recognizes revenues at different times for its different business lines. Wholesale and retail marketing revenues are typically recognized when energy is delivered to customers. Trading revenues are recognized as the fair value of trading contracts changes. Service revenues are recognized as services are provided, often on a percentage of completion basis.

Revenues and expenses for derivative contracts that are entered into for trading purposes are recorded on a net basis in revenues when these transactions settle. The settlement of wholesale non-trading derivative contracts for the sale of energy or gas by both the Utility Group and NU Enterprises that are related to customers' needs are recorded in operating expenses. Derivative contracts that hedge an underlying transaction and that qualify for hedge accounting affect 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 settlement of hedge derivative contracts is recorded in the same revenue or expense line as the transaction being hedged. For further information regarding the accounting for these contracts, see Note 1F, "Summary of Significant Accounting Policies - Derivative Accounting," to the consolidated financial statements.

Utility Group Unbilled Revenues: Unbilled revenues represent an estimate of electricity or gas delivered to customers that has not been billed. Unbilled revenues represent assets on the balance sheet that become accounts receivable in the following month as customers are billed.

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

The Utility Group currently estimates unbilled revenues monthly using the requirements method. The requirements method utilizes the total monthly volume of electricity or gas delivered to the system and applies a delivery efficiency (DE) factor to reduce the total monthly volume by an estimate of delivery losses in order to calculate total estimated monthly sales to customers. The total estimated monthly sales amount less total monthly billed sales amount results in a monthly estimate of unbilled sales. Unbilled revenues are estimated by applying an average rate to the estimate of unbilled sales. The estimated DE factor can have a significant impact on estimated unbilled revenue amounts.

During 2004 the unbilled sales estimates for all Utility Group companies were tested using the cycle method. The cycle method uses the billed sales from each meter reading cycle and an estimate of unbilled days in each month based on the meter reading schedule. The cycle method is historically more accurate than the requirements method when used in a mostly weather-neutral month. The cycle method testing was performed in the second and fourth quarters of 2004 but did not have a material impact on earnings.

During 2003 the cycle method resulted in adjustments to the estimate of unbilled revenues that had a net positive after-tax earnings impact of approximately $4.6 million. The 2003 positive after-tax impacts on CL&P, PSNH, and WMECO were $7.2 million, $3.3 million, and $0.3 million, respectively. There was a negative after-tax impact on Yankee Gas of $6.2 million, including certain gas cost adjustments.

Derivative Accounting: Effective January 1, 2001, NU adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended.

Most of the contracts comprising Select Energy's wholesale and retail marketing activities are derivatives, and many Utility Group contracts for the purchase or sale of energy or energy-related products are derivatives. The application of derivative accounting under SFAS No. 133, as amended, is complex and requires management judgment in the following respects: election and designation of the normal purchases and sales exception, identification of derivatives and embedded derivatives, identifying hedge relationships, assessing and measuring hedge ineffectiveness, and determining the fair value of derivatives. All of these judgments, depending upon their timing and effect, can have a significant impact on NU’s consolidated net income.

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

In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities," which amended existing derivative accounting guidance. This new statement incorporates interpretations that were included in previous Derivative Implementation Group (DIG) guidance, clarifies certain conditions, and amends other existing pronouncements. It was effective for contracts entered into or modified after June 30, 2003. Management has determined that the adoption of SFAS No. 149 did not change NU’s accounting for wholesale and retail marketing contracts or the ability of NU Enterprises to elect the normal purchases and sales exception. The adoption of SFAS No. 149 resulted in fair value accounting for certain Utility Group contracts that are subject to unplanned netting and do not meet the definition of capacity contracts. These non-trading derivative contracts are recorded at fair value at December 31, 2004 and 2003 as derivative assets and liabilities with offsetting amounts recorded as regulatory liabilities and assets because the contracts are part of providing regulated electric or gas service.

Emerging Issues Task Force (EITF) Issue No. 03-11, "Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133, and ‘Not Held for Trading Purposes’ as Defined in EITF Issue No. 02-3," was derived from EITF Issue No. 02-3, which requires net reporting in the income statement of energy trading activities. Issue No. 03-11 addresses income statement classification of revenues related to derivatives that physically deliver and are not related to energy trading activities. Prior to Issue No. 03-11, there was no specific accounting guidance that addressed the classification in the income statement of Select Energy’s retail marketing and wholesale contracts or the Utility Group’s power supply contracts, many of which are non-trading derivatives.

On July 31, 2003, the EITF reached a consensus in Issue No. 03-11 that determining whether realized gains and losses on contracts that physically deliver and are not held for trading purposes should be reported on a net (sales and purchases both in expenses) or gross (sales in revenues and purchases in expenses) basis is a matter of judgment that depends on the relevant facts and circumstances. The EITF indicated that existing accounting guidance should be considered and provided no new guidance in Issue No. 03-11. In Issue No. 03-11, the EITF did not provide transition guidance, which management could have interpreted as becoming applicable on October 1, 2003 for revenues from that date forward. However, management applied its conclusion on net or gross reporting to all periods presented to enhance comparability.

Select Energy reports the settlement of long-term derivative contracts that physically deliver and are not held for trading purposes on a gross basis, generally with sales in revenues and purchases in expenses. Short-term sales and purchases represent power that is purchased to serve full requirements contracts but is ultimately not needed based on the actual load of the full requirements customers. This excess power is sold to the independent system operator or to other counterparties. For the years ended December 31, 2004 and 2003, settlements of short-term derivative contracts that are

not held for trading purposes are reported on a net basis in expenses.

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

On June 25, 2003, the DIG cleared Issue No. C-20, which addressed the meaning of "not clearly and closely related regarding contracts with a price adjustment feature" as it relates to the election of the normal purchase and sales exception to derivative accounting. The implementation of this guidance was required for the fourth quarter of 2003 for NU. The implementation of Issue No. C-20 resulted in CL&P recording the fair value of two existing power purchase contracts as derivatives, one as a derivative asset, and one as a derivative liability. An offsetting regulatory liability and an offsetting regulatory asset were recorded, as these contracts are part of stranded costs, and management believes that these costs will continue to be recovered or refunded in rates.

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

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

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

Goodwill and Other Intangible Assets: SFAS No. 142, "Goodwill and Other Intangible Assets," requires that goodwill balances be reviewed for impairment at least annually by applying a fair value-based test. NU selected October 1st as the annual goodwill impairment testing date. The goodwill impairment analysis impacts the Yankee Gas and the NU Enterprises segment. 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 will be written-off to the extent it is impaired. This could have a significant impact on NU's consolidated financial statements.

NU has completed its impairment analyses as of October 1, 2004 for all reporting units that maintain goodwill and has determined that no impairments exist.

In performing the impairment evaluation required by SFAS No. 142, NU estimates the fair value of each reporting unit and compares it to the carrying amount of the reporting unit, including goodwill. NU estimates the fair values of its reporting units using discounted cash flow methodologies and an analysis of comparable companies or transactions. The discounted cash flow analysis requires the input of several critical assumptions, including future growth rates, operating cost escalation rates, allowed ROE, a risk-adjusted discount rate, and long-term earnings multiples of comparable companies. These assumptions are critical to the estimate and are susceptible to change from period to period.

Modifications to the aforementioned 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.

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

Results: Pre-tax periodic pension expense/income for the Pension Plan, excluding settlements, curtailments, and special termination benefits, totaled expense of $5.9 million, income of $31.8 million and income of $73.4 million for the years ended December 31, 2004, 2003 and 2002, respectively. The pension expense/income amounts exclude one-time items recorded under SFAS No. 88, "Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits."

As a result of litigation with nineteen former employees, in April 2004, NU was ordered by the court to modify its retirement 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. In the third quarter of 2004, NU withdrew its appeal of the court's ruling. As a result, NU recorded $2.1 million in special termination benefits related to this litigation in 2004.

There were no settlements, curtailments or special termination benefits recorded in 2003.

Net SFAS No. 88 items associated with early termination programs and the sale of the Millstone and Seabrook nuclear units totaled $22.2 million in income for the year ended December 31, 2002. This amount was recorded as a regulatory liability for refund to customers.

The pre-tax net PBOP Plan cost, excluding settlements, curtailments and special termination benefits, totaled $41.7 million, $35.1 million and $34.5 million for the years ended December 31, 2004, 2003 and 2002, respectively. The 2002 PBOP Plan cost excludes one-time items associated with the sale of the Seabrook nuclear units. These items totaled $1.2 million in income for the year ended December 31, 2002.

Long-Term Rate of Return Assumptions: In developing the expected long-term rate of return assumptions, NU evaluated input from actuaries and consultants, as well as long-term inflation assumptions and NU's historical 20-year compounded return of approximately 11 percent. NU's expected long-term rates of return on assets is based on certain target asset allocation assumptions and expected long-term rates of return. NU believes that 8.75 percent is a reasonable long-term rate of return on Pension Plan and PBOP Plan assets for 2004. NU will continue to evaluate the 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
	2004 and 2003		2004 and 2003
	Target Asset	Assumed Rate of	Target Asset	Assumed Rate of
Asset Category	Allocation	Return	Allocation	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, 2004 and 2003 approximated these target asset allocations. NU regularly 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 4A, "Employee Benefits - Pension Benefits and Postretirement Benefits Other Than Pensions," to the consolidated financial statements.

Actuarial Determination of Income and Expense: NU bases the actuarial determination of Pension Plan and PBOP Plan income/expense on a market-related valuation of assets, which reduces year-to-year volatility. This market-related valuation calculation recognizes investment gains or losses over a four-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the fair value of assets. Since the market-related valuation calculation recognizes gains or losses over a four-year period, the future value of the market-related assets will be impacted as previously deferred gains or losses are recognized. There will be no impact on the fair value of Pension Plan and PBOP Plan assets.

At December 31, 2004, the Pension Plan had cumulative unrecognized investment gains of $59 million, which will decrease pension expense over the next four years. At December 31, 2004, the Pension Plan had cumulative unrecognized actuarial losses of $413 million, which will increase pension expense over the expected future working lifetime of active Pension Plan participants, or approximately 13 years. The combined total of unrecognized investment gains and actuarial losses at December 31, 2004 is a net unrecognized loss of $354 million. These gains and losses impact the determination of pension expense and the actuarially determined prepaid pension amount recorded on the consolidated balance sheets but have no impact on expected Pension Plan funding.

At December 31, 2004, the PBOP Plan had cumulative unrecognized investment gains of $53 million, which will decrease PBOP Plan expense over the next four years. At December 31, 2004, the PBOP Plan also had cumulative unrecognized actuarial losses of $219 million, which will increase PBOP Plan expense over the expected future working lifetime of active PBOP Plan participants, or approximately 13 years. The combined total of unrecognized investment gains and actuarial losses at December 31, 2004 is a net unrecognized loss of approximately $166 million. These gains and losses impact the determination of PBOP Plan cost and the actuarially determined accrued PBOP Plan cost recorded on the consolidated balance sheets.

Discount Rate: The discount rate that is utilized in determining future pension and PBOP obligations is based on a yield-curve approach where each cash flow related to the Pension or PBOP 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, 2004. 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 6.00 percent for the Pension Plan and 5.50 percent for the PBOP Plan at December 31, 2004. Discount rates used at December 31, 2003 were 6.25 percent for the Pension Plan and the PBOP Plan.

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

	Pension Plan		Postretirement Plan
Year	Expected Contributions	Forecasted Expense	Expected Contributions	Forecasted Expense
2005	$ -	$41.5	$50.3	$50.3
2006	$ -	$50.6	$46.8	$46.8

2007

$ -

$38.1

$39.4

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

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

At December 31,

Pension Plan

Postretirement Plan

Assumption Change

2004

2003

2004

2003

Lower long-term

rate of return

$10.0

$10.7

$0.7

$0.9

Lower discount

rate

$13.4

$12.3

$1.0

Lower compensation

increase

$(5.8)

$(5.9)

N/A

Plan Assets: The market-related value of the Pension Plan assets has increased from $1.9 billion at December 31, 2003 to $2.1 billion at December 31, 2004. The projected benefit obligation (PBO) for the Pension Plan has increased from $1.9 billion at December 31, 2003 to $2.1 billion at December 31, 2004. These changes have decreased the funded status of the Pension Plan on a PBO basis from an overfunded position of $3.8 million at December 31, 2003 to an underfunded position of $57.7 million at December 31, 2004. The PBO includes expectations of future employee compensation increases. The accumulated benefit obligation (ABO) of the Pension Plan was approximately $225 million less than Pension Plan assets at December 31, 2004 and approximately $240 million less than Pension Plan assets at December 31, 2003. The ABO is the obligation for employee service and compensatio n provided through December 31, 2004. If the ABO exceeds Pension Plan assets at a future plan measurement date, NU will record an additional minimum liability. NU has not made employer contributions since 1991.

The value of PBOP Plan assets has increased from $178 million at December 31, 2003 to $199.8 million at December 31, 2004. The benefit obligation for the PBOP Plan has increased from $405 million at December 31, 2003 to $468.3 million at December 31, 2004. These changes have increased the underfunded status of the PBOP Plan on an accumulated projected benefit obligation basis from $227.1 million at December 31, 2003 to $268.5 million at December 31, 2004. NU has made a contribution each year equal to the PBOP Plan’s postretirement benefit cost, excluding curtailment, settlements and special termination benefits.

Health Care Cost: The health care cost trend assumption used to project increases in medical costs was 8 percent for 2004 and 9 percent for 2003, decreasing one percentage point per year to an ultimate rate of 5 percent in 2007. The effect of increasing the health care cost trend by one percentage point would have increased 2004 service and interest cost components of the PBOP Plan cost by $1 million in 2004 and $0.8 million in 2003.

Income Taxes: Income tax expense is calculated each year in each of the jurisdictions in which NU operates. This process involves estimating NU's actual current tax exposures as well as assessing temporary differences resulting from differing treatment of items, such as timing of the deduction and expenses for tax and book accounting purposes. These differences result in deferred tax assets and liabilities, which are included in NU's consolidated balance sheets. The income tax estimation process impacts all of NU's segments. Adjustments made to income taxes could significantly affect NU's consolidated financial statements. Management must also assess the likelihood that deferred tax assets will be recovered from future taxable income, and to the extent that recovery is not likely, a valuation allowance must be established. Significant management judgment is required in determin ing 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 $316.3 million and $253.8 million at December 31, 2004 and 2003, 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. Instead, the tax effect of the temporary difference impacts both amounts for income tax expense currently included in customers’ rates and the company’s net income. Flow through treatment can result in effective income tax rates that are significantly different than expected income tax rates. Recording deferred taxes on flow through items is required by SFAS No. 109, and the offset to the deferred tax amounts is the regulatory asset referred to above.

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

The estimates that are made by management in order to record income tax expense, accrued taxes and deferred taxes are compared each year to the actual tax amounts filed on NU’s income tax returns. The income tax returns were filed in the fall of 2004 for the 2003 tax year, and NU recorded differences between income tax expense, accrued taxes and deferred taxes on its consolidated financial statements and the amounts that were on its income tax returns.

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

Accounting for Environmental Reserves: Environmental reserves are accrued using a probabilistic model approach when assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated. Adjustments made to environmental liabilities could have a significant effect on earnings. The probabilistic model approach estimates the liability based on the most likely action plan from of 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 regulat ions and several cost estimates from outside engineering and remediation contractors. These amounts also take into consideration prior experience in remediating contaminated sites and data released by the United States Environmental Protection Agency and other organizations.

These estimates are subjective in nature partly because there are usually several different remediation options from which to choose when working on a specific site. These estimates are subject to revisions in future periods based on actual costs or new information concerning either the level of contamination at the site or newly enacted laws and regulations. The amounts recorded as environmental liabilities on the consolidated balance sheets represent management’s best estimate of the liability for environmental costs based on current site information from site assessments and remediation estimates. These liabilities are estimated on an undiscounted basis.

Under current rate-making policy, PSNH and Yankee Gas have regulatory recovery mechanisms in place for environmental costs. Accordingly, regulatory assets have been recorded for certain of PSNH’s and Yankee Gas’ environmental liabilities. As of December 31, 2004 and 2003, $28 million and $26.3 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 regulatory mechanism to recover environmental costs from its customers, and changes in WMECO's environmental reserves impact WMECO's earnings.

Capital expenditures related to environmental matters are expected to total approximately $104 million in aggregate for the years 2005 through 2009. Of the $104 million, approximately $55 million relates to the conversion of a 50 megawatt oil and coal burning unit at Schiller Station to a wood burning unit to, among other things, provide a reduction in air emissions at the plant and approximately $14 million relates to installing equipment to meet emission requirements at HWP's Mt. Tom coal-fired generating station. The remainder primarily relates to other environmental remediation programs associated with NU's hydroelectric generation assets.

Asset Retirement Obligations: NU adopted SFAS No. 143, "Accounting for Asset Retirement Obligations," on January 1, 2003. SFAS No. 143 requires that legal obligations associated with the retirement of property, plant and equipment be recorded as a liability on the balance sheet at fair value when incurred and when a reasonable estimate of the fair value can be made. SFAS No. 143 defines an asset retirement obligation (ARO) as a legal obligation that is required to be settled due to an existing or enacted law, statute, ordinance, or a written or oral promise to remove an asset. AROs may stem from environmental laws, state laws and regulations, easement agreements, building codes, contracts, franchise grants and agreements, oral promises made upon which third parties have relied, or the dismantlement, restoration, or reclamation of properties.

Upon adoption of SFAS No. 143, certain removal obligations were identified that management believes are AROs but either have not been incurred or are not material. These removal obligations arise in the ordinary course of business or have a low probability of occurring. The types of obligations primarily relate to transmission and distribution lines and poles, telecommunication towers, transmission cables and certain FERC or state regulatory agency re-licensing issues. There was no impact to NU's earnings upon adoption of SFAS No. 143; however, if there are changes in certain laws and regulations, orders, interpretations or contracts entered into by NU, there may be future AROs that need to be recorded.

On June 17, 2004, the FASB issued the proposed interpretation, "Accounting for Conditional Asset Retirement Obligations." The proposed interpretation 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 and clarifies that there are no circumstances in which a law or regulation obligates an entity to perform retirement activities but then allows the entity to permanently avoid settling the obligation.

If adopted in its current form, there may be an impact to NU for AROs that NU currently concludes have not been incurred (conditional obligations). These conditional obligations may include utility poles and asbestos that, if removed or disturbed by construction or demolition, creates a disposal obligation. Management is in the process of evaluating the impact of the interpretation on NU.

Under SFAS No. 71, regulated utilities, including NU's Utility Group companies, currently recover amounts in rates for future costs of removal of plant assets. Future removals of assets do not represent legal obligations and are not AROs. Historically, these amounts were included as a component of accumulated depreciation until spent. At December 31, 2004 and 2003, these amounts totaling $328.8 million and $334 million, respectively, are classified as regulatory liabilities on the accompanying consolidated balance sheets.

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

During 1999, SESI established an SPE, HEC/Tobyhanna Energy Project, LLC (HEC/Tobyhanna), in connection with a federal energy savings performance project located at the United States Army Depot in Tobyhanna, Pennsylvania. HEC/Tobyhanna sold $26.5 million of Certificates

related to the project and used the funds to repay SESI for the costs of the project. HEC/Tobyhanna's activities and Certificates are included in NU's consolidated financial statements.

Accounting Implications of NU Enterprises Comprehensive Business Review: The accounting for the business segments of NU Enterprises at December 31, 2004 assumed that those businesses are going concerns and will continue to be NU Enterprises' segments in the future. The comprehensive review of each of the NU Enterprises' businesses resulted in decisions that changed the existing going concern accounting conclusions for certain of those businesses on March 9, 2005. The impacts of the decisions could be material and could include:

The impairment of long-lived assets if they are no longer held and used and become held for sale at expected sales prices that are less than carrying values.

The impairment of goodwill if expected cash flows that support the fair values of the reporting units that hold goodwill are reduced significantly by a change in business strategy or a decision to sell all or portions of the reporting units at prices less than carrying values.

The impairment of intangible assets if expected cash flows that support them are reduced to below their carrying values.

The recognition of closure costs such as severance, benefit plan curtailments, and lease termination payments.

The recognition of losses associated with settling energy contracts currently accounted for on an accrual method of accounting that have negative fair values at the time of settlement.

The termination of the normal purchase and sales exception to fair value accounting for derivatives and the resulting recognition of losses or gains on changes in fair value of the contracts since inception.

The methods of implementing the company's decision involving the wholesale marketing and services businesses are under review. Accordingly, management cannot determine the amounts of impairments or other losses.

For further information regarding the matters in this "Critical Accounting Policies and Estimates" section, see Note 1, "Summary of Significant Accounting Policies," Note 3, "Derivative Instruments," Note 4, "Employee Benefits," Note 5, "Goodwill and Other Intangible Assets," and Note 6B, "Commitments and Contingencies - Environmental Matters," to the consolidated financial statements.

Other Matters

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

Contractual Obligations and Commercial Commitments: Information regarding NU’s contractual obligations and commercial commitments at December 31, 2004 is summarized through 2009 and thereafter as follows:

(Millions of

Dollars)

2005

2006

2007

2008

2009

Thereafter

Notes payable

to banks^(a)

$ 180.0

$ -

Long-term
debt^(a)

90.8

27.0

8.2

159.8

61.5

2,277.7

Estimated interest
payments on
existing debt

153.0

149.8

147.9

144.8

140.0

1,614.3

Capital
leases^(b)(c)

3.1

2.9

2.6

2.3

2.0

18.1

Operating
leases^(c)(d)

30.9

28.5

24.5

21.0

12.5

41.3

Required funding of
other post-

retirement benefit

obligations

50.3

46.8

39.4

29.6

21.4

N/A

Long-term
contractual
arrangements^(c)(d)

729.5

682.9

461.0

366.0

336.0

1,544.6

Select Energy
purchase
agreements^(c)(d)(e)

4,940.1

650.8

156.4

99.0

85.6

261.1

Totals

$6,177.7

$ 1,588.7

$840.0

$822.5

$659.0

$5,757.1

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

^(b) The capital lease obligations include imputed interest of $16.2 million.

^(c) NU has no provisions in its capital or operating lease agreements or agreements related to its long-term contractual arrangements or Select Energy purchase commitments that couldtrigger a change in terms and conditions, such as acceleration of payment obligations.

^(d) Amounts are not included on NU's consolidated balance sheets.

^(e) Select Energy's purchase agreement amounts can exceed the amount expected to be reported in fuel, purchased and net interchange power because energy trading purchases are classified in revenues.

Rate reduction bond amounts are non-recourse to NU, have no required payments over the next five years and are not included in this table. The Utility Group's standard offer service contracts and default service contracts also are not included in this table. The estimated payments under interest rate swap agreements are not included in this table as the estimated payment amounts are not determinable. For further information regarding NU’s contractual obligations and commercial commitments, see the Consolidated Statements of Capitalization and related footnotes, and Note 2, "Short-Term Debt," Note 6D, "Commitments and Contingencies - Long-Term Contractual Arrangements," and Note 9, "Leases," 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 t he forward looking statements include, but are not limited to, actions by state and federal regulatory bodies, competition and industry restructuring, changes in economic conditions, changes in weather patterns, changes in laws, regulations or regulatory policy, expiration or initiation of significant energy supply contracts, changes in levels of capital expenditures, developments in legal or public policy doctrines, technological developments, volatility in electric and natural gas commodity markets, effectiveness of our risk management policies and procedures, changes in accounting standards and financial reporting regulations, fluctuations in the value of electricity positions, changes in the ability to sell electricity positions and close out natural gas positions at anticipated margins, obtaining new contracts at anticipated volumes and margins, terrorist attacks on domestic energy facilities and other presently unknown or unforeseen factors. Other risk factors are detailed from time to time in our repo rts to the SEC. Management undertakes no obligation to update the information contained in any forward looking statements to reflect developments or circumstances occurring after the statement is made.

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

RESULTS OF OPERATIONS

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

Income Statement Variances	2004 over/(under) 2003		2003 over/(under) 2002
(Millions of Dollars)	Amount	Percent	Amount	Percent
Operating Revenues	$617	10%	$ 832	16 %

Operating Expenses:
Fuel, purchased and net interchange power	496	13	686	23
Other operation	131	14	138	17
Maintenance	13	8	(24)	(12)
Depreciation	20	10	(1)	(1)
Amortization	(53)	(28)	(129)	(40)
Amortization of rate reduction bonds	12	8	5	3
Taxes other than income taxes	10	4	5	2
Gain on sale of utility plant	-	-	187	100
Total operating expenses	629	11	867	18
Operating Income	(12)	(3)	(35)	(8)
Interest expense, net	7	3	(24)	(9)
Other income/(loss), net	15	(a)	(44)	(a)
Income before income tax expense	(4)	(2)	(55)	(24)
Income tax expense	1	2	(24)	(32)
Preferred dividends of subsidiaries	-	-	-	-
Income before cumulative effect of accounting changes	(5)	(4)	(31)	(20)
Cumulative effect of accounting changes, net of tax benefits	5	100	(5)	(100)
Net income/(loss)	$ -	-%	$ (36)	(23)%

(a) Percent greater than 100.

Operating Revenues

Total revenues increased $617 million in 2004, compared with 2003, due to higher revenues from NU Enterprises ($387 million), higher electric distribution revenues ($172 million), higher gas distribution revenues ($46 million) and higher regulated transmission revenues ($13 million).

The NU Enterprises’ revenue increase of $387 million is primarily due to higher revenues for the merchant retail energy business ($197 million), the 2003 revenue reduction recorded for the settlement of a wholesale power dispute associated with CL&P standard offer supply ($56 million), and an increased level of competitive energy services business ($42 million). Higher revenues for the merchant retail energy business resulted from higher electric volumes ($119 million), higher gas prices ($48 million), higher electric prices ($28 million), and higher gas volumes ($2 million). The competitive energy services business revenue increase resulted from higher revenues from a cogeneration project and higher volumes in the mechanical contracting group.

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

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

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

Total revenues increased $832 million in 2003, compared with 2002, due to higher revenues from NU Enterprises ($588 million), higher Utility Group electric revenues ($165 million) and higher Utility Group gas revenues ($79 million).

The NU Enterprises’ revenue increase of $588 million is primarily due to higher wholesale and retail requirements sales volumes ($386 million) and higher prices ($339 million).

The Utility Group revenue increase of $165 million is primarily due to higher retail electric revenue ($217 million), partially offset by lower wholesale revenue ($57 million). The regulated retail electric revenue increase is primarily due to higher CL&P recovery of incremental locational marginal pricing (LMP) costs net of amounts to be returned to customers ($72 million), higher sales volumes ($73 million), an adjustment to unbilled revenues ($46 million) and a higher average price resulting from the mix among customer classes for the regulated companies ($25 million). The

higher Yankee Gas revenue is primarily due to higher recovery of gas costs ($81 million) and higher gas sales volumes ($26 million), partially offset by an adjustment to unbilled revenues ($28 million). Regulated retail electric kWh sales increased by 2.1 percent and firm natural gas sales increased by 7.8 percent in 2003, before the adjustments to unbilled revenues. The regulated wholesale revenue decrease is primarily due to lower PSNH 2003 sales as a result of the sale of Seabrook.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expense increased $496 million in 2004, primarily due to higher wholesale costs at NU Enterprises ($224 million) and higher purchased power costs for the Utility Group ($272 million). The increase for the Utility Group is primarily due to an increase in the standard offer supply costs for CL&P ($152 million) and WMECO ($16 million), higher Yankee Gas expenses ($33 million) primarily due to increased gas prices, higher expenses for PSNH ($10 million) primarily due to higher energy and capacity purchases, partially offset by the 2003 CL&P recovery of certain fuel costs ($44 million).

Fuel, purchased and net interchange power expense increased $686 million in 2003, primarily due to higher wholesale energy purchases at NU Enterprises ($630 million) and higher gas costs ($77 million), partially offset by lower nuclear fuel ($20 million).

Other Operation

Other operation expenses increased $131 million in 2004, primarily due to higher expenses for NU Enterprises resulting from the increased volume in the contracting business ($71 million),higher CL&P RMR costs and other power pool related expenses ($71 million),higher PSNH fossil production expense ($6 million), and higher distribution expenses ($4 million), partially offset by lower C&LM expense ($20 million).

Other operation expense increased $138 million in 2003, primarily due to higher expenses for NU Enterprises resulting from service business growth ($59 million), higher regulated business administrative and general expenses primarily due to higher health care costs ($16 million), lower pension income ($31 million), higher RMR related transmission expense ($30 million), higher conservation and load management expenditures ($16 million), higher distribution expense ($6 million), and higher load and dispatch expenses ($6 million), partially offset by lower nuclear expense due to the sale of Seabrook ($29 million).

Maintenance

Maintenance expense increased $13 million in 2004, primarily due to higher expenses for NU Enterprises at its generating plants ($5 million), the absence of the 2003 positive resolution of the Millstone use of proceeds docket ($5 million) and higher electric distribution expenses ($5 million).

Maintenance expense decreased $24 million in 2003, primarily due to lower nuclear expense resulting from the sale of Seabrook ($26 million), partially offset by higher gas distribution expenses ($2 million).

Depreciation

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

Depreciation decreased $1 million in 2003 primarily due to lower decommissioning and depreciation expenses resulting from 2002 depreciation of Seabrook as compared to no 2003 Seabrook-related depreciation ($7 million) and lower NU Enterprises depreciation due to a study which resulted in lengthening the useful lives of certain generation assets ($3 million), partially offset by higher Utility Group depreciation resulting from higher plant balances ($9 million).

Amortization

Amortization decreased $53 million in 2004 primarily due to lower Utility Group recovery of stranded costs and a decrease in amortization expense resulting from the amortization of GSC over-recoveries allowed in the CL&P distribution rate case effective in January 2004 ($29 million).

Amortization decreased $129 million in 2003 primarily due to the 2002 amortization of stranded costs upon the sale of Seabrook ($183 million), partially offset by higher amortization in 2003 related to the Utility Group’s recovery of stranded costs ($62 million), in part resulting from higher wholesale revenue from the sale of IPP related energy.

Amortization of Rate Reduction Bonds

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

Amortization of rate reduction bonds increased $5 million in 2003 due to the repayment of principal.

Taxes Other Than Income Taxes

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

Taxes other than income taxes increased $5 million in 2003, primarily due to a credit recorded in 2002 recognizing a Connecticut sales and use tax audit settlement ($8 million), partially offset by a lower 2003 payment to compensate the Town of Waterford for lost property tax revenue as a result of the sale of Millstone ($3 million) and lower New Hampshire property taxes due to the sale of Seabrook ($2 million).

Gain on Sale of Utility Plant

Gain on the sale of utility plant decreased $187 million in 2003 due to the gain recognized in 2002 resulting from CL&P’s and North Atlantic Energy Corporation's (NAEC) sale of Seabrook ($187 million).

Interest Expense, Net

Interest expense, net increased $7 million in 2004 primarily due to the issuance of $75 million of ten-year notes at Yankee Gas in January 2004, the issuance of $50 million of thirty-year senior notes at WMECO in September 2004, and the issuance of $150 million of five-year notes at NU Parent in June 2003.

Interest expense, net decreased $24 million in 2003 primarily due to lower interest for the regulated subsidiaries resulting from lower rates ($12 million), lower interest at NU Parent as a result of the interest rate swap related to its $263 million fixed-rate senior notes ($8 million), capitalized interest on prepayments for generator interconnections ($4 million) and lower NAEC interest due to the retirement of debt ($3 million), partially offset by higher competitive business interest as a result of higher debt levels ($6 million).

Other Income/(Loss), Net

Other income/(loss), net increased $15 million in 2004 primarily due to the recognition, beginning in 2004, of a CL&P procurement fee approved in the TSO docket decision ($12 million).

Other (loss)/income, net decreased $44 million in 2003 primarily due to the 2002 elimination of certain reserves associated with NU’s ownership share of Seabrook ($25 million), 2002 Seabrook related gains ($15 million), lower equity in earnings from the Yankee companies in 2003 ($7 million), a higher level of donations in 2003 ($5 million), RMS losses recorded in 2003 ($4 million) and lower 2003 conservation and load management incentive income ($2 million), partially offset by 2002 investment write-downs ($18 million).

Income Taxes

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

Income tax expense increased by $1 million in 2004 due to higher reversal of prior flow-through depreciation and lower favorable adjustments to tax expense, partially offset by lower state income tax expense, due to increased state tax credits and favorable unitary apportionment.

Income tax expense decreased by $24 million in 2003, primarily due to lower taxable income.

Cumulative Effect of Accounting Change, Net of Tax Benefit

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

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.

Additionally, management is responsible for establishing and maintaining adequate internal controls over financial reporting. 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 inInternal 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 was ineffective as of December 31, 2004. Management identified a material weakness due to deficiencies in both the design and operating effectiveness of internal controls associated with the application of derivative accounting rules to certain wholesale natural gas contracts entered into by the wholesale marketing portion of NU Enterprises' merchant energy segment. NU filed a Form 8-K on January 26, 2005 to provide notice of the restatement of June 30, 2004 and September 30, 2004 reports on Form 10-Q due to this accounting error. Restatements amounted to an increase in net income of $1.1 million for the quarter ended June 30, 2004 and a decrease in net income of $47 million for the quarter ended September 30, 2004. Numerous account balances were affected by these material misstatements, primarily fuel, purchased and net interchange power, income tax expense, derivative assets, derivative liabilities, retained earnings, and accumulated other comprehensive income.

Accounting for derivative contracts is complex and requires a significant amount of judgment and interpretation of the rules. During the second and third quarters of 2004, management accounted for certain wholesale natural gas contracts using the accrual method of accounting. Using this method, changes in the fair value of the derivative contracts did not impact net income currently. As a result of further analysis performed through January 2005, management concluded that an error had been made in interpreting the derivative accounting rules. This misinterpretation led to a misapplication of the derivative accounting rules. These wholesale natural gas contracts should have been recorded at fair value with changes in fair value reflected currently in net income. The restatements discussed above were required in order to apply fair value accounting to these contracts. The material weakn ess occurred due to deficiencies in both the design and operating effectiveness of the internal control environment.

Management identified and is strengthening the effectiveness and design of internal controls related to this matter. During the first quarter of 2005, management is enhancing the effectiveness of internal controls by requiring additional documentation for each wholesale derivative transaction accounted for on an accrual basis. Management is also enhancing the design of internal controls, as follows. Accounting management will review and approve the accounting for all material transactions requiring accounting judgments. Accounting reporting relationships will be enhanced by having business unit controllers report to the corporate controller for accounting and financial reporting matters.

These control enhancements are being implemented in the first quarter of 2005. As a result, material misstatements in account balances and related disclosures associated with this material weakness are not expected in the future. However, until these controls or control enhancements are concluded to be operating effectively, management cannot determine if the material weakness described above will be eliminated.

This material weakness was discussed with the Audit Committee of the Board of Trustees and Deloitte & Touche LLP, our independent registered public accounting firm. Deloitte & Touche LLP, has issued an attestation report on management’s assessment of internal controls over financial reporting that can be found on the following page.

Reports of Independent Registered Public Accounting Firm

To the Board of Trustees and Shareholders of Northeast Utilities:

We have audited management’s assessment, included in the accompanying Company Report on Internal Controls Over Financial Reporting, that Northeast Utilities and subsidiaries (the “Company”) did not maintain effective internal control over financial reporting as of December 31, 2004, because of the effect of the material weakness identified in management’s assessment based on criteria established inInternal Control—Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible 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 management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial report ing based on our audit.

We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit 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 audit provides 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 directors, 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 g enerally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors 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.

A material weakness is a significant deficiency, or combination of significant deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. The following material weakness has been identified and included in management’s assessment: deficiencies existed in both the design and operating effectiveness of controls associated with the application of derivative accounting rules related to certain wholesale natural gas contracts entered into by the wholesale marketing portion of NU Enterprises’ merchant energy segment. These deficiencies resulted in restatements of net income included in the Company’s reports on Form 10-Q for June 30 and September 30, 2004 of $1.1 million and $47 million, respectively. Numerous account balances were affected by these material misstatements, primarily fuel, pu rchased and net interchange power, income tax expense, derivative assets, derivative liabilities, retained earnings, and accumulated other comprehensive income. Until these deficiencies are corrected, material misstatements in the account balances and related disclosures associated with this material weakness may occur. This material weakness was considered in determining the nature, timing, and extent of audit tests applied in our audit of the consolidated financial statements as of and for the year ended December 31, 2004, of the Company and this report does not affect our report on such financial statements.

In our opinion, management’s assessment that the Company did not maintain effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the criteria established inInternal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, because of the effect of the material weakness described above on the achievement of the objectives of the control criteria, the Company has not maintained effective internal control over financial reporting as of December 31, 2004, based on the criteria established inInternal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have not examined and, accordingly, we do not express an opinion or any other form of assurance on management’s statements in the fourth and fifth paragraphs of the Company Report on Internal Controls Over Financial Reporting.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2004, of the Company and our report dated March 16, 2005 expressed an unqualified opinion on those financial statements.

/s/	DELOITTE & TOUCHE LLP
	DELOITTE & TOUCHE LLP

Hartford, Connecticut

March 16, 2005

To the Board of Trustees and Shareholders of Northeast Utilities:

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Northeast Utilities and subsidiaries (a Massachusetts Trust) (the “Company”) as of December 31, 2004 and 2003, and the related consolidated statements of income, comprehensive income, shareholders’ equity and cash flows for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Northeast Utilities and subsidiaries as of December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

As discussed on Note 16 to the consolidated financial statements, in 2003, the Company adopted Financial Accounting Standards Board Interpretation No. 46,Consolidation of Variable Interest Entities.

As discussed in Note 16, the Company has restated the consolidated balance sheet as of December 31, 2003 and the related consolidated statement of cash flows for the year then ended.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004, based onInternal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 16, 2005 expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reportingand an adverse opinion on the effectiveness of the Company’s internal control over financial reporting because of a material weakness.

/s/	DELOITTE & TOUCHE LLP
	DELOITTE & TOUCHE LLP

Hartford, Connecticut

March16, 2005

NORTHEAST UTILITIES AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31,	2004	2003	2002
	(Thousands of Dollars, except share information)

Operating Revenues	$ 6,686,699	$ 6,069,156	$ 5,237,000
Operating Expenses:
Operation -
Fuel, purchased and net interchange power	4,231,192	3,735,154	3,048,813
Other	1,084,235	953,026	815,212
Maintenance	188,111	174,703	198,725
Depreciation	224,855	204,388	205,646
Amortization	138,271	191,805	320,409
Amortization of rate reduction bonds	164,915	153,172	148,589
Taxes other than income taxes	242,168	232,672	227,518
Gain on sale of utility plant	-	-	(187,113)
Total operating expenses	6,273,747	5,644,920	4,777,799
Operating Income	412,952	424,236	459,201

Interest Expense:
Interest on long-term debt	139,853	126,259	134,471
Interest on rate reduction bonds	98,899	108,359	115,791
Other interest	14,762	11,740	20,249
Interest expense, net	253,514	246,358	270,511
Other Income/(Loss), Net	14,465	(435)	43,828
Income Before Income Tax Expense	173,903	177,443	232,518
Income Tax Expense	51,756	50,732	74,850
Income Before Preferred Dividends of Subsidiary	122,147	126,711	157,668
Preferred Dividends of Subsidiary	5,559	5,559	5,559
Income Before Cumulative Effect of
Accounting Change, Net of Tax Benefit	116,588	121,152	152,109
Cumulative effect of accounting change,
net of tax benefit of $2,553 in 2003	-	(4,741)	-
Net Income	$ 116,588	$ 116,411	$ 152,109

Basic and Fully Diluted Earnings/(Loss) Per Common Share:
Income before cumulative effect of
accounting change, net of tax benefit	$ 0.91	$ 0.95	$ 1.18
Cumulative effect of accounting change,
net of tax benefit	-	(0.04)	-
Basic and Fully Diluted Earnings Per Common Share	$ 0.91	$ 0.91	$ 1.18
Basic Common Shares Outstanding (weighted average)	128,245,860	127,114,743	129,150,549
Fully Diluted Common Shares Outstanding (weighted average)	128,396,076	127,240,724	129,341,360

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

NORTHEAST UTILITIES AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


For the Years Ended December 31,	2004	2003	2002
	(Thousands of Dollars)

Net Income	$ 116,588	$ 116,411	$ 152,109
Other comprehensive (loss)/income, net of tax:
Qualified cash flow hedging instruments	(28,246)	9,274	52,360
Unrealized gains/(losses) on securities	1,191	2,093	(5,121)
Minimum supplemental executive retirement
pension liability adjustments	(156)	(303)	158
Other comprehensive (loss)/income, net of tax	(27,211)	11,064	47,397
Comprehensive Income	$ 89,377	$ 127,475	$ 199,506

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

NORTHEAST UTILITIES AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
	2004	2003 (Restated)*
(Thousands of Dollars) ASSETS

Current Assets:

Cash and cash equivalents	$ 46,989	$ 43,372
Restricted cash - LMP costs	-	93,630
Special deposits	82,584	79,120
Investments in securitizable assets	139,391	166,465
Receivables, less provision for uncollectible accounts
of $25,325 in 2004 and $40,846 in 2003	771,257	704,893
Unbilled revenues	144,438	125,881
Taxes receivable	61,420	-
Fuel, materials and supplies, at average cost	185,180	154,076
Derivative assets - current	81,567	116,305
Prepayments and other	154,395	63,780
	1,667,221	1,547,522
Property, Plant and Equipment:
Electric utility	5,918,539	5,465,854
Gas utility	786,545	743,990
Competitive energy	918,183	885,953
Other	241,190	221,986
	7,864,457	7,317,783
Less: Accumulated depreciation	2,382,927	2,244,263
	5,481,530	5,073,520
Construction work in progress	382,631	356,396
	5,864,161	5,429,916
Deferred Debits and Other Assets:
Regulatory assets	2,745,874	2,974,022
Goodwill	319,986	319,986
Purchased intangible assets, net	19,361	22,956
Prepaid pension	352,750	360,706
Prior spent nuclear fuel trust, at fair value	49,296	-
Derivative assets - long-term	198,769	132,812
Other	438,416	428,567
	4,124,452	4,239,049

Total Assets	$ 11,655,834	$ 11,216,487

* See Note 16.

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

NORTHEAST UTILITIES AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

		2003
At December 31,	2004	(Restated)*
	(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION

Current Liabilities:
Notes payable to banks	$ 180,000	$ 105,000
Long-term debt - current portion	90,759	64,936
Accounts payable	825,247	728,463
Accrued taxes	-	50,881
Accrued interest	49,449	41,653
Derivative liabilities - current	130,275	51,117
Counterparty deposits	57,650	46,496
Other	230,022	213,842
	1,563,402	1,302,388

Rate Reduction Bonds	1,546,490	1,729,960

Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	1,434,403	1,277,309
Accumulated deferred investment tax credits	99,124	102,652
Deferred contractual obligations	413,056	469,218
Regulatory liabilities	1,069,842	1,164,288
Derivative liabilities - long-term	58,737	61,495
Other	267,895	247,526
	3,343,057	3,322,488
Capitalization:
Long-Term Debt	2,789,974	2,481,331

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

Common Shareholders' Equity:
Common shares, $5 par value - authorized 225,000,000
shares; 151,230,981 shares issued and 129,034,442
shares outstanding in 2004 and 150,398,403 shares
issued and 127,695,999 shares outstanding in 2003	756,155	751,992
Capital surplus, paid in	1,116,106	1,108,924
Deferred contribution plan - employee stock
ownership plan	(60,547)	(73,694)
Retained earnings	845,343	808,932
Accumulated other comprehensive (loss)/income	(1,220)	25,991
Treasury stock, 19,580,065 shares in 2004
and 19,518,023 in 2003	(359,126)	(358,025)
Common Shareholders' Equity	2,296,711	2,264,120
Total Capitalization	5,202,885	4,861,651

Commitments and Contingencies (Note 7)
Total Liabilities and Capitalization	$ 11,655,834	$ 11,216,487
* See Note 16.

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	(Loss)/	Treasury
	Shares	Amount	Paid In	ESOP	Earnings	Income	Stock	Total
	(Thousands of Dollars, except share information)
Balance as of
January 1, 2002	130,132,136	$ 744,453	$ 1,107,609	$ (101,809)	$ 678,460	$ (32,470)	$(278,603)	$ 2,117,640
Net income for 2002					152,109			152,109
Cash dividends on common
shares - $0.525 per share					(67,793)			(67,793)
Issuance of common shares, $5 par value	485,207	2,426	5,032					7,458
Allocation of benefits - ESOP	607,475		(6,410)	14,063	2,835			10,488
Restricted shares, net	(11,887)		1,731				(151)	1,580
Repurchase of common shares	(3,650,900)						(58,734)	(58,734)
Capital stock expenses, net			376					376
Other comprehensive income						47,397		47,397
Balance as of
December 31, 2002	127,562,031	746,879	1,108,338	(87,746)	765,611	14,927	(337,488)	2,210,521
Net income for 2003					116,411			116,411
Cash dividends on common
shares - $0.575 per share					(73,090)			(73,090)
Issuance of common shares, $5 par value	1,022,556	5,113	8,541					13,654
Allocation of benefits - ESOP	607,020		(4,030)	14,052				10,022
Restricted shares, net	(7,508)		(4,110)				(99)	(4,209)
Repurchase of common shares	(1,638,100)						(23,210)	(23,210)
Issuance of treasury shares	150,000						2,772	2,772
Capital stock expenses, net			185					185
Other comprehensive income						11,064		11,064
Balance as of
December 31, 2003	127,695,999	751,992	1,108,924	(73,694)	808,932	25,991	(358,025)	2,264,120
Net income for 2004					116,588			116,588
Cash dividends on common
shares - $0.625 per share					(80,177)			(80,177)
Issuance of common shares, $5 par value	832,578	4,163	6,774					10,937
Allocation of benefits - ESOP	567,907		(2,384)	13,147				10,763
Restricted shares, net	(62,042)		1,250				(1,101)	149
Tax deduction for stock options exercised and Employee Stock Purchase Plan disqualifying dispositions			1,356					1,356
Capital stock expenses, net			186					186
Other comprehensive income						(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
The accompanying notes are an integral part of these consolidated financial statements.

NORTHEAST UTILITIES AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

		2003
For the Years Ended December 31,	2004	*Restated	2002
	(Thousands of Dollars)

Operating Activities:
Income before preferred dividends of subsidiary	$ 122,147	$ 126,711	$ 157,668
Adjustments to reconcile to net cash flows
provided by operating activities:
Bad debt expense	19,062	23,229	16,590
Depreciation	224,855	204,388	205,646
Deferred income taxes and investment tax credits, net	111,710	(129,733)	(156,780)
Amortization	138,271	191,805	320,409
Amortization of rate reduction bonds	164,915	153,172	148,589
(Deferral)/amortization of recoverable energy costs	(22,751)	20,486	27,623
Gain on sale of utility plant	-	-	(187,113)
Pension expense/(income)	10,636	(16,416)	(47,192)
Cumulative effect of accounting change	-	(4,741)	-
Regulatory (refunds)/overrecoveries	(150,119)	287,974	27,061
Mark-to-market on natural gas contracts	48,346	-	-
Other sources of cash	51,213	20,002	94,039
Other uses of cash	(114,210)	(192,097)	(170,671)
Changes in current assets and liabilities:
Restricted cash - LMP costs	93,630	(93,630)	-
Receivables and unbilled revenues, net	(103,983)	39,322	(118,771)
Fuel, materials and supplies	(31,104)	(34,223)	(27,590)
Investments in securitizable assets	27,074	12,443	27,459
Natural gas mark-to-market deposit	(77,607)	-	-
Other current assets	(109,235)	8,285	57,885
Accounts payable	96,784	(30,866)	166,298
Accrued taxes	(50,880)	(83,625)	107,134
Other current liabilities	68,313	90,928	(32,505)
Net cash flows provided by operating activities	517,067	593,414	615,779

Investing Activities:
Investments in property and plant:
Electric, gas and other utility plant	(626,173)	(545,917)	(489,528)
Competitive energy assets	(17,649)	(17,707)	(21,010)
Cash flows used for investments in property and plant	(643,822)	(563,624)	(510,538)
Investments in nuclear decommissioning trusts	-	-	(9,876)
Net proceeds from sale of utility plant	-	-	366,786
Buyout/buydown of IPP contracts	-	(20,437)	(5,152)
Investment in prior spent nuclear fuel trust	(49,296)	-	-
Payment for acquisitions, net of cash acquired	-	-	(16,351)
CVEC acquisition special deposit	-	(30,104)	-
Other investment activities	23,131	21,698	14,769
Net cash flows used in investing activities	(669,987)	(592,467)	(160,362)

Financing Activities:
Issuance of common shares	10,937	13,654	7,458
Repurchase of common shares	-	(20,537)	(57,800)
Issuance of long-term debt	512,762	268,368	310,648
Issuance of rate reduction bonds	-	-	50,000
Retirement of rate reduction bonds	(183,470)	(169,352)	(169,039)
Increase/(decrease) in short-term debt	75,000	49,000	(234,500)
Reacquisitions and retirements of long-term debt	(155,532)	(65,600)	(314,773)
Cash dividends on preferred stock of subsidiaries	(5,559)	(5,559)	(5,559)
Cash dividends on common shares	(80,177)	(73,090)	(67,793)
Other financing activities	(17,424)	(4,792)	(736)
Net cash flows provided by/(used in) financing activities	156,537	(7,908)	(482,094)
Net increase/(decrease) in cash and cash equivalents	3,617	(6,961)	(26,677)
Cash and cash equivalents - beginning of period	43,372	50,333	77,010
Cash and cash equivalents - end of period	$ 46,989	$ 43,372	$ 50,333

* See Note 16.
The accompanying notes are an integral part of these consolidated financial statements.

Consolidated Statements of Capitalization
		At December 31,
(Thousands of Dollars)		2004	2003
Common Shareholders’ Equity		2,296,711	2,264,120
Preferred Stock:
CL&P Preferred Stock Not Subject to Mandatory Redemption - $50 par value – authorized 9,000,000 shares in 2004 and 2003; 2,324,000 shares outstanding in 2004 and 2003; Dividend rates of $1.90 to $3.28: Current redemption prices of $50.50 to $54.00		116,200	116,200
Long-Term Debt: First Mortgage Bonds:
Final Maturity	Interest Rates
2005	5.00% to 6.75%	57,500	89,000
2009-2012	6.20% to 7.19%	80,000	80,000
2014	4.80% to 5.25%	275,000	-
2019-2024	7.88% to 10.07%	209,845	254,045
2026-2034	5.75% to 8.81%	450,000	320,000
Total First Mortgage Bonds		1,072,345	743,045
Other Long-Term Debt: Pollution Control Notes
2016-2018	5.90%	25,400	25,400
2021-2022	Adjustable Rate and 5.45% to 6.00%	428,285	428,285
2028	5.85% to 5.95%	369,300	369,300
2031	3.35% until 2008	62,000	62,000
Other:
2005-2007	6.11% to 8.81%	50,795	76,249
2008	3.30%	150,000	150,000
2010-2015	5.00% to 9.24%	328,694	329,582
2018-2019	6.00% to 6.23%	37,345	38,476
2020-2022	6.23% to 7.63%	41,581	39,461
2024-2026	6.23% to 7.69%	9,336	35,532
2034	5.90%	50,000	-
Total Pollution Control Notes and Other		$1,552,736	1,554,285
Total First Mortgage Bonds, Pollution Control Notes and Other		2,625,081	2,297,330
Fees and interest due for spent nuclear fuel disposal costs		259,707	256,438
Change in Fair Value		91	(3,577)
Unamortized premium and discount, net		(4,146)	(3,924)
Total Long-Term Debt		2,880,733	2,546,267
Less: Amounts due within one year		90,759	64,936
Long-Term Debt, Net		2,789,974	2,481,331
Total Capitalization		$5,202,885	$4,861,651

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

Notes To Consolidated Financial Statements

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

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

Utility Group: The Utility Group furnishes franchised retail electric service in Connecticut, New Hampshire and Massachusetts through three companies: The Connecticut Light and Power Company (CL&P), Public Service Company of New Hampshire (PSNH) and Western Massachusetts Electric Company (WMECO). Another company, North Atlantic Energy Corporation (NAEC), previously sold all of its entitlement to the capacity and output of the Seabrook nuclear unit (Seabrook) to PSNH under the terms of two, life-of-unit, full cost recovery contracts (Seabrook Power Contracts). Seabrook was sold on November 1, 2002. Another Utility Group subsidiary is Yankee Gas Services Company (Yankee Gas), which is Connecticut’s largest natural gas distribution system. The Utility Group includes three reportable business segments: the regulated electric utility distribution segment, the regulated gas utility distribution segment and the regulated electric utility transmission segment.

Effective January 1, 2004, PSNH completed the purchase of the electric system and retail franchise of Connecticut Valley Electric Company (CVEC), a subsidiary of Central Vermont Public Service Corporation (CVPS), for $30.1 million. CVEC's 11,000 customers in western New Hampshire have been added to PSNH’s customer base of more than 460,000 customers. The purchase price included the book value of CVEC's plant assets of approximately $9 million and an additional $21 million to terminate an above-market wholesale power purchase agreement CVEC had with CVPS. The $21 million payment is being recovered from PSNH’s customers.

NU Enterprises: NU Enterprises, Inc. is the parent company of Northeast Generation Company (NGC), Northeast Generation Services Company (NGS), Select Energy, Inc. (Select Energy), Select Energy Services, Inc. (SESI) and their respective subsidiaries, and Woods Network Services, Inc. (Woods Network), all of which are collectively referred to as "NU Enterprises." The generation operations of Holyoke Water Power Company (HWP) are also included in the results of NU Enterprises. The companies included in the NU Enterprises segment are grouped into two business segments: the merchant energy segment and the energy services business segment. The merchant energy business segment is comprised of Select Energy’s wholesale marketing business, which includes approximately 1,296 megawatts (MW) of pumped storage and hydroelectric generation assets owned by NGC, 147 MW of coal-fired generati on assets owned by HWP, and Select Energy's retail marketing business.

The energy services and other business segment includes the operations of SESI, NGS, and Woods Network. SESI performs energy management services for large commercial customers, institutional facilities and the United States government and energy-related construction services. NGS operates and maintains NGC's and HWP's generation assets and provides third-party electrical services. Woods Network is a network design, products and services company.

For information regarding NU's business segments, see Note 15, "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 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 contingencies at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Subsequent to the filing of its 2003 Form 10-K and annual report, NU concluded that it incorrectly classified as unrestricted cash from counterparties amounts that should have been classified as cash and cash equivalents at December 31, 2003. These corrections reclassified unrestricted cash from counterparties to cash and cash equivalents because those funds were unrestricted and were used to fund or were available to fund the company's operations. The December 31, 2003 consolidated balance sheet has been restated for these corrections and a correction to decrease derivative assets and liabilities by the same amount in order to eliminate intercompany derivative assets and liabilities. See Note 16, "Restatement of Previously Issued Financial Statements," to the consolidated financial statements for further information.

Additionally, certain reclassifications of prior year's data have been made to conform with the current year's presentation. See Note 16 for the effects of the significant reclassifications.

New Accounting Standards

Other-Than-Temporary Impairments: The Emerging Issues Task Force (EITF) of the Financial Accounting Standards Board (FASB) issued and later deferred the effective date of accounting guidance in EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary Impairment and Its

Application to Certain Investments." EITF Issue No. 03-1 provides guidance on how to evaluate and recognize an impairment loss that is other-than-temporary and could impact NU's investments in Acumentrics Corporation (Acumentrics) and NEON Communications, Inc. (NEON) upon its effective date. Certain accounting guidance included in EITF Issue No. 03-1 is not effective until the FASB concludes on this issue. EITF Issue No. 03-1 also requires certain annual disclosures, which are included in this annual report.

For information regarding these disclosures see Note 1J, "Summary of Significant Accounting Policies - Other Investments" and Note 8, "Marketable Securities," to the consolidated financial statements.

Share-Based Payments: On December 16, 2004, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 123 (Revised 2004), "Share-Based Payments," (SFAS No. 123R), which amended SFAS No. 123, "Accounting for Stock-Based Compensation." SFAS No. 123R requires all companies to recognize compensation expense in an amount equal to the fair value of share-based payments granted to employees. NU has elected to apply SFAS No. 123R on a modified prospective method. Under this method, NU will recognize compensation expense for the unvested portion of previously granted awards that remain outstanding on July 1, 2005, the effective date of SFAS No. 123R, and any new awards after that date. NU is currently evaluating the impact of SFAS No. 123R, but management believes that the adoption of SFAS No. 123R will not have a material impact on NU's consolidated financial statements.

For further information regarding equity-based compensation, see Note 1N, "Equity-Based Compensation," to the consolidated financial statements.

Accounting for the Effect of Medicare Changes on Postretirement Benefits Other Than Pension (PBOP):On December 8, 2003, the President of the United States signed into law a bill that expands Medicare, primarily by adding a prescription drug benefit and by adding a federal subsidy to qualifying plan sponsors of retiree health care benefit plans. NU chose to reflect the impact on December 31, 2003 reported amounts with no impact on 2003 expenses, assets, or liabilities.

On May 19, 2004, the FASB issued Staff Position (FSP) No. FAS 106-2, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003," to provide guidance on accounting for the effects of the aforementioned Medicare expansion. This FSP concludes that the effects of the federal subsidy should be considered an actuarial gain and treated like similar gains and losses and requires certain disclosures for employers that sponsor postretirement health care plans that provide prescription drug benefits which are included in this annual report. The accounting treatment under FSP No. FAS 106-2 is consistent with NU's accounting treatment at December 31, 2003 and reduced the projected benefit obligation by $7.5 million and $19.5 million in 2004 and 2003, respectively.

Consolidation of Variable Interest Entities: In December 2003, the FASB issued a revised version of FASB Interpretation No. (FIN) 46, "Consolidation of Variable Interest Entities," (FIN 46R). FIN 46R resulted in fewer NU investments meeting the definition of a variable interest entity (VIE). FIN 46R was effective for NU for the first quarter of 2004 and did not have an impact on NU's consolidated financial statements.

Guarantees

NU provides credit assurance in the form of guarantees and letters of credit in the normal course of business, primarily for the financial performance obligations of NU Enterprises. NU would be required to perform under these guarantees in the event of non-performance by NU Enterprises, primarily Select Energy. At December 31, 2004, the maximum level of exposure in accordance with FIN 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others," under guarantees by NU, primarily on behalf of NU Enterprises, totaled $1.1 billion. A majority of these guarantees do not have established expiration dates. For the guarantees with expiration dates, most are due to expire by December 31, 2005. Additionally, NU had $48.9 million of letters of credit issued, of which $33.9 million were issued for the benefit of NU Enterprise s at December 31, 2004.

At December 31, 2004, NU had outstanding guarantees on behalf of the Utility Group of $12.7 million. This amount is included in the total outstanding NU guarantee exposure amount of $1.1 billion.

Several underlying contracts that NU guarantees and 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.

NU currently has authorization from the SEC to provide up to $750 million of guarantees for NU Enterprises through June 30, 2007. The $12.7 million in guarantees to the Utility Group are subject to a separate $50 million SEC limitation apart from the current $750 million guarantee limit. The amount of guarantees outstanding for compliance with the SEC limit for NU Enterprises at December 31, 2004 is $358.6 million, which is calculated using different, more probabilistic and fair-value based criteria than the maximum level of exposure required to be disclosed under FIN 45. FIN 45 includes all exposures even though they are not reasonably likely to result in exposure to NU.

On October 19, 2004, the SEC authorized NU to issue guarantees of up to an aggregate $100 million through June 30, 2007 of the debt or other obligations of two of its subsidiaries, NUSCO and Rocky River Realty Company. These companies provide certain specialized support and real estate services and occasionally enter into transactions that require financial backing from NU parent. The amount of guarantees outstanding for compliance with the SEC limit under this category at December 31, 2004 is $0.2 million.

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.

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 been billed. Unbilled revenues are assets on the balance sheet that become 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 requirements method. The requirements method utilizes the total monthly volume of electricity or gas delivered to the system and applies a delivery efficiency (DE) factor to reduce the total monthly volume by an estimate of delivery losses in order to calculate total estimated monthly sales to customers. The total estimated monthly sales amount less the total monthly billed sales amount results in a monthly estimate of 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 estimated DE factor can have a significant impact on estimated unbilled revenue amounts.

In accordance with management's policy of testing the estimate of unbilled revenues twice each year using the cycle method of estimating unbilled revenues, testing was performed in the second and fourth quarters of 2004 but did not have a material impact on earnings. The cycle method uses the billed sales from each meter reading cycle and an estimate of unbilled days in each month based on the meter reading schedule. The cycle method is more accurate than the requirements method when used in a mostly weather-neutral month.

Utility Group Transmission Revenues: Wholesale transmission revenues are based on rates and formulas that are approved by the FERC. Most of NU’s wholesale transmission revenues are collected through a combination of the New England Regional Network Service (RNS) tariff and NU’s Local Network Service (LNS) tariff. The RNS tariff, which is administered by the New England Independent System Operator, recovers the revenue requirements associated with transmission facilities that are deemed by the FERC to be regional facilities. This regional rate is reset on June 1st of each year. The LNS tariff provides for the recovery of NU’s total transmission revenue requirements, net of revenues received from other sources, including those revenues received under RNS rates. NU’s LNS tariff is also reset on June 1st of each year to coincide with the change in RNS rates. Add itionally, NU’s LNS tariff provides for a true-up to actual costs which ensures that NU recovers its total transmission revenue requirements, including an allowed ROE.

A significant portion of NU's transmission businesses' revenue is from charges to NU's distribution businesses. These distribution businesses recover these charges through rates charged to their retail customers. WMECO has a rate tracking mechanism to track transmission costs charged in distribution rates to the actual amount of transmission charges incurred. The 2004 rates set in the CL&P distribution rate case contained a level of transmission revenue sufficient to recover CL&P's anticipated 2004 transmission costs. The June 1, 2005 PSNH retail rate increase includes revenues to recover expected transmission costs. Neither CL&P nor PSNH have transmission cost tracking mechanisms.

NU Enterprises: NU Enterprises' revenues are recognized at different times for its different business lines. Wholesale and retail marketing revenues are recognized when energy is delivered. Trading revenues are recognized as the fair value of trading contracts changes. Service revenues are recognized as services are provided, often on a percentage of completion basis.

Derivative Accounting

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

EITF Issue No. 03-11: In August of 2003, the FASB ratified the consensus reached by its EITF in July 2003 on EITF Issue No. 03-11, "Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ as Defined in Issue No. 02-3." Prior to Issue No. 03-11, no specific guidance existed to address the classification in the income statement of derivative contracts that are not held for trading purposes. The consensus stated that determining whether realized gains and losses on contracts that physically deliver and are not held for trading purposes should be reported on a net or gross basis was a matter of judgment that depended on the relevant facts and circumstances. NU Enterprises and the Utility Group have derivative sales contracts, and though these contracts may result in physical delivery, management has determined, based on the relevant facts and circumstances, that because these transactions are part of the respective companies’ procurement activities, inclusion in operating expenses better depicts these sales activities. At December 31, 2004, 2003 and 2002, the settlement of these derivative contracts that are not held for trading purposes are reported on a net basis in expenses.

In EITF Issue No. 03-11, the EITF did not provide transition guidance, which management could have interpreted as becoming applicable on October 1, 2003 for revenues from that date forward. However, management applied its conclusion on net or gross reporting to all periods presented to enhance comparability. Operating revenues and fuel, purchased and net interchange power for the years ended December 31, 2004, 2003 and 2002 reflect net reporting. The adoption of net reporting had no effect on net income.

Accounting for Energy Contracts: The accounting treatment for energy contracts entered into varies between contracts and depends on the intended use of the particular contract and on whether or not the contracts are derivatives.

Non-derivative contracts are recorded at the time of delivery or settlement.

Most of the contracts comprising Select Energy's wholesale and retail marketing activities are derivatives. The application of derivative accounting under SFAS No. 133, as amended, is complex and requires management's judgment. Judgment is applied in the election and designation of the normal purchases and sale exception (and resulting accounting upon delivery or settlement), which 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 accounting upon delivery or settlement would be terminated and fair value accounting would be applied.

Both long-term non-derivative contracts and long-term derivative contracts that are normal are recorded in revenues when these contracts represent sales, and recorded in fuel, purchased and net interchange power when these contracts represent purchases, except for sales contracts that relate to procurement activities. These contracts are recorded in fuel, purchased and net interchange power when settled.

Derivative contracts that are entered into for trading purposes are recorded on the consolidated balance sheets at fair value, and changes in fair value impact earnings. Revenues and expenses for these contracts are recorded on a net basis in revenues. Derivative contracts that are not held for trading purposes and that do not qualify as normal purchases and sales or hedges are non-trading derivative contracts. These contracts are recorded on the consolidated balance sheets at fair value, and changes in fair value for these contracts are recorded primarily in expenses.

Contracts that are hedging an underlying transaction and that qualify as 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. 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.

For further information regarding these contracts and their accounting, see Note 3, "Derivative Instruments," to the consolidated financial statements.

Utility Group 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. New Hampshire's electric utility industry restructuring laws have been modified to delay the sale of PSNH’s fossil and hydroelectric generation assets until at least April of 2006. There has been no regulatory action to the contrary, and management currently has no plans to divest of these generation assets. As the New Hampshire Public Utilities Commission (NHPUC) has allowed and is expected to continue to allow rate recovery of a return on and recovery of these assets, as well as all operating expenses, PSNH meets the criteria for the application of SFAS No. 71. Stranded costs related to generation assets, to the extent not currently recovered in rates, are deferred as Part 3 str anded costs under the "Agreement to Settle PSNH Restructuring" (Restructuring Settlement). Part 3 stranded costs are non-securitized regulatory assets that must be recovered by a recovery end date determined in accordance with the Restructuring Settlement or be written off.

Management believes the application of SFAS No. 71 to the portions of those businesses continues to be appropriate. Management also believes it is probable that NU’s Utility Group companies will recover their investments in long-lived assets, including regulatory assets. In addition, all material net regulatory assets are earning an equity return, except for securitized regulatory assets, which are not supported by equity.

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

At December 31,
(Millions of Dollars)	2004	2003
Recoverable nuclear costs	$ 52.0	$ 82.4
Securitized assets	1,537.4	1,721.1
Income taxes, net	316.3	253.8
Unrecovered contractual obligations	354.7	378.6
Recoverable energy costs	255.0	255.7
Other	230.5	282.4
Totals	$2,745.9	$2,974.0

Additionally, the Utility Group had $11.6 million and $12.3 million of regulatory costs at December 31, 2004 and 2003, respectively, that are included in deferred debits and other assets - other on the accompanying consolidated balance sheets. These amounts represent regulatory costs that have not yet been approved by the applicable regulatory agency. Management believes that these costs are recoverable in future rates.

Recoverable Nuclear Costs: In March of 2001, CL&P and WMECO sold their ownership interests in the Millstone nuclear units (Millstone). The gains on the sale in the amounts of approximately $521.6 million and $119.8 million, respectively, for CL&P and WMECO were used to offset recoverable nuclear costs. These unamortized recoverable nuclear costs amounted to $22.5 million at December 31, 2003, and were fully recovered by December 31, 2004. Additionally, PSNH recorded a regulatory asset in conjunction with the sale of Millstone 3 with an unamortized balance of $29.7 million and $33.3 million at December 31, 2004 and 2003, respectively, which is included in recoverable nuclear costs. Also included in recoverable nuclear costs for 2004 and 2003 are $22.3 million and $26.6 million, respectively, primarily related to Millstone 1 recoverable nuclear costs associated wi th the undepreciated plant and related assets at the time Millstone 1 was shutdown.

Securitized Assets: In March 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 $850 million and $960.5 million at December 31, 2004 and 2003, 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 a balance remaining of $144.3 million and $163.2 million at December 31, 2004 and 2003, respectively.

In April 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 power contracts with NAEC. The remaining PSNH securitized asset balance is $392.2 million and $427.5 million at December 31, 2004 and 2003, respectively.

In January 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 2001. The remaining PSNH securitized asset balance for the January 2002 issuance is $29.4 million and $37.9 million at December 31, 2004 and 2003, respectively. In May 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 remaining WMECO securitized asset balance is $121.5 million and $132 million at December 31, 2004 and 2003, respectively.

Securitized assets are being recovered over the amortization period of their associated rate reduction certificates and bonds. All outstanding rate reduction certificates of CL&P are scheduled to 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. For further information regarding income taxes, see Note 1H, "Summary of Significant Accounting Policies - Income Taxes," to the consolidated financial statements.

Unrecovered Contractual Obligations: CL&P, WMECO and PSNH, under the terms of contracts with the Yankee Companies, are responsible for their proportionate share of the remaining costs of the units, including decommissioning. These amounts are recorded as unrecovered contractual obligations. A portion of these obligations for CL&P was securitized in 2001 and is included in securitized regulatory assets. Amounts for PSNH are being recovered along with other stranded costs. See Note 6E, "Deferred Contractual Obligations" for additional information.

Recoverable Energy Costs: Under the Energy Policy Act of 1992 (Energy Act), CL&P, PSNH, WMECO, and NAEC were assessed for their proportionate shares of the costs of decontaminating and decommissioning uranium enrichment plants owned by the United States Department of Energy (DOE) (D&D Assessment). The Energy Act requires that regulators treat D&D Assessments as a

reasonable and necessary current cost of fuel, to be fully recovered in rates like any other fuel cost. CL&P, PSNH and WMECO no longer own nuclear generation but continue to recover these costs through rates. At December 31, 2004 and 2003, NU’s total D&D Assessment deferrals were $13.9 million and $18 million, respectively, and have been recorded as recoverable energy costs. Also included in recoverable energy costs at December 31, 2004, is $32.5 million related to Federally Mandated Congestion Charges. During 2003, CL&P paid for a temporary generation resource in southwest Connecticut to help maintain reliability. Costs for this resource of $15.8 million were recorded as recoverable energy costs at December 31, 2003.

In conjunction with the implementation of restructuring under the Restructuring Settlement on May 1, 2001, PSNH's fuel and purchased-power adjustment clause (FPPAC) was discontinued. At December 31, 2004 and 2003, PSNH had $144.8 million and $162.2 million, respectively, of recoverable energy costs deferred under the FPPAC. Under the Restructuring Settlement, the FPPAC deferrals are recovered as a Part 3 stranded cost through a stranded cost recovery charge. Also included in PSNH's recoverable energy costs are deferred costs associated with certain contractual purchases from IPPs. These costs are also treated as Part 3 stranded costs and amounted to $50.1 million and $56.1 million at December 31, 2004 and 2003, respectively.

The regulated rates of Yankee Gas include a purchased gas adjustment clause under which gas costs above or below base rate levels are charged to or credited to customers. Differences between the actual purchased gas costs and the current rate recovery are deferred and recovered or refunded in future periods. These amounts are recorded as recoverable energy costs of $13.7 million and $2.9 million at December 31, 2004 and 2003, respectively.

The majority of the recoverable energy costs are currently recovered in rates from the customers of CL&P, PSNH, WMECO, and Yankee Gas. PSNH's recoverable energy costs are Part 3 stranded costs which are non-securitized regulatory assets which must be recovered by a recovery end date determined in accordance with the Restructuring Settlement or be written off. Based on current projections, PSNH expects to fully recover all of its Part 3 costs by the recovery end date.

Regulatory Liabilities: The Utility Group had $1.1 billion and $1.2 billion of regulatory liabilities at December 31, 2004 and 2003, respectively. These amounts are comprised of the following:

At December 31,
(Millions of Dollars)	2004	2003
Cost of removal	$ 328.8	$ 334.0
CL&P CTA, GSC, and SBC overcollections	200.0	333.7
PSNH cumulative deferrals - SCRC	208.6	160.4
Regulatory liabilities offsetting
Utility Group derivative assets	191.4	117.0
Other regulatory liabilities	141.0	219.2
Totals	$1,069.8	$1,164.3

Under SFAS No. 71, regulated utilities, including NU's Utility Group companies, currently recover amounts in rates for future costs of removal of plant assets. Historically, these amounts were included as a component of accumulated depreciation until spent. These amounts are classified as regulatory liabilities on the accompanying consolidated balance sheets in accordance with SFAS No. 143, "Accounting for Asset Retirement Obligations."

The Competitive Transition Assessment (CTA) allows CL&P to recover stranded costs, such as securitization costs associated with the rate reduction bonds, amortization of regulatory assets, and IPP over market costs while the Generation Service Charge (GSC) allows CL&P to recover the costs of the procurement of energy for standard offer service. The System Benefits Charge (SBC) allows CL&P to recover certain regulatory and energy public policy costs, such as public education outreach costs, hardship protection costs, transition period property taxes, and displaced workers protection costs. The Stranded Cost Recovery Charge (SCRC) allows PSNH to recover its stranded costs.

The regulatory liabilities offsetting derivative assets relate primarily to the fair value of CL&P IPP contracts and PSNH purchase and sales contracts used for market discovery of future procurement activities that will benefit ratepayers in the future.

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 expense are as follows:

	For the Years Ended December 31,
(Thousands of Dollars)	2004	2003	2002
The components of the federal and state income tax provisions are:
Current income taxes:
Federal	$(53,531)	$ 143,349	$ 197,426
State	(6,422)	37,116	34,204
Total current	(59,953)	180,465	231,630
Deferred income taxes, net
Federal	120,285	(90,005)	(114,597)
State	(4,768)	(35,909)	(15,591)
Total deferred	115,517	(125,914)	(130,188)
Investment tax credits, net	(3,808)	(3,819)	(26,592)
Total income tax expense	$ 51,756	$ 50,732	$ 74,850
A reconciliation between income tax expense and the expected tax expense at the statutory rate is as follows:
Expected federal income tax	$ 60,866	$ 62,105	$ 81,381
Tax effect of differences:
Depreciation	5,805	4,010	10,404
Amortization of regulatory assets	1,795	1,795	11,518
Investment tax credit amortization	(3,808)	(3,819)	(26,592)
State income taxes, net of federal benefit	(5,377)	785	12,098
Dividends received deduction	(1,255)	(1,370)	(3,237)
Tax asset valuation allowance/reserve adjustments	1,914	(5,379)	(111)
Other, net	(8,184)	(7,395)	(10,611)
Total income tax expense	$ 51,756	$ 50,732	$ 74,850

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

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

	At December 31,
(Millions of Dollars)	2004	2003
Deferred tax liabilities - current:
Change in fair value of energy contracts	$ 74.7	$ 55.4
Other	33.0	22.1
Total deferred tax liabilities - current	107.7	77.5
Deferred tax assets - current:
Change in fair value of energy contracts	76.3	59.1
Other	14.7	8.4
Total deferred tax assets - current	91.0	67.5
Net deferred tax liabilities - current	16.7	10.0
Deferred tax liabilities - long-term:
Accelerated depreciation and other plant-related differences	1,105.5	904.4
Employee benefits	169.2	151.4
Regulatory amounts:
Securitized contract termination costs and other	252.1	247.0
Income tax gross-up	215.1	178.6
Other	239.8	254.7
Total deferred tax liabilities - long-term	1,981.7	1,736.1
Deferred tax assets - long-term:
Regulatory deferrals	365.0	341.5
Employee benefits	86.7	72.1
Income tax gross-up	32.6	20.8
Other	63.0	24.4
Total deferred tax assets - long-term	547.3	458.8
Net deferred tax liabilities - long-term	1,434.4	1,277.3
Net deferred tax liabilities	$1,451.1	$1,287.3

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

At December 31, 2003, NU had state net operating loss carry forwards of $119.5 million that expire between December 31, 2006 and December 31, 2023. The state net operating losses produced a deferred tax asset of $17.2 million and $10.4 million at December 31, 2004 and 2003, respectively.

NU had established a valuation allowance of $12.6 million and $9.4 million as of December 31, 2004 and 2003, respectively.

In 2000, NU requested from the Internal Revenue Service (IRS) a Private Letter Ruling (PLR) regarding the treatment of unamortized investment tax credits (ITC) and excess deferred income taxes (EDIT) related to generation assets that have been sold. EDIT are temporary differences between book and taxable income that were recorded when the federal statutory tax rate was higher than it is now or when those differences were expected to be resolved. The PLR addresses whether or not EDIT and ITC can be returned to customers, which without a PLR management believes would represent a violation of current tax law. The IRS declared a moratorium on issuing PLRs until final regulations on the return of EDIT and ITC to regulated customers are issued by the Treasury Department. Proposed regulations were issued in March 2003, and a hearing took place in June 2003. The proposed new regulations would allow the r eturn of EDIT and ITC to regulated customers without violating the tax law. Also, under the proposed regulations, a company could elect to apply the regulation retroactively. The Treasury Department is currently deliberating the comments received at the hearing. The ultimate results of this contingency could have a positive impact on CL&P’s earnings.

Accounting for R.M. Services, Inc.

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

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

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

On June 30, 2004, RMS sold virtually all of its assets and liabilities for $3 million. NU recorded a gain totaling $0.8 million on the sale of RMS. Prior to the sale, RMS was consolidated into NU's financial statements and had after-tax operating losses totaling $1 million in 2004. These charges and gains are included in Note 1V, "Summary of Significant Accounting Policies – Other Income/(Loss)," and in the other segment in Note 15, "Segment Information," to the consolidated financial statements.

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

Other Investments

At December 31, 2004 and 2003, NU maintained certain cost method and other investments. The cost method investments are comprised of NEON, a provider of optical networking services and Acumentrics, a developer of fuel cell and power quality equipment. Yankee Energy System, Inc. maintains the other investment, a long-term note receivable from BMC Energy LLC (BMC), an operator of renewable energy projects.

NEON: Under a 2002 common stock purchase agreement with NEON, NU invested $2.1 million in 2004 in exchange for an additional 341,000 shares of NEON common stock.

On July 19, 2004, NEON and Globix Corporation (Globix) announced a definitive merger agreement in which Globix, an unaffiliated publicly-owned entity, would acquire NEON for shares of Globix common stock. The merger closed on March 8, 2005, and NU received 1.2748 shares of Globix common stock for each of the 2.1 million shares of NEON stock it owned. 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 2002, NU recorded an investment write-down of $14.6 million on a pre-tax basis to reduce the carrying value of the investment in NEON to its net realizable value at that time. NU's investment in NEON had a carrying value of $9.8 million and $9.9 million at December 31, 2004 and 2003, respectively.

Acumentrics: Based on new information that affected the fair value of NU’s investment in Acumentrics, management determined that the value of NU’s investment declined in 2004 and that these declines were other-than-temporary in nature. Total investment write-downs of $9.1 million on a pre-tax basis were recorded in 2004 to reduce the carrying value of the investment. The balance of this investment at December 31, 2003 totaled $9.5 million including an investment in Acumentrics debt securities of $2 million. During 2004, NU invested an additional $0.2 million in Acumentrics debt securities. At December 31, 2004, after the investment write-downs, NU's remaining investment in Acumentrics totaled $0.6 million in debt securities.

BMC: In late-March 2004, based on revised information that impacted undiscounted cash flow projections and fair value estimates, management determined that the fair value of the note receivable from BMC had declined and that the note was impaired. As a result, management recorded an investment write-down of $2.5 million on a pre-tax basis in the first quarter of 2004. NU's remaining note receivable from BMC, which management expects to collect from BMC, totaled $1.3 million and $4 million at December 31, 2004 and 2003, respectively.

The NEON, Acumentrics and BMC investment write-downs are included in other income/(loss) on the accompanying consolidated statement of income. For further information regarding other income/(loss), see Note 1V, "Other Income/(Loss)" to the consolidated financial statements.

Depreciation

The provision for depreciation on utility assets is calculated using the straight-line method based on the estimated remaining useful lives of depreciable plant-in-service, which range primarily from 3 years to 75 years, adjusted for salvage value and removal costs, as approved by the appropriate regulatory agency where applicable. Depreciation rates are applied to plant-in-service from the time it is placed in service. When plant is retired from service, the original cost of the plant, including costs of removal less salvage, is charged to the accumulated provision for depreciation. Cost of removal is classified as a regulatory liability. The depreciation rates for the several classes of electric utility plant-in-service are equivalent to a composite rate of 3.3 percent in 2004, 3.4 percent in 2003 and 3.2 percent in 2002.

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

In 2002, NU Enterprises concluded a study of the depreciable lives of certain generation assets. The impact of this study was to lengthen the useful lives of those generation assets by 32 years to an average of 70 years. In addition, the useful lives of certain software was revised and shortened to reflect a remaining life of 1.5 years. Depreciation expense associated with these generation assets and software totaled $12.1 million in 2004, $14.2 million in 2003 and $17.7 million in 2002.

Jointly Owned Electric Utility Plant

Regional Nuclear Companies: At December 31, 2004, CL&P, PSNH and WMECO own common stock in three regional nuclear companies (Yankee Companies). NU’s ownership interests in the Yankee Companies at December 31, 2004, which are accounted for on the equity method are 49 percent of the Connecticut Yankee Atomic Power Company (CYAPC), 38.5 percent of the Yankee Atomic Electric Company (YAEC) and 20 percent of the Maine Yankee Atomic Power Company (MYAPC). In 2003, CL&P, PSNH and WMECO sold their collective 17 percent ownership interest in Vermont Yankee Nuclear Power Corporation (VYNPC). NU’s total equity investment in the Yankee Companies at December 31, 2004 and 2003, was $28.6 million and $32.2 million, respectively. Earnings related to these equity investments are included in other income/(loss) on the accompanying consolidated statements of income. For fu rther information, see Note 1V, "Other Income/(Loss)," to the consolidated financial statements. Each of the remaining Yankee Companies owns a single nuclear generating plant which is being decommissioned.

NU owns 49 percent of the common stock of CYAPC with a carrying value of $21.4 million at December 31, 2004. CYAPC is involved in litigation over the termination of the decommissioning contract with Bechtel Power Corporation (Bechtel). Management believes that this litigation has not impaired the value of its investment in CYAPC at December 31, 2004 but will continue to evaluate the impact of the litigation on NU's investment. For further information regarding the Bechtel litigation, see Note 6E, "Commitments and Contingencies - Deferred Contractual Obligations," to the consolidated financial statements.

Hydro-Quebec: NU parent has a 22.66 percent equity ownership interest in two companies that transmit electricity imported from the Hydro-Quebec system in Canada. NU's investment and exposure to loss is $9.5 million and $10.1 million at December 31, 2004 and 2003, 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 consolidated statements of income as follows:

For the Years Ended December 31,
(Millions of Dollars, except percentages)	2004	2003	2002
Borrowed funds Equity funds	$4.5 3.8	$ 5.0 6.5	$ 7.5 5.8
Totals	$8.3	$11.5	$13.3
Average AFUDC rate	3.9%	4.0%	4.9%

The average AFUDC rate is based on a FERC-prescribed formula that develops an average rate using the cost of the company's short-term financings as well as the company's capitalization (preferred stock, long-term debt and common equity). The average rate is applied to eligible construction work in progress amounts to calculate AFUDC.

Equity-Based Compensation

NU maintains an Employee Stock Purchase Plan and other long-term, equity-based incentive plans under the Northeast Utilities Incentive Plan (Incentive Plan). NU accounts for these plans under the recognition and measurement principles of Accounting Principles Board Opinion (APB) No. 25, "Accounting for Stock Issued to Employees," and related interpretations. No equity-based employee compensation cost for stock options is reflected in net income, as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the date of grant. The following table illustrates the effect on net income and earnings per share (EPS) if NU had applied the fair value recognition provisions of SFAS No. 123 to equity-based employee compensation:

	For the Years Ended December 31,
(Millions of Dollars, except per share amounts)		2004	2003	2002
Net income as reported		$116.6	$116.4	$152.1
Total equity-based employee compensation expense determined under the fair value-based method for all awards, net of related tax effects		(1.1)	(1.9)	(3.2)
Pro forma net income		$115.5	$114.5	$148.9
EPS:
Basic and diluted - as reported		$ 0.91	$0.91	$1.18
Basic and diluted - pro forma		$ 0.90	$0.90	$1.15

Net income as reported includes $3.8 million, $2 million and $1 million of expense for restricted stock and restricted stock units for the years ended December 31, 2004, 2003 and 2002, respectively. NU accounts for restricted stock in accordance with APB No. 25 and amortizes the intrinsic value of the award over the related service period.

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

During the year ended December 31, 2004, no stock options were awarded.

Under SFAS No. 123R, NU will be required to recognize compensation expense for the unvested portion of previously granted awards that remain outstanding on July 1, 2005, the effective date of SFAS No. 123R, and any new awards after that date. Management believes that the impact of the adoption of SFAS No. 123R will not be material.

Sale of Receivables

Utility Group: At December 31, 2004 and 2003, CL&P had sold an undivided interest in its accounts receivable of $90 million and $80 million, respectively, to a financial institution with limited recourse through CL&P Receivables Corporation (CRC), a wholly owned subsidiary of CL&P. CRC can sell up to $100 million of an undivided interest in its accounts receivable and unbilled revenues. At December 31, 2004 and 2003, the reserve requirements calculated in accordance with the Receivables Purchase and Sale Agreement were $18.8 million and $29.3 million, respectively. These reserve amounts are deducted from the amount of receivables eligible for sale at the time. 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 within its service territory.

At December 31, 2004 and 2003, amounts sold to CRC by CL&P but not sold to the financial institution totaling $139.4 million and $166.5 million, respectively, are included in 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 7, 2004, CRC renewed its Receivables Purchase and Sale Agreement with CL&P and the financial institution through July 6, 2005, and the termination date of the facility was extended to July 3, 2007. CL&P's continuing involvement with the receivables that are sold to CRC and the financial institution is limited to the servicing of those receivables.

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

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

At December 31, 2004, SESI had sold $30 million of accounts receivable related to the installation of the energy efficiency projects, with limited recourse, under this master purchase agreement. A loss of approximately $0.1 million was recorded on the sale of these receivables. Under the delivery order with the government, SESI is responsible for on-going maintenance and other services related to the energy efficiency project

installation. SESI receives payment for those services in addition to the amounts sold under the master purchase agreement. NU has provided a guarantee that SESI will perform its obligations under the master purchase agreement and subsequent individual assignment agreements. The sale of the receivables to the unaffiliated third party qualifies for sales treatment under SFAS No. 140, and therefore these receivables are not included in the consolidated financial statements.

In 2004, SESI entered into assignment agreements to sell an additional $26.5 million of receivables upon completion of the installation of the energy savings projects in 2005. Until the construction is completed, the receivables are recorded under the percentage of completion method and included in the consolidated financial statements and the advances under the purchase agreement are recorded as debt.

Asset Retirement Obligations

In June 2001, the FASB issued SFAS No. 143. This statement requires that legal obligations associated with the retirement of property, plant and equipment be recognized as a liability at fair value when incurred and when a reasonable estimate of the fair value of the liability can be made. SFAS No. 143 was effective on January 1, 2003 for NU. Management has completed its review process for potential asset retirement obligations (ARO) and has not identified any material AROs that have been incurred. However, management has identified certain removal obligations that arise in the ordinary course of business or have a low probability of occurring. These types of obligations primarily relate to transmission and distribution lines and poles, telecommunication towers, transmission cables, and certain FERC or state regulatory agency re-licensing issues. These obligations are AROs that have no t been incurred or are not material in nature.

On June 17, 2004, the FASB issued the proposed interpretation, "Accounting for Conditional Asset Retirement Obligations". The proposed interpretation 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 and clarifies that there are no circumstances in which a law or regulation obligates an entity to perform retirement activities but then allows the entity to permanently avoid settling the obligation.

A portion of NU’s regulated utilities’ rates is intended to recover the cost of removal of certain utility assets. The amounts recovered do not represent AROs and are recorded as regulatory liabilities. At December 31, 2004 and 2003, cost of removal was approximately $328.8 million and $334 million, respectively.

Materials and Supplies

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

Cash and Cash Equivalents

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

Special Deposits

Special deposits represent amounts Select Energy has on deposit with unaffiliated counterparties and brokerage firms in the amount of $46.3 million and amounts included in escrow for SESI that have not been spent on construction projects of $20 million at December 31, 2004. Similar amounts totaled $17 million and $32 million, respectively, at December 31, 2003. Special deposits at December 31, 2004 also included $16.3 million in escrow for Yankee Gas. The $16.3 million represents Yankee Gas' June 1, 2005 first mortgage bond payment. Special deposits at December 31, 2003 also included $30.1 million in escrow that PSNH funded to acquire CVEC on January 1, 2004.

Restricted Cash – LMP Costs

Restricted cash - LMP costs represents incremental locational marginal pricing (LMP) cost amounts that were collected by CL&P and deposited into an escrow account.

At December 31, 2003, restricted cash - LMP costs totaled $93.6 million, and an additional $30 million was deposited in 2004. During the third quarter of 2004, $83 million of the amount was paid to CL&P’s standard offer suppliers in accordance with the FERC approved Standard Market Design (SMD) settlement. The remaining $41 million was released from the escrow account in the third quarter of 2004 and was refunded to CL&P's customers as a credit on bills from September to December of 2004.

Excise Taxes

Certain excise taxes levied by state or local governments are collected by NU from its customers. These excise taxes are accounted for on a gross basis with collections in revenues and payments in expenses. For the years ended December 31, 2004, 2003 and 2002, gross receipts taxes, franchise taxes and other excise taxes of $97 million, $96.8 million, and $88.8 million, respectively, are included in operating revenues and taxes other than income taxes on the accompanying consolidated statements of income.

Other Income/(Loss)

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

For the Years Ended December 31,
(Millions of Dollars)	2004	2003	2002
Other Income:
Seabrook-related gains	$ -	$ -	$ 38.7
Investment income	16.5	17.1	25.4
CL&P procurement fee	11.7	-	-
AFUDC - equity funds	3.8	6.5	5.8
Gain on sale of RMS	0.8	-	-
Other	20.5	18.0	39.1
Total Other Income	53.3	41.6	109.0
Other Loss:
Investment write-downs	(13.8)	(1.4)	(18.4)
Charitable donations	(3.8)	(8.4)	(3.7)
Costs not recoverable from Regulated customers	(5.6)	(10.5)	(2.7)
Other	(15.6)	(21.7)	(40.4)
Total Other Loss	(38.8)	(42.0)	(65.2)
Totals	$ 14.5	$ (0.4)	$ 43.8

Investment income includes equity in earnings of regional nuclear generating and transmission companies of $2.6 million in 2004, $4.5 million in 2003 and $11.2 million in 2002. Equity in earnings relates to NU's investment in the Yankee Companies and the Hydro-Quebec system.

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

Supplemental Cash Flow Information

	For the Years Ended December 31,
(Millions of Dollars)	2004	2003	2002
Cash paid during the year for: Interest, net of amounts capitalized	$227.7	$241.3	$259.9
Income taxes	$ 74.3	$248.3	$114.4

Marketable Securities

NU currently maintains two trusts that hold marketable securities. The trusts are used to fund NU's Supplemental Executive Retirement Plan (SERP) and WMECO's prior spent nuclear fuel liability. 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 in the consolidated statements of shareholders' equity. Realized gains and losses are included in other income/(loss), in the consolidated statements of income.

For information regarding marketable securities, see Note 8, "Marketable Securities," to the consolidated financial statements.

Counterparty Deposits

Balances collected from counterparties resulting from Select Energy's credit management activities totaled $57.7 million at December 31, 2004 and $46.5 million at December 31, 2003. These amounts are recorded as current liabilities and included as counterparty deposits on the accompanying consolidated balance sheets. To the extent Select Energy requires collateral from counterparties, cash is received as a part of the total collateral required. The right to receive such cash collateral in an unrestricted manner is determined by the terms of Select Energy’s agreements. Key factors affecting the unrestricted status of a portion of this cash collateral include the financial standing of Select Energy and of NU as its credit supporter.

Provision for Uncollectible Accounts

NU maintains a provision for uncollectible accounts to record its receivables at an estimated net realizable value. This provision is determined based upon a variety of factors, including applying an estimated uncollectible account percentage to each receivables aging category, historical collection and write-off experience and management's assessment of individual customer collectibility. 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 theprovision for uncollectibleaccounts when these balances are deemed to be uncollectible.

2. Short-Term Debt

Limits: The amount of short-term borrowings that may be incurred by NU and its operating companies is subject to periodic approval by either the SEC under the 1935 Act or by the respective state regulators. On June 30, 2004, the SEC granted authorization allowing NU, CL&P, PSNH, WMECO, and Yankee Gas to incur total short-term borrowings up to a maximum of $450 million, $450 million, $100 million, $200 million, and $150 million, respectively, through June 30, 2007. The SEC also granted authorization for borrowing through the NU Money Pool (Pool).

The charter of CL&P contains preferred stock provisions restricting the amount of unsecured debt that CL&P may incur. At meetings in November 2003, CL&P obtained authorization from its stockholders to issue unsecured indebtedness with a maturity of less than 10 years in excess of the 10 percent of total capitalization limitation in CL&P's charter, provided that all unsecured indebtedness would not exceed 20 percent of total capitalization for a ten-year period expiring March 2014. On March 18, 2004, the SEC approved this change in CL&P's charter. As of December 31, 2004, CL&P is permitted to incur $394.8 million of additional unsecured debt.

PSNH is authorized by the NHPUC to incur short-term borrowings up to a maximum of $100 million.

Utility Group Credit Agreement: On November 8, 2004, CL&P, PSNH, WMECO, and Yankee Gas entered into a 5-year unsecured revolving credit facility for $400 million. This facility replaces a $300 million credit facility that expired on November 8, 2004. CL&P may draw up to $200 million, with PSNH, WMECO and Yankee Gas able to draw up to $100 million, subject to the $400 million maximum borrowing limit. Unless extended, the credit facility will expire on November 6, 2009. At December 31, 2004 and 2003, there were $80 million and $40 million, respectively, in borrowings under these credit facilities.

NU Parent Credit Agreement: On November 8, 2004, NU entered into a 5-year unsecured revolving credit and letter of credit (LOC) facility for $500 million. This facility replaces a $350 million 364-day facility that expired on November 8, 2004. This facility provides a total commitment of $500 million which is available for advances, subject to an LOC sub-limit. Subject to the advances outstanding, LOCs may be issued in notional amounts up to $350 million for periods up to 364 days. The agreement provides for LOCs to be issued in the name of NU or any of its subsidiaries. This total commitment may be increased to $600 million, subject to approval, at the request of the borrower. Unless extended, the credit facility will expire on November 6, 2009.

Current SEC authorization permits borrowings up to a maximum of $450 million. On November 20, 2004, an application was filed with the SEC requesting an increase of maximum borrowings to $500 million, to match this facility limit. At December 31, 2004 and 2003, there were $100 million and $65 million, respectively, in borrowings under these credit facilities. In addition, there were $48.9 million and $106.9 million in LOCs outstanding at December 31, 2004 and 2003, respectively.

Under the Utility Group and NU parent credit agreements, NU and its subsidiaries may borrow at fixed or variable rates plus an applicable margin based upon certain debt ratings, as rated by the lower of Standard and Poor's or Moody's Investors Service. The weighted average interest rates on NU's notes payable to banks outstanding on December 31, 2004 and 2003 were 4.53 percent and 2.07 percent, respectively.

Under the Utility Group and NU parent credit agreements, NU and its subsidiaries must comply with certain financial and non-financial covenants as are customarily included in such agreements, including but not limited to, consolidated debt ratios and interest coverage ratios. The most restrictive financial covenant is the interest coverage ratio. 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 any one time.

Other Credit Facility: On June 30, 2004, E.S. Boulos Company (Boulos), a subsidiary of NGS, renewed its $6 million line of credit. This credit facility replaces a similar credit facility that expired on June 30, 2004, and unless extended, will expire on June 30, 2005. 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, 2004 and 2003, there were no borrowings under this credit facility.

3. Derivative Instruments

Derivatives that are utilized for trading purposes are recorded at fair value with changes in fair value included in earnings. Other contracts that are derivatives but do not meet the definition of a cash flow hedge and cannot be designated as being used for normal purchases or normal sales are also recorded at fair value with changes in fair value included in earnings. For those contracts that meet the definition of a derivative and meet the cash flow hedge requirements, the changes in the fair value of the effective portion of those contracts are generally recognized in accumulated other comprehensive income until the underlying transactions occur. For contracts that meet the definition of a derivative but do not meet the hedging requirements, and for the ineffective portion of contracts that meet the cash flow hedge requirements, the changes in fair value of those contracts are recognized currently in ear nings. Derivative contracts designated as fair value hedges and the item they are hedging are both recorded at fair value on the consolidated balance sheets. Derivative contracts that are entered into as a normal purchase or sale and will result in physical delivery, and are documented as such, are recognized in revenue and expense when such deliveries occur.

For the year ended December 31, 2004, a negative $57.8 million, net of tax, was reclassified as an expense from other comprehensive income in connection with the consummation of the underlying hedged transactions and recognized in earnings. Also during 2004, new cash flow hedge transactions were entered into that hedge cash flows through 2007. As a result of these new transactions and market value changes since January 1, 2004, accumulated other comprehensive income decreased by $28.3 million, net of tax. Accumulated other comprehensive income at December 31, 2004, was a negative $3.5 million, net of tax (decrease to equity), relating to hedged transactions, and it is estimated that a negative $2.9 million included in this net of tax balance will be reclassified as a decrease to earnings within the next twelve months. Cash flows from hedge contracts are reported in the sa me category as cash flows from the underlying hedged transaction.

There was a negative pre-tax impact of $0.5 million recognized in earnings for the ineffective portion of cash flow hedges. A negative pre-tax $0.6 million was recognized in 2004 earnings for the ineffective portion of fair value hedges. The changes in the fair value of both the fair value hedges and the natural gas inventory being hedged are recorded in fuel, purchased, and net interchange power on the accompanying consolidated statements of income.

The tables below summarize current and long-term derivative assets and liabilities at December 31, 2004 and December 31, 2003. The business activities of NU Enterprises that result in the recognition of derivative assets include concentrations of credit risk to energy marketing and trading counterparties. At December 31, 2004, Select Energy has $87.3 million of derivative assets from trading, non-trading, and hedging activities. These assets are exposed to counterparty credit risk. However, a significant portion of these assets is contracted with investment grade rated counterparties or collateralized with cash. The amounts below do not include option premiums paid, which are recorded as prepayments and amounted to $5.4 million and $9.1 million related to energy trading activities and $5.2 million and $7.6 million related to marketing activities at December 31, 2004 and December 31, 200 3, respectively. These amounts also do not include option premiums paid of $18.7 million related to non-trading gas options at December 31, 2004.

The amounts below also do not include option premiums received, which are recorded as other current liabilities and amounted to $7 million and $12.2 million related to energy trading activities at December 31, 2004 and December 31, 2003, respectively, and $1.1 million related to marketing activities at December 31, 2004. Also not included at December 31, 2004, are option premiums received of $19 million related to non-trading gas options.

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

	At December 31, 2003
(Millions of Dollars)	Assets		Liabilities
	Current	Long- Term	Current	Long- Term	Net Total
NU Enterprises:
Trading	$ 40.0	$31.8	$(33.0)	$ (6.3)	$ 32.5
Non-trading	1.6	-	(0.8)	-	0.8
Hedging	54.6	1.2	(10.7)	(2.0)	43.1
Utility Group - Gas:
Non-trading	0.2	-	(0.2)	-	-
Hedging	2.8	-	-	-	2.8
Utility Group - Electric:
Non-trading	17.1	99.8	(6.4)	(49.6)	60.9
NU Parent: Hedging	-	-	-	(3.6)	(3.6)
Total	$116.3	$132.8	$(51.1)	$(61.5)	$136.5

NU Enterprises - Trading: To gather market intelligence and utilize this information in risk management activities for the wholesale marketing activities, Select Energy conducts limited energy trading activities in electricity, natural gas, and oil, and therefore, experiences net open positions. Select Energy manages these open positions with strict policies that limit its exposure to market risk and require daily reporting to management of potential financial exposures.

Derivatives used in trading activities are recorded at fair value and included in the consolidated balance sheets as derivative assets or liabilities. Changes in fair value are recognized in operating revenues in the consolidated statements of income in the period of change. The net fair value positions of the trading portfolio at December 31, 2004 and 2003 were assets of $29.6 million and $32.5 million, respectively.

Select Energy's trading portfolio includes New York Mercantile Exchange (NYMEX) futures, financial swaps, and options, the fair value of which is based on closing exchange prices; over-the-counter forwards, financial swaps, and options, the fair value of which is based on the mid-point of bid and ask market prices; and bilateral contracts for the purchase or sale of electricity or natural gas, the fair value of which is determined using

available information from external sources. Select Energy's trading portfolio also includes transmission congestion contracts (TCC). The fair value of the TCCs included in the trading portfolio is based on published market data.

NU Enterprises - Non-Trading: Certain non-trading derivative contracts are used for delivery of energy related to Select Energy's wholesale and retail marketing activities. Changes in fair value of a negative $79.4 million of non-trading derivative contracts were recorded primarily in expenses in 2004. Of the $79.4 million change in fair value, $77.7 million relates to natural gas hedges at December 31, 2004. These hedges are used to mitigate the risk of electricity price changes on Select Energy’s fixed-price electricity purchase contracts. These hedges do not meet criteria to be accounted for as cash flow hedges nor do they meet the normal purchase and sales exception and are accordingly accounted for at fair value as non-trading contracts. The contracts are natural gas contracts with fair values determined by prices provided by external sources and actively quoted market s. Select Energy held none of these contracts at December 31, 2003.

Market information for the TCCs classified as non-trading is not available, and those contracts cannot be reliably valued. Management believes the amounts paid for these contracts, which total $3.2 million at December 31, 2004, and $4.3 million at December 31, 2003 and are included in premiums paid, are equal to their fair value.

NU Enterprises - Hedging: Select Energy utilizes derivative financial and commodity instruments, including futures and forward contracts, to reduce market risk associated with fluctuations in the price of electricity and natural gas purchased to meet firm sales and purchase commitments to certain customers. Select Energy also utilizes derivatives, including price swap agreements, call and put option contracts, and futures and forward contracts to manage the market risk associated with a portion of its anticipated supply and delivery requirements. These derivatives have been designated as cash flow hedging instruments and are used to reduce the market risk associated with fluctuations in the price of electricity or natural gas. A derivative that hedges exposure to the variable cash flows of a forecasted transaction (a cash flow hedge) is initially recorded at fair value with changes in fair value recorded in accumulated other comprehensive income. Cash flow hedges impact net income when the forecasted transaction being hedged occurs, when hedge ineffectiveness is measured and recorded, when the forecasted transaction being hedged is no longer probable of occurring, or when there is accumulated other comprehensive loss and the hedge and the forecasted transaction being hedged are in a loss position on a combined basis.

Select Energy maintains natural gas service agreements with certain customers to supply gas at fixed prices for terms extending through 2006. Select Energy has hedged its gas supply risk under these agreements through NYMEX futures contracts. Under these contracts, which also extend through 2006, the purchase price of a specified quantity of gas is effectively fixed over the term of the gas service agreements. At December 31, 2004 the NYMEX futures contracts had notional values of $90.7 million and were recorded at fair value as derivative liabilities of $3.2 million.

Select Energy also maintains various physical and financial instruments to hedge its electric and gas purchases and sales through 2006. These instruments include forwards, futures, options, financial collars and swaps. These hedging contracts, which are valued at the mid-point of bid and ask market prices, were recorded as derivative assets of $3.7 million and derivative liabilities of $6.7 million at December 31, 2004.

Select Energy hedges certain amounts of natural gas inventory with gas futures, options and swaps, some of which are accounted for as fair value hedges. Changes in the fair value of hedging instruments and natural gas inventory are recorded in earnings. The fair value of the futures, options and swaps were recorded as derivative assets of $0.8 million at December 31, 2004. The fair value of the hedged natural gas inventory was recorded as a reduction to fuel, materials and supplies of $1.5 million at December 31, 2004. For the year ended December 31, 2004, Select Energy recorded a negative pre-tax of $0.6 million in earnings related to its hedging instruments and natural gas inventory. In 2004, certain of these fair value hedges were redesignated as cash flow hedges, and future changes in fair value during the hedge designation will be included in other comprehensive income (equity), unless ineff ective.

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

Utility Group - Gas - Hedging: Yankee Gas maintains a master swap agreement with a financial counterparty to purchase gas at fixed prices. Under this master swap agreement, the purchase price of a specified quantity of gas for an unaffiliated customer is effectively fixed over the term of the gas service agreements with that customer for a period not extending beyond 2005. At December 31, 2004, the commodity swap agreement had a notional value of $2.3 million and was recorded at fair value as a derivative asset of $1.5 million. The firm commitment contract that is hedged is also recorded as a liability on the accompanying consolidated balance sheets, and changes in fair values of the hedge and firm commitment have offsetting impacts in earnings.

Utility Group - Electric - Non-Trading: CL&P has two IPP contracts to purchase power that contain pricing provisions that are not clearly and closely related to the price of power and therefore do not qualify for the normal purchases and sales exception. The fair values of these IPP non-trading derivatives at December 31, 2004 include a derivative asset with a fair value of $191.3 million and a derivative liability with a fair value of $47.2 million. An offsetting regulatory liability and an offsetting regulatory asset were recorded, as these contracts are part of the stranded costs, and management believes that these costs will continue to be recovered or refunded in rates.

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

4. Employee Benefits

Pension Benefits and Postretirement Benefits Other Than Pensions

Pension Benefits: NU's subsidiaries participate in a uniform noncontributory defined benefit retirement plan (Pension Plan) covering substantially all regular NU employees. Benefits are based on years of service and the employees’ highest eligible compensation during 60 consecutive months of employment. Pre-tax pension expense/(income) was expense of $5.9 million in 2004, income of $31.8 million in 2003, and income of $73.4 million in 2002. These amounts exclude pension settlements, curtailments and net special termination benefit expense of $2.1 million in 2004 and income of $22.2 million in 2002. NU uses a December 31 measurement date for the Pension Plan. Pension (income)/expense attributable to earnings is as follows:

For Years Ended December 31,

(Millions of Dollars)

2004

2003

2002

Pension expense/(income) before

settlements, curtailments

and special termination benefits

$5.9

$(31.8)

$ (73.4)

Pension income capitalized
as utility plant

2.6

15.4

26.2

Net pension expense/(income)

before settlements,

curtailments, and special

termination benefits

8.5

(16.4)

(47.2)

Settlements, curtailments, and

special termination benefits

reflected in earnings

2.1

Total pension expense/(income)

included in earnings

$10.6

$(16.4)

$(47.2)

Pension Settlements, Curtailments and Special Termination Benefits: As a result of litigation with nineteen former employees, in April 2004, NU was ordered by the court to modify its retirement plan to include special retirement benefits for fifteen of these former employees retroactive to the dates of their retirement and increased future monthly benefit payments. In the third quarter of 2004, NU withdrew its appeal of the court's ruling. As a result, NU recorded $2.1 million in special termination benefits related to this litigation in 2004. NU made a lump sum benefit payment totaling $1.5 million to these former employees.

There were no settlements, curtailments or special termination benefits in 2003 and none in 2002 that impacted earnings.

On November 1, 2002, CL&P, NAEC and certain other joint owners consummated the sale of their ownership interests in Seabrook to a subsidiary of FPL Group, Inc. (FPL) and North Atlantic Energy Service Corporation (NAESCO), a wholly owned subsidiary of NU, ceased having operational responsibility for Seabrook at that time. NAESCO employees were transferred to FPL, which significantly reduced the expected service lives of NAESCO employees who participated in the Pension Plan. As a result, NAESCO recorded pension curtailment income of $29.1 million in 2002. As the curtailment related to the operation of Seabrook, NAESCO credited the joint owners of Seabrook with this amount. CL&P recorded its $1.2 million share of this income as a reduction to stranded costs, and as such, there was no impact on 2002 CL&P earnings. PSNH was credited with its $10.5 million share of this income through the S eabrook Power Contracts with NAEC. PSNH also credited this income as a reduction to stranded costs, and as such, there was no impact on 2002 PSNH earnings.

Additionally, in conjunction with the divestiture of its generation assets, NU recorded $1.2 million in curtailment income in 2002, all of which was recorded as a regulatory liability and did not impact earnings.

Effective February 1, 2002, certain CL&P and Utility Group employees who were displaced were eligible for a Voluntary Retirement Program (VRP). The VRP supplements the Pension Plan and provides special provisions. Eligible employees include non-bargaining unit employees or employees belonging to a collective bargaining unit that has agreed to accept the VRP who are active participants in the Pension Plan at January 1, 2002, and that have been displaced as part of the reorganization between January 22, 2002 and March 2003. Eligible employees received a special retirement benefit under the VRP whose value was roughly equivalent to a multiple of base pay based on years of credited service. During 2002, NU recorded an expense of $8.1 million associated with special pension termination benefits related to the VRP. NU believes that the cost of the VRP is probable of recovery through regulated utili ty rates, and accordingly, the $8.1 million was recorded as a regulatory asset with no impact on 2002 earnings.

Market-Related Value of Pension Plan Assets: NU bases the actuarial determination of pension plan income or 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.

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

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

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

Based on the current PBOP Plan provisions, NU’s actuaries believe that NU will qualify for this federal subsidy because the actuarial value of NU’s PBOP Plan is estimated to be 60 percent greater than that of the standard Medicare benefit. NU will directly benefit from the federal subsidy for retirees of PSNH and NAESCO who retired before 1993, and other NU retirees who retired before 1991. For other retirees, management does not believe that NU will benefit from the subsidy because NU’s cost support for these retirees is capped at a fixed dollar commitment.

Based on the most recent actuarial valuation as of January 1, 2004, the impact of the Medicare program has been revised from a $19.5 million decrease in the PBOP benefit obligation at December 31, 2003 to $27 million at January 1, 2004. The total $27 million decrease consists of $20 million as a direct result of the subsidy for certain non-capped retirees and $7 million related to changes in participation assumptions for capped retirees and future retirees as a result of the subsidy. The total $27 million decrease is currently being amortized as a reduction to PBOP expense over approximately 13 years. For the year ended December 31, 2004, this reduction in PBOP expense totaled approximately $3.6 million, including amortization of the actuarial gain of $2 million and a reduction in interest cost and service cost based on a lower PBOP benefit obligation of $1.6 million.

PBOP Settlements, Curtailments and Special Termination Benefits: There were no settlements, curtailments or special termination benefits in 2004 or 2003.

In 2002, NU recorded PBOP special termination benefits income of $1.2 million related to the sale of Seabrook. CL&P and PSNH recorded their shares of this curtailment as reductions to stranded costs.

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

	At December 31,
	Pension Benefits		Postretirement Benefits
(Millions of Dollars)	2004	2003	2004	2003
Change in benefit obligation
Benefit obligation at beginning of year	$(1,941.3)	$(1,789.8)	$(405.0)	$(397.8)
Service cost	(40.7)	(35.1)	(6.0)	(5.3)
Interest cost	(118.9)	(117.0)	(25.3)	(26.8)
Medicare prescription drug benefit impact	N/A	N/A	-	19.5
Actuarial loss	(136.7)	(102.9)	(68.7)	(34.8)
Benefits paid - excluding lump sum payments	105.0	99.6	36.7	40.2
Benefits paid - lump sum payments	1.5	3.9	-	-
Special termination benefits	(2.1)	-	-	-
Benefit obligation at end of year	$(2,133.2)	$(1,941.3)	$(468.3)	$(405.0)
Change in plan assets
Fair value of plan assets at beginning of year	$ 1,945.1	$ 1,632.3	$178.0	$ 147.7
Actual return on plan assets	236.9	416.3	16.8	35.4
Employer contribution	-	-	41.7	35.1
Benefits paid - excluding lump sum payments	(105.0)	(99.6)	(36.7)	(40.2)
Benefits paid - lump sum payments	(1.5)	(3.9)	-	-
Fair value of plan assets at end of year	$ 2,075.5	$ 1,945.1	$ 199.8	$ 178.0
Funded status at December 31	$ (57.7)	$ 3.8	$(268.5)	$(227.1)
Unrecognized transition obligation/(asset)	0.4	(1.1)	94.8	106.6
Unrecognized prior service cost	56.3	63.5	(5.2)	(5.5)
Unrecognized net loss	353.7	294.5	166.5	113.6
Prepaid/(accrued) benefit cost	$ 352.7	$ 360.7	$ (12.4)	$ (12.4)

The accumulated benefit obligation for the Plan was $1.9 billion and $1.7 billion at December 31, 2004 and 2003, respectively.

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

	At December 31,
Balance Sheets	Pension Benefits		Postretirement Benefits
	2004	2003	2004	2003
Discount rate	6.00%	6.25%	5.50%	6.25%
Compensation/progression rate	4.00%	3.75%	N/A	N/A
Health care cost trend rate	N/A	N/A	8.00%	9.00%

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

	For the Years Ended December 31,
	Pension Benefits				Postretirement Benefits
(Millions of Dollars)	2004	2003	2002	2004		2003	2002
Service cost	$ 40.7	$ 35.1	$ 37.2	$ 6.0		$ 5.3	$ 6.2
Interest cost	118.9	117.0	119.8	25.3		26.8	29.2
Expected return on plan assets	(175.1)	(182.5)	(204.9)	(12.5)		(14.9)	(16.6)
Amortization of unrecognized net transition (asset)/obligation	(1.5)	(1.5)	(1.4)	11.9		11.9	13.6
Amortization of prior service cost	7.2	7.2	7.7	(0.4)		(0.4)	(0.1)
Amortization of actuarial loss/(gain)	15.7	(7.1)	(31.8)	-		-	-
Other amortization, net	-	-	-	11.4		6.4	2.2
Net periodic expense/(income) - before curtailments and special termination benefits	5.9	(31.8)	(73.4)	41.7		35.1	34.5
Curtailment income	-	-	(30.3)	-		-	-
Special termination benefits expense/(income)	2.1	-	8.1	-		-	(1.2)
Total curtailments and special termination benefits	2.1	-	(22.2)	-		-	(1.2)
Total - net periodic expense/(income)	$ 8.0	$(31.8)	$(95.6)	$ 41.7		$ 35.1	$ 33.3

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

	For the Years Ended December 31,
Statements of Income	Pension Benefits			Postretirement Benefits
	2004	2003	2002	2004	2003	2002
Discount rate	6.25%	6.75%	7.25%	6.25%	6.75%	7.25%
Expected long-term rate of return	8.75%	8.75%	9.25%	N/A	N/A	N/A
Compensation/progression rate	3.75%	4.00%	4.25%	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%	7.25%
Life assets and non-taxable health assets	N/A	N/A	N/A	8.75%	8.75%	9.25%

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,

2004

2003

Health care cost trend rate

assumed for next year

7.00%

8.00%

Rate to which health care cost

trend rate is assumed to

decline (the ultimate trend rate)

5.00%

Year that the rate reaches the

ultimate trend rate

2007

The annual per capita cost of covered health care benefits was assumed to decrease by one percentage point each year through 2007.

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

$ 1.0

$ (0.8)

Effect on postretirement

benefit obligation

$15.1

$(13.3)

NU's investmentstrategy 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 regularly 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
	2004 and 2003		2004 and 2003
	Target Asset	Assumed Rate of	Target Asset	Assumed Rate of
Asset Category	Allocation	Return	Allocation	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, 2004 and 2003, 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	2004	2003	2004	2003
Equity securities:
United States	47%	47%	55%	59%
Non-United States	17%	18%	14%	12%
Emerging markets	3%	3%	1%	1%
Private	4%	3%	-	-
Debt Securities: Fixed income	19%	19%	28%	25%
High yield fixed income	5%	5%	2%	3%
Real estate	5%	5%	-	-
Total	100%	100%	100%	100%

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

(Millions of Dollars)
Year	Pension Benefits	Postretirement Benefits	Government Subsidy
2005	$107.5	$ 39.5	$ -
2006	109.9	40.3	2.3
2007	112.9	40.8	2.3
2008	116.2	40.1	2.3
2009	120.0	39.4	2.2
2010-2014	685.5	186.4	10.4

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

Contributions: NU does not expect to make any contributions to the Pension Plan in 2005 and expects to make $50.3 million in contributions to the PBOP Plan in 2005.

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

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

401(k) Savings Plan

NU maintains a 401(k) Savings Plan for substantially all NU employees. This savings plan provides for employee contributions up to specified limits. NU matches employee contributions up to a maximum of three percent of eligible compensation with one percent cash and two percent NU shares. The 401(k) matching contributions of cash and NU shares made by NU were $10.5 million in 2004, $9.9 million in 2003 and $11.1 million in 2002.

Employee Stock Ownership Plan

NU maintains an Employee Stock Ownership Plan (ESOP) for purposes of allocating shares to employees participating in the 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 contribution to the ESOP trust totaled $12 million in 2004, $14.7 million in 2003 and $16.4 million in 2002. Interest expense on the unsecured notes was $5.7 million, $7.6 million and $9.5 million in 2004, 2003 and 2002, respective ly. For the years ended December 31, 2004, 2003 and 2002, NU recognized $7.3 million, $6.9 million and $7.6 million, respectively, of expense related to the ESOP, excluding the interest expense on the unsecured notes.

All dividends received by the ESOP on unallocated shares are used to pay debt service and are not considered dividends for financial reporting purposes. During the first and second quarters of 2003, NU paid a $0.1375 per share quarterly dividend. During the third quarter of 2003 through the second quarter of 2004, NU paid a $0.15 per share quarterly dividend. NU paid a $0.1625 per share dividend during the third and fourth quarters of 2004.

In 2004 and 2003, the ESOP trust issued 567,907 and 607,020 of NU common shares, respectively, to satisfy 401(k) Savings Plan obligations to employees. At December 31, 2004 and 2003, total allocated ESOP shares were 8,183,711 and 7,615,804, respectively, and total unallocated ESOP shares were 2,616,474 and 3,184,381, respectively. The fair market value of the unallocated ESOP shares at December 31, 2004 and 2003, was $49.3 and $64.2 million, respectively.

Equity-Based Compensation

Impact of SFAS No. 123R: SFAS No. 123R will require NU to recognize compensation expense in an amount equal to the fair value of share-based payments granted to employees on or after July 1, 2005. NU is currently evaluating the impact of SFAS No. 123R on the Employee Share Purchase Plan (ESPP) and the Incentive Plan. Management believes that the impact of the adoption of SFAS No. 123R will not be material. See Note 1C, "New Accounting Standards," for more information on SFAS No. 123R.

Employee Share Purchase Plan: Since July 1998, NU has maintained an ESPP for all eligible employees. Under the ESPP, NU common shares are purchased at 6-month intervals at 85 percent of the lower of the price on the first or last day of each 6-month period. Employees may purchase shares having a value not exceeding 25 percent of their compensation as of the beginning of the purchase period. During 2004 and 2003, employees purchased 194,838 and 225,985 shares, respectively, at discounted prices of $14.17 and $15.90 in 2004 and $12.20 in 2003. At December 31, 2004 and 2003, 1,390,403 shares and 1,585,241 shares remained registered for future issuance under the ESPP, respectively.

Incentive Plans: Under the Incentive Plan, NU is authorized to grant various types of awards, including restricted stock, performance units, restricted stock units, and stock options to eligible employees and board members. The number of shares that may be utilized for grants and awards during a given calendar year may not exceed the aggregate of one percent of the total number of shares of NU common shares outstanding as of the first day of that calendar year and the shares not utilized in previous years. At December 31, 2004 and 2003, NU had 1,361,528 and 1,649,268 shares of common stock, respectively, registered for issuance under the Incentive Plan.

Restricted Stock and Restricted Stock Units:During 2004, NU granted 25,000 shares and 382,395 units of restricted stock and restricted stock units, respectively, under the Incentive Plan. The restricted shares granted in 2004 had a fair value of $0.4 million and were recorded as an offset to shareholders' equity. The restricted stock units granted in 2004 had a fair value of $7.4 million and were recorded as a liability in the accompanying consolidated balance sheets. During 2003, NU granted 383,589 shares of restricted stock under the Incentive Plan shares. Also during 2003, 75,000 restricted stock units were granted, all of which were forfeited January 1, 2004. During 2004, 2003 and 2002, $3.8 million, $2 million and $1 million, respectively, was expensed related to restricted stock and restricted stock units.

Performance Units: Under the Incentive Plan, NU also granted 30,122, 35,303 and 38,847 performance units during 2004, 2003 and 2002, respectively. The performance units vest ratably over three years and will be paid in cash at the end of the vesting period. NU records a liability for the performance units based on the achievement of the performance unit goals. A liability of $3.2 million and $1.5 million was recorded at December 31, 2004 and 2003, respectively, for these performance units. During 2004, 2003 and 2002, $1.7 million, $0.2 million and $1.3 million, respectively, was recorded as an expense related to these performance units.

Stock Options: Prior to 2003, NU granted stock options to certain employees. The exercise price of stock options, as set at the time of grant, was equal to the fair market value per share at the date of grant, and therefore no equity-based compensation cost was reflected in net income. No stock options were granted during 2004 or 2003. A summary of stock option transactions is as follows:

		Exercise Price Per Share
	Options	Range			Weighted Average
Outstanding - December 31, 2001	3,009,916	$ 9.6250	-	$22.2500	$16.4467
Granted	1,337,345	$16.5500	-	$19.8700	$17.8284
Exercised	(262,800)	$10.0134	-	$19.5000	$15.4666
Forfeited and cancelled	(247,152)	$14.9375	-	$22.2500	$18.3473
Outstanding - December 31, 2002	3,837,309	$ 9.6250	-	$22.2500	$16.8738
Exercised	(562,982)	$ 9.6250	-	$19.5000	$14.6223
Forfeited and cancelled	(151,005)	$14.9375	-	$21.0300	$19.0227
Outstanding – December 31, 2003	3,123,322	$ 9.6250	-	$22.2500	$17.1270
Exercised	(612,666)	$ 9.6250	-	$19.5000	$12.3181
Forfeited and cancelled	(516,914)	$16.5500	-	$19.5000	$16.6139
Outstanding - December 31, 2004	1,993,742	$14.9375	-	$22.2500	$18.7370
Exercisable - December 31, 2002	1,956,555	$ 9.6250	-	$22.2500	$15.3758
Exercisable - December 31, 2003	2,027,413	$ 9.6250	-	$22.2500	$16.6969
Exercisable - December 31, 2004	1,877,595	$14.9375	-	$22.2500	$18.7778

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

The fair value of each stock option grant has been estimated on the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions. No stock options were granted during 2004 or 2003.

		2002
Risk-free interest rate		4.86%
Expected life		10 years
Expected volatility		23.71%
Expected dividend yield		2.11%

The weighted average grant date fair values of options granted during 2002 was $5.64. The weighted average remaining contractual lives for the options outstanding at December 31, 2004 is 6.03 years.

In January 2005, 490,600 options that were outstanding and exercisable at December 31, 2004 with exercise prices ranging from $18.4375 to $21.03 were forfeited. This forfeiture resulted in outstanding and exercisable options in January 2005 of 1,503,142 and 1,386,995, respectively.

For additional information regarding equity-based compensation, see Note 1N, "Summary of Significant Accounting Policies - Equity-Based Compensation."

Supplemental Executive Retirement and Other Plans

NU has maintained a SERP since 1987. The SERP provides its participants, who are executives of NU, with benefits that would have been provided to them under NU’s retirement plan if certain Internal Revenue Code and other limitations were not imposed. The SERP liability of $24.2 million and $22.1 million at December 31, 2004 and 2003, respectively, represents NU’s actuarially-determined obligation under the SERP. During 2004, 2003 and 2002, $4 million, $3.9 million, and $3.8 million, respectively, was expensed related to the SERP.

The SERP is the only NU retirement plan for which a minimum pension liability has been recorded. Recording this minimum pension liability resulted in a reduction of $0.1 million to accumulated other comprehensive income.

NU maintains a plan for retirement and other benefits for certain current and past company officers. The actuarially-determined liability for this plan was $36.7 million and $35.5 million at December 31, 2004 and 2003, respectively. During 2004, 2003 and 2002, $4.5 million, $6.3 million and $7.8 million, respectively, was expensed related to this plan.

For further information regarding SERP investments, see Note 8, "Marketable Securities," to the consolidated financial statements.

5. Goodwill and Other Intangible Assets

SFAS No. 142, "Goodwill and Other Intangible Assets," requires that goodwill and intangible assets deemed to have indefinite useful lives be reviewed for impairment at least annually by applying a fair value-based test. NU uses October 1st as the annual goodwill impairment testing date. Goodwill impairment is deemed to exist if the net book value of a reporting unit exceeds its estimated fair value and if the implied fair value of goodwill based on the estimated fair value of the reporting unit is less than the carrying amount. Excluding adjustments to the purchase price allocation related to the acquisition of Woods Electrical Co., Inc. (Woods Electrical) and Woods Network recorded in 2003, there were no impairments or adjustments to the goodwill balances during 2004 or 2003. The Woods Electrical and Woods Network adjustments primarily related to the reclassification between goodwill and int angible assets.

NU's reporting units that maintain goodwill are generally consistent with the operating segments underlying the reportable segments identified in Note 15, "Segment Information," to the consolidated financial statements. Consistent with the way management reviews the operating results of its reporting units, NU's reporting units under the NU Enterprises reportable segment include: 1) the merchant energy reporting unit and 2) the energy services reporting unit. The merchant energy reporting unit is comprised of the operations of Select Energy, NGC and the generation operations of HWP, while the energy services reporting unit is comprised of the operations of SESI, NGS and Woods Network. As a result, NU's reporting units that maintain goodwill are as follows: the Yankee Gas reporting unit, which is classified under the Utility Group - gas reportable segment; the merchant energy reporting un it, which is classified under the NU Enterprises - merchant energy reportable segment; and the energy services reporting unit, which is classified under NU Enterprises - services and other.

NU has completed its impairment analyses as of October 1, 2004, for all reporting units that maintain goodwill and has determined that no impairment exists. In completing these analyses, the fair values of the reporting units were estimated using both discounted cash flow methodologies and an analysis of comparable companies or transactions.

At December 31, 2004, NU maintained $319.9 million of goodwill that is no longer being amortized, $10.8 million of identifiable intangible assets subject to amortization and $8.5 million of intangible assets not subject to amortization. At December 31, 2003, NU maintained $319.9 million of goodwill that is no longer being amortized, $14.4 million of identifiable intangible assets subject to amortization and $8.5 million of intangible assets not subject to amortization. A summary of NU's goodwill balances at December 31, 2004 and December 31, 2003, by reportable segment and reporting unit is as follows:

	At December 31,
(Millions of Dollars)	2004	2003
Utility Group - Gas:
Yankee Gas	$287.6	$287.6
NU Enterprises:
Merchant Energy	3.2	3.2
Energy Services	29.1	29.1
Totals	$319.9	$319.9

The goodwill recorded related to the acquisition of Yankee Gas is not being recovered from the customers of Yankee Gas.

At December 31, 2004 and December 31, 2003, NU’s intangible assets and accumulated amortization, all of which relates to NU Enterprises, consisted of the following:

	At December 31, 2004
*(Millions of Dollars)*	Gross Balance	Accumulated Amortization	Net Balance
Intangible assets subject to amortization:
Exclusivity agreement	$17.7	$ 9.8	$ 7.9
Customer list	6.6	3.7	2.9
Totals	$24.3	$13.5	$10.8
Intangible assets not subject to amortization:
Customer relationships	$5.2
Tradenames	3.3
Totals	$8.5

	At December 31, 2003
(Millions of Dollars)	Gross Balance	Accumulated Amortization	Net Balance
Intangible assets subject to amortization:
Exclusivity agreement	$17.7	$7.2	$10.5
Customer list	6.6	2.7	3.9
Totals	$24.3	$9.9	$14.4
Intangible assets not subject to amortization:
Customer relationships	$5.2
Tradenames	3.3
Totals	$8.5

NU recorded amortization expense of $3.6 million and $3.7 million for the years ended December 31, 2004 and 2003, respectively, related to these intangible assets. Substantially all of the intangible assets subject to amortization are being amortized over a period of 8.5 years.

Based on the current amount of intangible assets subject to amortization, the estimated annual amortization expense for each of the succeeding 5 years from 2005 through 2009 is $3.6 million in 2005 through 2007 and no amortization expense in 2008 or 2009. These amounts may vary as acquisitions and dispositions occur in the future.

6. Commitments and Contingencies

Regulatory Developments and Rate Matters

Connecticut:

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

On April 1, 2004, CL&P filed its 2003 CTA and SBC reconciliation with the Connecticut Department of Public Utility Control (DPUC), which compares CTA and SBC revenues to revenue requirements. A final decision in the 2003 CTA and SBC docket was issued on August 4, 2004 and ordered a refund to customers of $88.5 million over a seven-month period beginning with October 2004 consumption.

In the 2001 CTA and SBC reconciliation filing, and subsequently in a September 10, 2002 petition to reopen related proceedings, CL&P requested that a deferred intercompany tax liability associated with the intercompany sale of generation assets be excluded from the calculation of CTA revenue requirements. On September 10, 2003, the DPUC issued a final decision denying CL&P's request, and on October 24, 2003, CL&P appealed the DPUC's final decision to the Connecticut Superior Court. The appeal has been fully briefed and argued. A decision from the court is not expected to be issued until the second quarter of 2005. If CL&P's request is granted through these court proceedings, then there could be additional amounts due to CL&P from its customers. The 2004 impact of including the deferred intercompany liability in CTA revenue requirements has been a reduction of approximately $19 .3 million in revenue.

New Hampshire:

SCRC Reconciliation Filings: The SCRC allows PSNH to recover its stranded costs. On an annual basis, PSNH files with the NHPUC a SCRC reconciliation filing for the preceding calendar year. This filing includes the reconciliation of stranded cost revenues billed with stranded costs, and transition energy service and default energy service (TS/DS) revenues billed with TS/DS costs. The NHPUC reviews the filing, including a prudence review of PSNH's generation operations. The cumulative deferral of SCRC revenues in excess of costs was $208.6 million at December 31, 2004. This cumulative deferral will decrease the amount of non-securitized stranded costs that will have to be recovered from PSNH's customers in the future from $411.3 million to $202.7 million.

The 2003 SCRC reconciliation filing was filed with the NHPUC on April 30, 2004, and a stipulation and settlement agreement between PSNH, the Office of Consumer Advocate and NHPUC staff was filed with the NHPUC on October 4, 2004. Under the terms of the settlement agreement, no costs related to the recovery of stranded costs or the cost of providing transition energy service were disallowed and the NHPUC staff agreed to accept the 2003 SCRC filing without change. On October 29, 2004, the NHPUC issued an order accepting the settlement agreement as filed.

SCRC and TS/DS rate mechanisms, consistent with accrual accounting. At December 31, 2004, the PSNH unbilled revenue balance related to SCRC and TS/DS was $11.7 million and $16.7 million, respectively. If approved, this change will allow for the inclusion of accrued unbilled revenue balances in the recovery of SCRC and TS/DS costs. Management believes that the unbilled revenue balance related to SCRC and TS/DS is probable of being recovered from PSNH's customers.

Massachusetts:

Transition Cost Reconciliation: On March 31, 2004, WMECO filed its 2003 transition cost reconciliation with the Massachusetts Department of Telecommunications and Energy (DTE). This filing reconciled the recovery of generation-related stranded costs for calendar year 2003. The DTE has not initiated its investigation into this filing. WMECO expects to file its 2004 transition cost reconciliation with the DTE on March 31, 2005. The DTE has combined the 2003 transition cost reconciliation filing and the 2004 transition cost reconciliation filing into a single proceeding. The timing of this decision in the combined proceeding is uncertain, but management does not expect the outcome to have a material adverse impact on WMECO's net income or financial position.

Environmental Matters

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

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

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

The amounts recorded as environmental liabilities on the consolidated balance sheets represent management’s best estimate of the liability for environmental costs and takes into consideration site assessment and remediation costs. Based on currently available information for estimated site assessment and remediation costs at December 31, 2004 and 2003, NU had $38.7 million and $40.8 million, respectively, recorded as environmental reserves. A reconciliation of the total reserve amount at December 31, 2004 and 2003 is as follows:

(Millions of Dollars)	For the Years Ended December 31,
	2004	2003
Balance at beginning of year	$40.8	$41.9
Additions and adjustments	6.4	4.1
Payments	(8.5)	(5.2)
Balance at end of year	$38.7	$40.8

NU currently has 53 sites included in the environmental reserve. Of those 53 sites, 25 sites are in the remediation or long-term monitoring phase, 22 sites have had site assessments completed and the remaining six sites are in the preliminary stages of site assessment.

For nine sites that are included in the company's liability for environmental costs, the information known and nature of the remediation options at those sites allow an estimate of the range of losses to be made. These sites primarily relate to manufactured gas plant (MGP) sites. At December 31, 2004, $8.1 million has been accrued as a liability for these sites, which represents management's best estimate of the liability for environmental costs. This amount differs from an estimated range of loss from $4.9 million to $25.8 million as management utilizes the probabilistic model approach to make its estimate of the liability for environmental costs. For the 45 remaining sites for which an estimate is based on the probabilistic model approach, determining a range of estimated losses is not possible.

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

At December 31, 2004, there are ten 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.

MGP Sites: MGP sites comprise the largest portion of NU's environmental liability. MGPs are sites that manufactured gas from coal produced certain byproducts that may pose risk to human health and the environment. At December 31, 2004 and 2003, $33.2 million and $36.3 million, respectively, represent amounts for the site assessment and remediation of MGPs. At December 31, 2004 and 2003, the five largest MGP sites comprise approximately 58 percent and 57 percent, respectively, of the total MGP environmental liability.

At December 31, 2004, NU has one site that is held for sale. The site, a former MGP site, is currently held for sale under a pending purchase and sale agreement. NU is currently remediating the property and has been deferring the costs associated with those remediation efforts as allowed by a

regulatory order. At December 31, 2004, NU had $7.9 million related to remediation efforts at the property and other sale costs recorded in other deferred debits on the accompanying consolidated balance sheets.

A final decision was reached by the DPUC on January 19, 2005, which approved the sale proceedings of the 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 $13.8 million ($8.3 million after-tax). The purchase and sale agreement releases NU from all environmental claims arising out of or in connection with the property.

CERCLA Matters: The Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA) and its amendments or state equivalents impose joint and several strict liabilities, regardless of fault, upon generators of hazardous substances resulting in removal and remediation costs and environmental damages. Liabilities under these laws can be material and in some instances may be imposed without regard to fault or for past acts that may have been lawful at the time they occurred. NU has five 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 need to 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, as necessary.

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

Spent Nuclear Fuel Disposal Costs

Under the Nuclear Waste Policy Act of 1982 (the Act), CL&P, PSNH, WMECO, and NAEC must pay the DOE for the disposal of spent nuclear fuel and high-level radioactive waste. The DOE is responsible for the selection and development of repositories for, and the disposal of, spent nuclear fuel and high-level radioactive waste. For nuclear fuel used to generate electricity prior to April 7, 1983 (Prior Period Fuel) for CL&P and WMECO, an accrual has been recorded for the full liability, and payment must be made prior to the first delivery of spent fuel to the DOE. Until such payment is made, the outstanding balance will continue to accrue interest at the 3-month treasury bill yield rate. At December 31, 2004 and 2003, fees due to the DOE for the disposal of Prior Period Fuel were $259.7 million and $256.4 million, respectively, including interest costs of $177.6 million and $174.3 million, respective ly.

During 2004, WMECO established a trust, which holds marketable securities, to fund amounts due to the DOE for the disposal of WMECO's prior period fuel. For further information on this trust see Note 8, "Marketable Securities," to the consolidated financial statements.

Long-Term Contractual Arrangements

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 (Entergy) for approximately $180 million. Under the terms of the sale, CL&P, PSNH and WMECO will continue to buy approximately 16 percent of the plant's output through March 2012 at a range of fixed prices. The total cost of purchases under contracts with VYNPC amounted to $26.8 million in 2004, $29.9 million in 2003 and $27.6 million in 2002.

Electricity Procurement Contracts: CL&P, PSNH and WMECO have entered into various arrangements for the purchase of electricity. The total cost of purchases under these arrangements amounted to $323.3 million in 2004, $283.4 million in 2003 and $278.3 million in 2002. These amounts relate to IPP contracts and do not include contractual commitments related to CL&P's standard offer, PSNH’s short-term power supply management or WMECO's standard offer and default service.

Natural Gas Procurement Contracts: Yankee Gas has entered into long-term contracts for the purchase of a specified quantity of natural gas in the normal course of business as part of its portfolio to meet its actual sales commitments. These contracts have expiration dates in 2006 and 2007. The total cost of Yankee Gas’ procurement portfolio, including these contracts, amounted to $250.5 million in 2004, $218.6 million in 2003 and $158 million in 2002.

Hydro-Quebec: Along with other New England utilities, CL&P, PSNH, WMECO, and HWP have entered into agreements to support transmission and terminal facilities to import electricity from the Hydro-Quebec system in Canada. CL&P, PSNH, WMECO, and HWP are obligated to pay, over a 30-year period ending in 2020, their proportionate shares of the annual O&M expenses and capital costs of those facilities. The total cost of these agreements amounted to $23.7 million in 2004, $25.3 million in 2003 and $26 million in 2002.

Yankee Gas Liquefied Natural Gas (LNG) Storage Facility:In 2004, Yankee Gas signed a contract for the design and building of the LNG facility. Yankee Gas anticipates that the facility will become operational in late 2007 in time for the 2007/2008 heating season. Certain future estimated construction expenditures totaling $21.4 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. The remaining $21.4 million does not include $12.9 million that was spent through 2004.

Northern Wood Power Project: In October 2004, PSNH received the approvals necessary to begin construction related to the conversion of one of three 50 megawatt units at the coal-fired Schiller Station to burn wood. Construction of the $75 million Northern Wood Power Project has begun

and is expected to be completed by late 2006. Certain other estimated construction expenditures totaling $8.6 million are not included in the contract signed to perform the Schiller Station conversion and are not included in the table of estimated future annual Utility Group costs below.

Yankee Companies FERC-Approved 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 CL&P, PSNH and WMECO. These companies in turn pass these costs on to their customers through state regulatory commission-approved retail rates. YAEC and MYAPC received FERC approval to collect all presently estimated decommissioning costs. The table of estimated future annual Utility Group costs below includes the decommissioning and closure costs for YAEC, MYAPC and CYAPC.

Estimated Future Annual Utility Group Costs: The estimated future annual costs of NU’s significant long-term contractual arrangements are as follows:

(Millions of Dollars)

2005

2006

2007

2008

2009

Thereafter

VYNPC

$ 27.1

$ 28.5

$ 27.5

$ 27.9

$ 30.9

$ 66.5

Electricity
procurement
contracts

319.0

322.0

253.0

218.3

190.0

1,103.1

Natural gas
procurement
contracts

201.8

180.5

82.7

38.5

38.3

103.2

Hydro-Quebec

24.8

24.4

22.8

20.4

19.6

215.6

Yankee Gas
LNG facility

27.9

41.8

4.0

Northern Wood
Power Project

39.3

7.5

Yankee

Companies

FERC-

approved

billings

89.6

78.2

71.0

60.9

57.2

56.2

Totals

$729.5

$682.9

$461.0

$366.0

$336.0

$1,544.6

NU Enterprises Purchase Agreements: Select Energy maintains long-term agreements to purchase energy in the normal course of business as part of its portfolio of resources to meet its actual or expected sales commitments. The aggregate amount of these purchase contracts was $6.2 billion at December 31, 2004 as follows:

(Millions of Dollars)
Year
2005	$4,940.1
2006	650.8
2007	156.4
2008	99.0
2009	85.6
Thereafter	261.1
Total	$6,193.0

Select Energy’s purchase contract amounts can exceed the amount expected to be reported in fuel, purchased and net interchange power because energy trading transactions are classified in revenues.

The amounts and timing of Select Energy's purchase agreements could be impacted by the NU Enterprises' strategic review.

Deferred Contractual Obligations

CYAPC's estimated decommissioning and plant closure costs for the period 2000 through 2023 have increased by approximately $395 million over the April 2000 estimate of $436 million approved by the FERC in a 2000 rate case settlement. The revised estimate reflects the increases in the projected costs of spent fuel storage, increased security and liability and property insurance costs, and the fact that CYAPC is now self-performing all work to complete the decommissioning of the plant due to the termination of the decommissioning contract with Bechtel in July 2003. NU's share of CYAPC's increase in decommissioning and plant closure costs is approximately $194 million. On July 1, 2004, CYAPC filed with the FERC for recovery of these increased costs. In the filing, CYAPC sought to increase its annual decommissioning collections from $16.7 million to $93 million for a six-year period beginning on January 1, 2005. On August 30, 2004, the FERC issued an order accepting the rates, with collection beginning on February 1, 2005, subject to refund, and scheduled hearings for May 2005. In total, NU's estimated remaining decommissioning and plant closure obligation for CYAPC is $308.7 million at December 31, 2004.

granting further consideration regarding the DPUC's and OCC's petition for reconsideration. No hearing date has been established for this reconsideration.

CYAPC is currently in litigation with Bechtel over the termination of its decommissioning contract. On June 13, 2003, CYAPC gave notice of the termination of its contract with Bechtel for the decommissioning of its nuclear power plant. CYAPC terminated the contract due to Bechtel's incomplete and untimely performance and refusal to perform the remaining decommissioning work. Bechtel has departed the site and the decommissioning responsibility has been transitioned to CYAPC, which has recommenced the decommissioning process.

In the prejudgment remedy proceeding before the Connecticut Supreme Court (the Court), Bechtel sought garnishment of the CYAPC decommissioning trust and related payments. In October 2004, Bechtel and CYAPC entered into an agreement under which Bechtel waived its right to seek garnishment of the decommissioning trust and related payments in return for the potential attachment of CYAPC's real property in Connecticut and the escrowing of $41.7 million the sponsors are scheduled to pay to CYAPC through June 30, 2007 in respect to CYAPC's common equity. This stipulation is subject to approval of the Court and would not be implemented until the Court found that such assets were subject to attachment. CYAPC has contested the attachability of such assets. The DPUC is an intervener in this proceeding.

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

The Yankee Companies also filed litigation in 1998 charging that the federal government breached contracts it entered into with each company in 1983 under the Act. Under the Act, the DOE was to begin removing spent nuclear fuel from the nuclear plants of YAEC, MYAPC and CYAPC no later than January 31, 1998 in return for payments by each company into the nuclear waste fund. No fuel has been collected by the DOE, and spent nuclear fuel is stored on the sites of the Yankee Companies' plants. YAEC, MYAPC and CYAPC collected the funds for payments into the nuclear waste fund from wholesale utility customers under FERC-approved contract rates. The wholesale utility customers in turn collect these payments from their retail electric customers. The Yankee Companies' individual damage claims attributed to the government's breach totaling $548 million are specific to each plant and include incremental stor age, security, construction and other costs through 2010, which is the earliest date the DOE projects that it will begin removing nuclear fuel. The YAEC damage claim is $191 million, the MYAPC claim is $160 million and the CYAPC claim is $197 million.

The DOE trial ended on August 31, 2004 and a verdict has not been reached. The current Yankee Companies' rates do not include an amount for recovery of damages in this matter. Management can predict neither the outcome of this matter nor its ultimate impact on NU.

NRG Energy, Inc. Exposures

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

Impacts of Decision to Exit NU Enterprises' Wholesale Marketing Contracts and to Explore Ways to Divest the NU Enterprises' Services Businesses

The March 2005 decision to exit NU Enterprises' wholesale marketing business and to explore ways to divest NU Enterprises' services businesses creates certain potential loss contingencies. They could be material and could include:

The impairment of long-lived assets if they are no longer held and used and become held for sale at expected sales prices that are less than carrying values.

The impairment of intangible assets if expected cash flows that support them are reduced to below their carrying values.

The recognition of closure costs such as severance, benefit plan curtailments, and lease termination payments.

The recognition of losses associated with settling energy contracts currently accounted for on an accrual method of accounting that have negative fair values at the time of settlement.

NU expects to record a charge in the first quarter of 2005 associated with the wholesale marketing and energy services businesses. The level of that charge will depend on a number of factors, including how the disposition of those businesses is accomplished.

Consolidated Edison, Inc. Merger Litigation

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

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

An intervener in this litigation has made the claim that NU shareholders at March 5, 2001 are entitled to damages from Con Edison, if any, and not current NU shareholders.

7. 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, Restricted Cash – LMP, and Special Deposits: The carrying amounts approximate fair value due to the short-term nature of these cash items.

SERP Investments: Investments held for the benefit of the SERP are recorded at fair market value based upon quoted market prices. The investments having a cost basis of $50.1 million and $33.8 million held for benefit of the SERP were recorded at their fair market values at December 31, 2004 and 2003, of $55.1 million and $36.9 million, respectively. For further information regarding the SERP liabilities and related investments, see Note 4E, "Employee Benefits - Supplemental Executive Retirement and Other Plans," and Note 8, "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 $49.5 million were recorded at their fair market value at December 31, 2004 of $49.3 million. For further information regarding these investments, see Note 8, "Marketable Securities," to the consolidated financial statements.

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

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

	At December 31, 2003
(Millions of Dollars)	Carrying Amount	Fair Value
Preferred stock not subject to mandatory redemption	$ 116.2	$ 87.5
Long-term debt -
First mortgage bonds	743.0	833.3
Other long-term debt	1,810.7	1,896.5
Rate reduction bonds	1,730.0	1,860.7

Other long-term debt includes $259.7 million and $256.4 million of fees and interest due for spent nuclear fuel disposal costs at December 31, 2004 and 2003, 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.

8. Marketable Securities

The following is a summary of NU’s available-for-sale securities related to NU's SERP securities which are included in deferred debits and other assets - other on the accompanying consolidated balance sheets, and WMECO's prior spent nuclear fuel trust:

	At December 31,
	2004	2003
(Millions of Dollars)
SERP securities	$ 55.1	$36.9
WMECO prior spent nuclear fuel trust	49.3	-
Totals	$104.4	$36.9

At December 31, 2004

Amortized

Cost

Pre-Tax

Gross

Unrealized

Gains

Pre-Tax

Gross

Unrealized

Losses

Estimated

Fair

Value

United States equity

securities

$19.3

$3.8

$(0.2)

$ 22.9

Non-United States

equity securities

5.6

1.3

6.9

Fixed income securities

74.7

0.3

(0.4)

74.6

Totals

$99.6

$5.4

$(0.6)

$104.4

At December 31, 2003

Amortized

Cost

Pre-Tax

Gross

Unrealized

Gains

Pre-Tax

Gross

Unrealized

Losses

Estimated

Fair

Value

United States equity

securities

$13.2

$2.5

$(0.1)

$15.6

Non-United States

equity securities

3.4

0.7

4.1

Fixed income securities

17.2

0.1

(0.1)

17.2

Total SERP securities

$33.8

$3.3

$(0.2)

$36.9

At December 31, 2004 and 2003 NU has 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.

For information related to the change in net unrealized holding gains and losses included in shareholders' equity, see Note 12, "Accumulated Other Comprehensive Income/(Loss)," to the consolidated financial statements.

For years ended December 31, 2004, 2003, and 2002, realized gains and losses recognized on the sale of available-for-sale securities are as follows (in millions):

	Realized Gains	Realized Losses	Net Realized Gains/(Losses)
2004	$0.9	$(0.3)	$0.6
2003	0.5	(0.1)	0.4
2002	0.8	(1.4)	(0.6)

NU utilizes the specific identification basis method for the 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 totaled $56.7 million, $34.1 million, and $7.5 million for the years ended December 31, 2004, 2003 and 2002, respectively.

At December 31, 2004, the contractual maturities of the available-for-sale securities are as follows (in millions):

	Amortized Cost	Estimated Fair Value
Less than one year	$47.6	$ 52.5
One to five years	21.9	21.7
Six to ten years	6.0	6.0
Greater than ten years	24.1	24.2
Total	$99.6	$104.4

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

9. Leases

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

Capital lease rental payments charged to operating expense were $3.3 million in 2004, $3.7 million in 2003 and $1.7 million in 2002. Interest included in capital lease rental payments was $2 million in 2004, $2.3 million in 2003 and $0.6 million in 2002. Operating lease rental payments charged to expense were $16.3 million in 2004, $16.1 million in 2003 and $14.5 million in 2002.

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, 2004 are as follows:

(Millions of Dollars)	Capital Leases	Operating Leases
2005	$ 3.1	$ 30.9
2006	2.9	28.5
2007	2.6	24.5
2008	2.3	21.0
2009	2.0	12.5
Thereafter	18.1	41.3
Future minimum lease payments	31.0	$158.7
Less amount representing interest	16.2
Present value of future minimum lease payments	$14.8

10. Long-Term Debt

Long-term debt maturities and cash sinking fund requirements on debt outstanding at December 31, 2004, for the years 2005 through 2009 and thereafter, are as follows:

(Millions of Dollars)
Year
2005	$ 90.8
2006	27.0
2007	8.2
2008	159.8
2009	61.5
Thereafter	2,277.7
Total	$2,625.0

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

CL&P has $315.3 million of pollution control notes 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 Pollution Control Revenue Bonds (PCRBs) with bond insurance and secured by the first mortgage bonds. For financial reporting purposes, this debt is not considered to be first mortgage bonds unless CL&P failed to meet its obligations under the PCRBs.

PSNH entered into financing arrangements with the Business Finance Authority (BFA) of the state of New Hampshire, pursuant to which, the BFA issued five series of PCRBs and loaned the proceeds to PSNH. At December 31, 2004 and 2003, $407.3 million of the PCRBs were outstanding. PSNH’s obligation to repay each series of PCRBs is secured by bond insurance and the 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.

Long-term debt - first mortgage bonds at December 31, 2004 includes the issuance of $280 million, $125 million and $50 million of long-term debt related to CL&P, Yankee Gas and PSNH during 2004, respectively.

The weighted-average effective interest rate on the variable-rate pollution control notes ranged from 1.24 percent to 1.26 percent for 2004 and 0.99 percent to 1.08 percent for 2003.

The interest rate of 3.35 percent is effective through October 1, 2008 at which time the bonds will be remarketed, and the interest rate will be adjusted.

Other long-term debt – other at December 31, 2004, includes the issuance of $7.5 million and $50 million of long-term debt related to SESI and WMECO during 2004. In 2004, SESI sold $30 million of receivables related to the energy savings contract projects. The transfer of receivables to the unaffiliated third party qualified as a sale under SFAS No. 140. Accordingly, the $30 million sold at December 31, 2004 is not included as debt in the consolidated financial statements.

For information regarding fees and interest due for spent nuclear fuel disposal costs, see Note 1X, "Marketable Securities," and Note 6C, "Commitments and Contingencies - Spent Nuclear Fuel Disposal Costs," to the consolidated financial statements.

The fair value of the NU parent 7.25 percent amortizing note, due 2012 in the amount of $263 million is hedged with a fixed to floating interest rate swap. The change in fair value of the debt was recorded as an adjustment to long-term debt with an equal and offsetting adjustment to derivative assets for the change in fair value of the fixed to floating interest rate swap.

11. Dividend Restrictions

The Federal Power Act, the Public Utility Holding Act of 1935 (the Act), and certain state statutes limit the payment of dividends by CL&P, PSNH, and WMECO to their respective retained earnings balances. Yankee Gas is also subject to the restrictions under the 1935 Act.

Certain consolidated subsidiaries also have dividend restrictions imposed by their long-term debt agreements. These restrictions limit the amount of retained earnings available for NU common dividends. At December 31, 2004, retained earnings available for payment of dividends totaled $343.5 million.

NGC is subject to certain dividend payment restrictions under its bond covenants.

The Utility Group credit agreement also limits dividend payments subject to the requirements that each subsidiaries' total debt to total capitalization ratio does not exceed 65 percent.

12. Accumulated Other Comprehensive Income/(Loss)

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

(Millions of Dollars)

December 31,

2003

Current Period Change

December 31,

2004

Qualified cash flow

hedging instruments

$24.8

$(28.3)

$(3.5)

Unrealized gains

on securities

2.0

1.2

3.2

Minimum supplemental

executive retirement

pension liability

adjustments

(0.8)

(0.1)

(0.9)

Accumulated other

comprehensive income

$26.0

$(27.2)

$(1.2)

(Millions of Dollars)

December 31,

2002

Current

Period

Change

December 31,

2003

Qualified cash flow

hedging instruments

$15.5

$ 9.3

$24.8

Unrealized

(losses)/gains

on securities

(0.1)

2.1

2.0

Minimum supplemental

executive retirement

pension liability

adjustments

(0.5)

(0.3)

(0.8)

Accumulated other

comprehensive income

$14.9

$11.1

$26.0

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

(Millions of Dollars)	2004	2003	2002
Qualified cash flow hedging instruments	$14.4	$(6.4)	$(33.1)
Unrealized (losses)/gains on securities	(0.7)	(1.4)	3.3
Minimum supplemental executive retirement pension liability adjustments	-	- -	- -
Accumulated other comprehensive income	$13.7	$(7.8)	$(29.8)

Accumulated other comprehensive income/(loss) fair value adjustments of NU's qualified cash flow hedging instruments are as follows:

	At December 31,
(Millions of Dollars, Net of Tax)	2004	2003
Balance at beginning of year	$24.8	$15.5
Hedged transactions recognized into earnings	(57.8)	(5.3)
Change in fair value	25.0	5.0
Cash flow transactions entered into for the period	4.5	9.6
Net change associated with the current period hedging transactions	(28.3)	9.3
Total fair value adjustments included in accumulated other comprehensive income	$(3.5)	$24.8

13. 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 2004, 2003 and 2002, 696,994 options, 355,153 options and 2,968,933 options, respectively, were excluded from the following table as these options were antidilutive. The following table sets forth the components of basic and diluted EPS.

(Millions of Dollars, except share information)	2004	2003	2002
Income before cumulative effect of accounting change	$116.6	$121.1	$152.1
Cumulative effect of accounting change, net of tax benefit	-	(4.7)	-
Net income	$116.6	$116.4	$152.1
Basic EPS common shares outstanding (average)	128,245,860	127,114,743	129,150,549
Dilutive effect of employee stock options	150,216	125,981	190,811
Fully diluted EPS common shares outstanding (average)	128,396,076	127,240,724	129,341,360
Basic and fully diluted EPS:
Income before cumulative effect of accounting change	$0.91	$0.95	$1.18
Cumulative effect of accounting change, net of tax benefit	-	(0.04)	-
Net income	$0.91	$0.91	$1.18

14. Nuclear Generation Asset Divestitures

Seabrook: On November 1, 2002, CL&P and NAEC consummated the sale of their 40.04 percent combined ownership interest in Seabrook to a subsidiary of FPL. CL&P, NAEC and certain other of the joint owners collectively sold 88.2 percent of Seabrook to FPL. NU received approximately $367 million of total cash proceeds from the sale of Seabrook and another approximately $17 million from Baycorp Holdings, Ltd. (Baycorp), as a result of the sale of its interest in Seabrook. A portion of this cash was used to repay all $90 million of NAEC's outstanding debt and other short-term debt, to return a portion of NAEC's equity to NU and was used to pay approximately $93 million in taxes. The remaining proceeds received by NAEC were refunded to PSNH through the Seabrook Power Contracts. As part of the sale, FPL assumed responsibility for decommissioning Seabrook. NAEC and CL&P recor ded a gain on the sale in the amount of approximately $187 million, which was primarily used to offset stranded costs.

In the third quarter of 2002, CL&P and NAEC received regulatory approvals for the sale of Seabrook from the DPUC and the NHPUC. As a result of these approvals, CL&P and NAEC eliminated $0.6 million and $13.9 million, respectively, on an after-tax basis, of reserves related to their respective ownership shares of certain Seabrook assets.

On October 10, 2000, NU reached an agreement with Baycorp, a 15 percent joint owner of Seabrook, under which NU guaranteed a minimum sale price and NU and Baycorp would share the excess proceeds if the sale of Seabrook resulted in proceeds of more than $87.2 million related to the sale of Baycorp's 15 percent ownership interest. The agreement also limited any accelerated decommissioning funding required to be funded by Baycorp for decommissioning as part of the sale process. NU received approximately $17 million in 2002 in connection with this agreement. This amount is included in the $38.7 million of pre-tax Seabrook-related gains included in other income/(loss).

VYNPC: On July 31, 2002, VYNPC consummated the sale of its nuclear generating plant to a subsidiary of Entergy Corporation (Entergy) for approximately $180 million. As part of the sale, Entergy assumed responsibility for decommissioning VYNPC's nuclear generating unit. In 2003, CL&P, PSNH and WMECO sold their collective 17 percent ownership interest in VYNPC. CL&P, PSNH and WMECO will continue to buy approximately 16 percent of the plant's output through March 2012 at a range of fixed prices.

15. Segment Information

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. Based on different information that is reviewed by NU's new chief operating decision maker on January 1, 2004, separate detailed information regarding the Utility Group's transmission businesses and NU Enterprises' merchant energy business is now included in the following segment information. Segment information for all periods has been restated to conform to the current presentation except for total asset information for the transmission business segment as this information is not available.

The Utility Group segment, including both the regulated electric distribution and transmission businesses, as well as the gas distribution business comprised of Yankee Gas, represents approximately 69 percent, 72 percent, and 78 percent of NU's total revenues for the years ended December 31, 2004, 2003 and 2002 respectively, and includes the operations of the regulated electric utilities, CL&P, PSNH and WMECO, whose complete financial statements are included in NU's report on Form 10-K. PSNH's distribution segment includes generation activities. Also included in NU's combined 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 primarily are derived from residential, commercial and industrial customers and are not dependent on any single customer.

The NU Enterprises merchant energy business segment includes Select Energy, NGC, the generation operations of HWP, and their respective subsidiaries, while the NU Enterprises services and other business segment includes SESI, NGS, Woods Network, and their respective subsidiaries and intercompany eliminations. The results of NU Enterprises parent are also included within services and other.

Select Energy has served a portion of CL&P's transitional standard offer (TSO) or standard offer load for 2004, 2003 and 2002. Total Select Energy revenues from CL&P for CL&P's standard offer load, TSO load and for other transactions with CL&P, represented $611.3 million or 21 percent for the year ended December 31, 2004, approximately $688 million or 27 percent for the year ended December 31, 2003, and approximately $631 million or 35 percent for the year ended December 31, 2002, of total NU Enterprises' revenues. Total CL&P purchases from Select Energy are eliminated in consolidation.

WMECO's purchases from Select Energy for standard offer and default service and for other transactions with Select Energy represented approximately $108.5 million, $143 million and $14 million of total NU Enterprises' revenues for the years ended December 31, 2004, 2003 and 2002 respectively. Total WMECO purchases from Select Energy are eliminated in consolidation.

Select Energy revenues related to contracts with NSTAR companies represented $300.2 million or 11 percent of total NU Enterprises' revenues for the year ended December 31, 2004. Select Energy also provides basic generation service in the New Jersey and Maryland market. Select Energy revenues related to these contracts represented $334.2 million or 12 percent of total NU Enterprises' revenues for the year ended December 31, 2004, $380.4 million or 15 percent for the year ended December 31, 2003 and approximately $207.4 million or 12 percent for the year ended December 31, 2002. No other individual customer represented in excess of 10 percent of NU Enterprises' revenues for the years ended December 31, 2004, 2003, or 2002.

Other in the NU consolidated tables includes the results for Mode 1 Communications, Inc., an investor in NEON, the results of the non-energy-related subsidiaries of Yankee (Yankee Energy Services Company, RMS, Yankee Energy Financial Services, and NorConn Properties, Inc.), the non-energy operations of HWP, the results of NU's parent and service companies, and write-downs of certain of the company's investments. Interest expense included in other primarily relates to the debt of NU parent. Other includes after-tax investment write-downs totaling $8.8 million in 2004 and $11 million in 2002 related to Acumentrics and NEON. No investment write-downs related to Acumentrics or NEON were recorded in 2003. Virtually all of the assets and liabilities of RMS were sold on June 30, 2004.

NU's segment information for the years ended December 31, 2004, 2003, and 2002 is as follows (some amounts between segment schedules may not agree due to rounding):

	For the Year Ended December 31, 2004
	Utility Group
	Distribution			NU
(Millions of Dollars)	Electric	Gas	Transmission	Enterprises	Other	Eliminations	Totals
Operating revenues	$4,040.1	$407.8	$140.7	$2,855.1	$ 289.6	$(1,046.6)	$6,686.7
Depreciation and amortization	(458.5)	(26.2)	(21.6)	(19.1)	(16.4)	13.7	(528.1)
Other operating expenses	(3,268.3)	(347.0)	(68.5)	(2,817.1)	(284.5)	1,039.7	(5,745.7)
Operating income/(loss)	313.3	34.6	50.6	18.9	(11.3)	6.8	412.9
Interest expense, net of AFUDC	(159.1)	(16.6)	(12.3)	(51.2)	(26.2)	11.9	(253.5)
Interest income	4.8	0.1	0.3	8.5	12.9	(12.9)	13.7
Other income/(loss), net	15.4	(1.0)	(0.2)	(5.6)	76.7	(84.5)	0.8
Income tax (expense)/benefit	(56.8)	(3.0)	(8.9)	14.3	15.3	(12.6)	(51.7)
Preferred dividends	(5.6)	-	-	-	-	-	(5.6)
Net income/(loss)	$ 112.0	$ 14.1	$ 29.5	$ (15.1)	$ 67.4	$ (91.3)	$ 116.6
Total assets (1)	$8,410.8	$1,147.9	$ -	$2,176.2	$4,313.1	$(4,392.2)	$11,655.8
Cash flows for total investments in plant	$ 390.0	$ 56.6	$163.9	$ 17.6	$ 15.7	$ -	$ 643.8

	For the Year Ended December 31, 2003
	Utility Group
	Distribution			NU
(Millions of Dollars)	Electric	Gas	Transmission	Enterprises	Other	Eliminations	Totals
Operating revenues	$ 3,865.8	$ 361.5	$117.9	$2,574.8	$ 257.9	$(1,108.7)	$ 6,069.2
Depreciation and amortization	(483.8)	(23.4)	(18.7)	(19.6)	(14.2)	10.3	(549.4)
Other operating expenses	(3,072.1)	(311.7)	(51.9)	(2,509.4)	(238.2)	1,087.7	(5,095.6)
Operating income/(loss)	309.9	26.4	47.3	45.8	5.5	(10.7)	424.2
Interest expense, net of AFUDC	(166.1)	(13.1)	(3.5)	(49.6)	(23.5)	9.3	(246.5)
Interest income	3.8	-	0.1	8.0	9.4	(9.5)	11.8
Other income/(loss), net	(0.2)	(2.4)	(0.9)	(5.6)	90.9	(93.9)	(12.1)
Income tax (expense)/benefit	(44.8)	(3.6)	(14.8)	(2.0)	14.6	(0.1)	(50.7)
Preferred dividends	(5.6)	-	-	-	-	-	(5.6)
Income/(loss) before cumulative effect of accounting change	97.0	7.3	28.2	(3.4)	96.9	(104.9)	121.1
Cumulative effect of accounting change, net of tax benefit	-	-	-	-	(4.7)	-	(4.7)
Net income/(loss)	$ 97.0	$ 7.3	$ 28.2	$ (3.4)	$ 92.2	$ (104.9)	$ 116.4
Total assets (1)	$ 8,219.8	$1,068.6	$ -	$2,047.8	$4,314.8	$(4,434.5)	$11,216.5
Cash flows for total investments in plant	$ 365.8	$ 54.8	$ 96.3	$ 17.7	$ 29.0	$ -	$ 563.6

(1)

Information for segmenting total assets between electric distribution and transmission is not available at December 31, 2004 or December 31, 2003. On a NU consolidated basis, these distribution and transmission assets are disclosed in the electric distribution columns above.

	For the Year Ended December 31, 2002
	Utility Group
	Distribution			NU
(Millions of Dollars)	Electric	Gas	Transmission	Enterprises	Other	Eliminations	Totals
Operating revenues	$ 3,701.3	$282.0	$122.1	$1,800.8	$324.3	$(993.5)	$5,237.0
Depreciation and amortization	(600.1)	(24.0)	(18.0)	(21.6)	(18.8)	7.9	(674.6)
Other operating expenses	(2,701.4)	(218.1)	(46.4)	(1,818.5)	(299.2)	980.4	(4,103.2)
Operating income/(loss)	399.8	39.9	57.7	(39.3)	6.3	(5.2)	459.2
Interest expense, net of AFUDC	(182.5)	(14.2)	(1.9)	(43.9)	(35.5)	7.5	(270.5)
Interest income	4.1	0.1	-	6.5	7.7	(7.5)	10.9
Other income/(loss), net	16.7	(0.9)	(1.1)	(6.0)	161.9	(137.7)	32.9
Income tax (expense)/benefit	(107.4)	(7.3)	0.9	29.5	10.4	(0.9)	(74.8)
Preferred dividends	(5.6)	-	-	-	-	-	(5.6)
Net income/(loss)	$ 125.1	$ 17.6	$ 55.6	$ (53.2)	$150.8	$(143.8)	$ 152.1
Cash flows for total investments in plant	$ 333.5	$ 67.6	$ 57.9	$ 21.0	$ 30.5	$ -	$ 510.5

NU Enterprises' segment information for the years ended December 31, 2004, 2003, and 2002 is as follows. Eliminations are included in the services and other columns.

	NU Enterprises - For the Year Ended December 31, 2004
(Millions of Dollars)	Merchant Energy	Services and Other	Totals
Operating revenues	$2,580.5	$274.6	$2,855.1
Depreciation and amortization	(17.2)	(1.9)	(19.1)
Other operating expenses	(2,538.5)	(278.6)	(2,817.1)
Operating income	24.8	(5.9)	18.9
Interest expense	(43.8)	(7.4)	(51.2)
Interest income	1.6	6.9	8.5
Other (loss)/income, net	(2.0)	(3.6)	(5.6)
Income tax (expense)/benefit	7.3	7.0	14.3
Net income/(loss)	(12.1)	(3.0)	(15.1)
Total assets	$1,886.5	$289.7	$2,176.2
Cash flows for total investments in plant	$ 15.8	$ 1.8	$ 17.6

	NU Enterprises - For the Year Ended December 31, 2003
(Millions of Dollars)	Merchant Energy	Services and Other	Totals
Operating revenues	$2,345.6	$ 229.2	$ 2,574.8
Depreciation and amortization	(17.7)	(1.9)	(19.6)
Other operating expenses	(2,285.9)	(223.5)	(2,509.4)
Operating income	42.0	3.8	45.8
Interest expense	(42.4)	(7.2)	(49.6)
Interest income	0.8	7.2	8.0
Other (loss)/income, net	(5.7)	0.1	(5.6)
Income tax (expense)/benefit	(0.2)	(1.8)	(2.0)
Net income/(loss)	(5.5)	2.1	(3.4)
Total assets	$1,776.7	$ 271.1	$ 2,047.8
Cash flows for total investments in plant	$ 17.7	$ -	$ 17.7

	NU Enterprises - For the Year Ended December 31, 2002
(Millions of Dollars)	Merchant Energy	Services and Other	Totals
Operating revenues	$ 1,619.5	$ 181.3	$1,800.8
Depreciation and amortization	(20.0)	(1.6)	(21.6)
Other operating expenses	(1,637.2)	(181.3)	(1,818.5)
Operating income	(37.7)	(1.6)	(39.3)
Interest expense	(39.4)	(4.5)	(43.9)
Interest income	1.5	5.0	6.5
Other (loss)/income, net	(5.5)	(0.5)	(6.0)
Income tax (expense)/benefit	28.7	0.8	29.5
Net income/(loss)	(52.4)	(0.8)	(53.2)
Cash flows for total investment in plant	$ 21.0	$ -	$ 21.0

16. Restatement of Previously Issued Financial Statements

NU concluded that it incorrectly classified as unrestricted cash from counterparties amounts that should have been classified as cash and cash equivalents at December 31, 2003. These corrections reclassified unrestricted cash from counterparties to cash and cash equivalents because those funds were unrestricted and were used to fund or were available to fund the company's operations. The December 31, 2003 consolidated balance sheet has been restated for these corrections and a correction to decrease derivative assets and liabilities by the same amount in order to eliminate certain intercompany derivative assets and liabilities.

The effects of the revisions on the consolidated balance sheet as of December 31, 2003 and the consolidated statement of cash flows for the year ended December 31, 2003 are summarized in the following tables (in thousands):

Consolidated Balance Sheet	At December 31, 2003
	Previously Reported	As Restated
Cash and cash equivalents	$ 37,196	$ 43,372
Unrestricted cash from counterparties	46,496	-
Derivative assets - current (1)	301,194	249,117
Accounts payable	768,783	728,463
Derivative liabilities - current (1)	164,689	112,612

(1)

The 2003 derivative assets and derivative liabilities balances have been reclassified to conform to the current year's presentation. See reclassification below.

Consolidated Statement of Cash Flows	For the Year Ended December 31, 2003
	Previously Reported	As Restated
Income before preferred dividends of subsidiary	$126,711	$126,711
Adjustments to reconcile net cash flows provided by operating activities:
Unrestricted cash from counterparties	(29,606)	-
Other current assets	(24,863)	8,285
Accounts payable	(7,436)	(30,866)
Other current liabilities	100,039	90,928
Other operating activities	408,727	398,356
Net cash flows provided by operating activities	573,572	593,414
Net decrease in cash and cash equivalents	(13,137)	(6,961)
Cash and cash equivalents – end of year	$ 37,196	$ 43,372

Additionally, certain reclassifications of prior years’ data have been made to conform with the current year’s presentation. These reclassifications are summarized in the following tables (in thousands):

	At December 31, 2003
	Previously Reported	As Reclassified
Derivative assets - current (1)	$ 249,117	$116,305
Derivative assets - long-term	-	132,812
	249,117	249,117

Derivative liabilities - current (1)	112,612	51,117
Derivative liabilities - long-term	-	61,495
	112,612	112,612

Accumulated deferred income taxes	1,287,354	1,277,309
Accrued taxes	51,598	50,881
Other current liabilities (2)	203,080	213,842
	$1,542,032	$1,542,032

(1)

The 2003 derivative assets and derivative liabilities balances have been restated from amounts previously reported. For information regarding these restatements, see Note 16, "Restatement of Previously Issued Financial Statements," to the consolidated financial statements.

(2)

Other current liabilities as previously reported excludes $46.5 million of counterparty deposits, which are now separately disclosed.

Reclassifications to income statement amounts are as follows:

	For Year Ended December 31, 2003
	Previously Reported	As Reclassified
Fuel, purchased and net interchange power	$3,730,416	$3,735,154
Other	900,437	953,026
Maintenance	232,030	174,703
Amortization	182,675	191,805
Income tax expense	59,862	50,732

	For Year Ended December 31, 2002
	Previously Reported	As Reclassified
Fuel, purchased and net interchange power	$3,046,781	$3,048,813
Other	752,482	815,212
Maintenance	263,487	198,725
Amortization	312,955	320,409
Income tax expense	82,304	74,850

Consolidated Statements Of Quarterly Financial Data (Unaudited)

	Quarter Ended (a)
(Thousands of Dollars, except per share information)	March 31,	June 30,	September 30,	December 31,
2004
Operating Revenues	$1,838,287	$1,524,666	$1,667,985	$1,655,761
Operating Income	172,788	96,201	35,558	108,405
Net Income/(Loss)	67,442	23,992	(7,908)	33,062
Basic and Fully Diluted Earnings/(Loss) Per Common Share	0.53	0.19	(0.06)	0.26

2003
Operating Revenues	$1,584,183	$1,330,038	$1,640,117	$1,514,818
Operating Income	160,918	103,703	127,315	32,300
Income/(loss) Before Cumulative Effect of Accounting Change	60,204	26,869	43,979	(9,900)
Cumulative Effect of Accounting Change, Net of Tax Benefit	-	-	(4,741)	-
Net Income/(Loss)	60,204	26,869	39,238	(9,900)
Basic and Fully Diluted Earnings per Common Share:
Income/(loss) Before Cumulative Effect of Accounting Change	$0.47	$0.21	$0.35	$(0.08)
Cumulative Effect of Accounting Change, Net of Tax Benefit	-	-	(0.04)	-
Net Income/(Loss)	$0.47	$0.21	$0.31	$(0.08)

(a)

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

Selected Consolidated Financial Data (Unaudited)

(Thousands of Dollars, except percentages and share information)	2004	2003	2002	2001	2000
Balance Sheet Data:
Property, Plant and Equipment, Net	$ 5,864,161	$ 5,429,916	$ 5,049,369	$ 4,472,977	$ 3,547,215
Total Assets (a) (b)	11,655,834	11,216,487	10,764,880	10,331,923	10,217,149
Total Capitalization (c)	5,293,644	4,926,587	4,670,771	4,576,858	4,739,417
Obligations Under Capital Leases (c)	14,806	15,938	16,803	17,539	159,879
Income Data:
Operating Revenues	$6,686,699	$ 6,069,156	$ 5,237,000	$ 5,760,949	$ 5,876,620
Income Before Cumulative Effect of Accounting Changes and Extraordinary Loss, Net of Tax Benefits	116,588	121,152	152,109	265,942	205,295
Cumulative Effect of Accounting Changes, Net of Tax Benefits	-	(4,741)	-	(22,432)	-
Extraordinary Loss, Net of Tax Benefit	-	-	-	-	(233,881)
Net Income/(Loss)	$ 116,588	$ 116,411	$ 152,109	$ 243,510	$ (28,586)
Common Share Data:
Basic and Fully Diluted Earnings Per Common Share:
Income Before Cumulative Effect of Accounting Changes and Extraordinary Loss, Net of Tax Benefits	$0.91	$0.95	$1.18	$1.97	$1.45
Cumulative Effect of Accounting Changes, Net of Tax Benefits	-	(0.04)	-	(0.17)	-
Extraordinary Loss, Net of Tax Benefit	-	-	-	-	(1.65)
Net Income/(Loss)	$0.91	$0.91	$1.18	$1.80	$(0.20)
Basic Common Shares Outstanding (Average)	128,245,860	127,114,743	129,150,549	135,632,126	141,549,860
Fully Diluted Common Shares Outstanding (Average)	128,396,076	127,240,724	129,341,360	135,917,423	141,967,216
Dividends Per Share	$ 0.63	$ 0.58	$ 0.53	$ 0.45	$ 0.40
Market Price - Closing (high) (d)	$20.10	$20.17	$20.57	$23.75	$24.25
Market Price - Closing (low) (d)	$17.30	$13.38	$13.20	$16.80	$18.25
Market Price - Closing (end of year) (d)	$18.85	$20.17	$15.17	$17.63	$24.25
Book Value Per Share (end of year)	$17.80	$17.73	$17.33	$16.27	$15.43
Tangible Book Value Per Share (end of year)	$15.17	$15.05	$14.62	$13.71	$13.09
Rate of Return Earned on Average Common Equity (%)	5.1	5.2	7.0	11.2	(1.3)
Market-to-Book Ratio (end of year)	1.1	1.1	0.9	1.1	1.6
Capitalization:
Common Shareholders’ Equity	44%	46%	47%	46%	47%
Preferred Stock (c) (e)	2	2	3	3	4
Long-Term Debt (c)	54	52	50	51	49
	100%	100%	100%	100%	100%

(a)

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

(b)

Includes effects of restatements described in Note 16.

(c)

Includes portions due within one year.

(d)

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

(e)

Excludes $100 million of Monthly Income Preferred Securities.

Consolidated Sales Statistics (Unaudited)

	2004	2003	2002	2001	2000
Revenues: (Thousands)
Utility Group:
Residential	$1,707,434	$1,669,199	$1,512,397	$1,490,487	$1,469,439
Commercial	1,429,608	1,411,881	1,298,939	1,310,701	1,265,219
Industrial	513,999	514,076	485,591	544,806	560,821
Other Utilities	344,254	405,120	567,608	854,002	1,343,595
Streetlighting and Railroads	41,976	44,977	43,679	43,889	45,998
Miscellaneous and eliminations	143,631	(61,364)	(84,513)	52,794	55,860
Total Electric	4,180,902	3,983,889	3,823,701	4,296,679	4,740,932
Total Gas	407,812	361,450	281,206	378,033	251,233
Total - Utility Group	$4,588,714	$4,345,339	$4,104,907	$4,674,712	$4,992,165
NU Enterprises:
Retail	$ 857,355	$ 660,145	$ 508,734	$ 209,838	$ 132,027
Wholesale (a)	1,722,603	1,684,448	1,108,370	1,675,647	1,654,487
Generation	196,191	185,493	170,143	184,878	184,106
Services	323,433	269,045	220,638	213,996	126,978
Miscellaneous and eliminations	(244,419)	(224,340)	(207,062)	(209,435)	(207,895)
Total - NU Enterprises	$2,855,163	$2,574,791	$1,800,823	$2,074,924	$1,889,703
Other miscellaneous and eliminations	(757,178)	(850,974)	(668,730)	(988,687)	(1,005,248)
Total	$6,686,699	$6,069,156	$5,237,000	$5,760,949	$5,876,620
Utility Group Sales: (kWh - Millions)
Residential	14,866	14,824	13,923	13,322	12,940
Commercial	14,710	14,471	14,103	13,751	13,023
Industrial	6,274	6,223	6,265	6,790	7,130
Other Utilities	23,778	18,791	82,538	48,336	42,234
Streetlighting and Railroads	348	348	344	332	333
Total	59,976	54,657	117,173	82,531	75,660
Utility Group Customers: (Average)
Residential	1,659,419	1,631,582	1,614,239	1,610,154	1,576,068
Commercial	194,233	186,792	183,577	171,218	166,114
Industrial	7,752	7,644	7,763	7,730	7,701
Other	3,930	3,858	3,949	3,969	3,917
Total Electric	1,865,334	1,829,876	1,809,528	1,793,071	1,753,800
Gas	194,212	192,816	190,855	190,998	185,328
Total	2,059,546	2,022,692	2,000,383	1,984,069	1,939,128
Utility Group - Average Annual Use Per Residential Customer (kWh)	8,960	9,087	8,611	8,251	8,233
Utility Group- Average Annual Bill Per Residential Customer	$1,028.97	$1,024.20	$ 934.90	$ 923.70	$ 934.94
Utility Group Average Revenue Per kWh:
Residential	11.48¢	11.27¢	10.86¢	11.20¢	11.36¢
Commercial	9.70	9.74	9.18	9.48	9.65
Industrial	8.19	8.26	7.75	8.10	7.95

(a)

Operating income amounts for 2004 through 2002 reflect the application of EITF Issue No. 03-11. Operating revenue amounts prior to 2002 have not been reclassified.

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The Connecticut Light and Power Company (CNLTP) 10-K2004 FY Annual report

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