CL&P 2007 Annual Report

Exhibit 13.1

2007 Annual Report
The Connecticut Light and Power Company

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

The following discussion and analysis should be read in conjunction with our consolidated financial statements and the related notes

included in this exhibit to our Form 10-K. References in this exhibit to "CL&P" or "the company" are to The Connecticut Light and Power Company, and the terms "we," "us" and "our" refer to CL&P.

The discussion below references our earnings, which at times excludes a reduction in 2006 income tax expense pursuant to a Private Letter Ruling (PLR) issued by the Internal Revenue Service (IRS). We use this measure not recognized under accounting principles generally accepted in the United States of America (GAAP) to more fully explain and compare the 2007 and 2006 results without the impact of this non-recurring item. This measure should not be considered as an alternative to our reported net income determined in accordance with GAAP as an indicator of our operating performance.

Financial Condition and Business Analysis

Executive Summary

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

Results:

In 2007, we earned $133.6 million compared to $200 million in 2006 and $94.8 million in 2005. These earnings are stated before approximately $5.6 million of preferred dividends in each year. Included in earnings were transmission segment earnings of $68.2 million, $48.1 million and $30.7 million in 2007, 2006 and 2005, respectively, and distribution segment earnings of $65.4 million, $151.9 million and $64.1 million in 2007, 2006 and 2005, respectively. Results for 2006 included a reduction in income tax expense for the distribution segment of $74 million pursuant to a PLR received from the IRS.

We have currently completed the majority of each of our three major transmission projects presently under construction in southwest Connecticut. Two of those projects are expected to be completed in 2008 and the third in 2009.

Legislative and Regulatory Items:

On January 28, 2008, the Connecticut Department of Public Utility Control (DPUC) approved $77.8 million, or 11.7 percent, and $20.1 million, or 2.6 percent, in annualized increases over our current distribution rates, effective on February 1, 2008 and 2009, respectively, which also represents a 0.9 percent increase on a total rates basis over December 2007 rates and a 0.4 percent increase on a total rates basis over February 2008 rates, respectively. The rate decision included an authorized regulatory return on equity (Regulatory ROE) of 9.4 percent, which was significantly lower than CL&P’s requested amount and the approval of substantially all of our requested distribution segment capital program of $294 million for 2008 and $288 million for 2009. Due to the disallowance of certain operating expenses in rates, we project our Regulatory ROE for 2008 to be lower than the authorized amount.

On June 4, 2007, Connecticut Governor Rell signed into law "An Act Concerning Electricity and Energy Efficiency" (Energy Efficiency Act). Among other provisions, the Energy Efficiency Act requires electric distribution companies to file integrated resource plans for DPUC approval, provides incentives for customers to reduce consumption, particularly during peak load periods, and requires CL&P and The United Illuminating Company (UI) to file proposals with the DPUC to build cost-of-service peaking generation facilities.

Liquidity:

Our liquidity position in 2007 benefited from a capital contribution of $570.7 million from our parent company and the proceeds we received from the issuance of $500 million of long-term debt in 2007.

Our cash capital expenditures totaled $826.2 million in 2007, compared with $567.2 million in 2006. The increase was primarily the result of higher transmission segment capital expenditures.

We project a total of approximately $3.5 billion of capital expenditures from 2008 through 2012, including $872 million in 2008, of which $538 million is projected to be spent on transmission. Over the five-year period, approximately $2 billion is projected to be spent on transmission and approximately $1.5 billion on distribution.

We had consolidated operating cash flows in 2007 of $199.7 million, compared with $251.4 million in 2006. This decrease was primarily due to a $257 million increase in income taxes paid in 2007 as compared to 2006, which was a result of the 2006 sale of NU’s competitive generation business, as discussed further below under "Liquidity," partially offset by an expected reduction in regulatory refunds paid to our customers during 2007 as compared to 2006. This decrease was also offset by lower payments to Connecticut Yankee Atomic Power Company (CYAPC), Maine Yankee Atomic Power Company (MYAPC) and Yankee Atomic Electric Company (YAEC) (the Yankee Companies) for nuclear decommissioning and closure costs in 2007 as compared to 2006.

Overview

We are a wholly owned subsidiary of Northeast Utilities (NU). NU’s other regulated electric subsidiaries include Public Service Company of New Hampshire and Western Massachusetts Electric Company.

In 2007, we earned $133.6 million, compared to $200 million in 2006 and $94.8 million in 2005. These results include transmission segment earnings of $68.2 million, $48.1 million, and $30.7 million in 2007, 2006 and 2005, respectively, and distribution earnings of $65.4 million, $151.9 million and $64.1 million in 2007, 2006 and 2005, respectively. These earnings are stated before approximately $5.6 million of preferred dividends in each year, including $4 million for distribution and $1.6 million for transmission in 2007, $4.3 million for distribution and approximately $1.3 million for transmission in 2006, and $4.2 million for distribution and $1.4 million for transmission in 2005. Results for 2006 included a reduction in income tax expense of $74 million pursuant to a PLR received from the IRS. Results for 2007 included a discretionary pre-tax donation to the NU Foundation, Inc. of $0.6 million.

The increase in transmission segment earnings in 2007 reflects a reduction in 2006 fourth quarter earnings as a result of the October 31, 2006 Federal Energy Regulatory Commission (FERC) return on equity (ROE) decision and a higher FERC approved ROE for 2007. Additionally, for both 2007 and 2006, the earnings increases reflect a higher level of investment in our transmission infrastructure, where we have invested approximately $1 billion since the beginning of 2005. This investment has been made primarily to upgrade the transmission infrastructure of southwest Connecticut. At December 31, 2007, our transmission rate base was approximately $1.2 billion. Under our transmission tariffs, our transmission segment earnings generally track with the level of rate base.

Our 2007 distribution segment earnings, which do not include preferred dividends, were $86.5 million lower than in 2006 primarily because of the $74 million reduction in income tax expense pursuant to the PLR received from the IRS in 2006 related to the treatment of excess deferred income taxes (EDIT) and unamortized tax credits in connection with the sale of our former generating plants. Excluding the impact of the PLR on 2006 earnings, our 2007 distribution segment earnings were $12.5 million lower than in 2006. This decrease in earnings was primarily due to the $7.7 million after-tax benefit in 2006 related to the sale to a third party of competitive generation assets that we had previously sold to another subsidiary of NU; the absence in 2007 of a fixed procurement fee of approximately $6.6 million (after-tax) that expired at the end of 2006; higher operations and maintenance expense; higher interest expense; and higher income tax expense, partially offset by a $7 million distribution rate increase that took effect on January 1, 2007 and a 1.7 percent increase in sales. Our distribution segment Regulatory ROE was 7.9 percent for 2007 and 7.5 percent for 2006. We expect our distribution segment Regulatory ROE will be in the 8 percent to 8.5 percent range in the first full year of new rates beginning February 1, 2008, as a result of the DPUC's final decision in our distribution rate proceeding. Due to the February 2008 implementation of new rates, we expect a distribution segment Regulatory ROE of approximately 8 percent in calendar year 2008.

For our distribution segment, a summary of changes in our retail electric kilowatt-hour (KWH) sales for 2007 as compared to 2006 on an actual and weather normalized basis (using a 30-year average) is as follows:


	Percentage Increase/ (Decrease)	Weather Normalized Percentage Increase/ (Decrease)
Residential	2.8 %	0.4 %
Commercial	1.3 %	0.8 %
Industrial	(1.3)%	(1.5)%
Other	6.9 %	6.9 %
Total	1.7 %	0.4 %

A summary of our retail electric sales in gigawatt-hours for 2007 and 2006 is as follows:


	2007	2006	Percentage Increase/ (Decrease)
Residential	10,336	10,053	2.8 %
Commercial	10,128	9,995	1.3 %
Industrial	3,264	3,306	(1.3)%
Other	304	284	6.9 %
Total	24,032	23,638	1.7 %

Our electric sales per customer, adjusted for weather impacts, have been negatively affected by retail rate increases driven by the energy component of customer bills that began in early 2006. Although the longer-term trend in customer usage in our service territory when energy prices were stable had reflected a generally increasing use per customer, customers have responded to higher energy prices in recent years by using less electricity. Even though generation costs stabilized in 2007, use per customer on a weather normalized basis did not change significantly from 2006 levels, reflecting continued conservation efforts. We cannot determine at this time whether these trends will continue or the effect they may have on our distribution segment earnings.

Liquidity

During 2007, our liquidity position benefited from a capital contribution of $570.7 million from NU parent and the proceeds we received from the issuance of $500 million of long-term debt. At December 31, 2007, we had $20 million sold under our $100 million facility for the sale of accounts receivable.

We had consolidated operating cash flows in 2007 of $199.7 million, compared with $251.4 million in 2006 and $297.3 million in 2005. This decrease was primarily due to a $257 million increase in income taxes paid in 2007 as compared to 2006, which was a result of the 2006 sale of NU's competitive generation business. We accrued the majority of our portion of this tax obligation in 2000 upon the sale of these generation assets to another NU subsidiary, but due to the intercompany nature of the sales, the federal and state income tax payments were deferred at that time. It was not until NU ultimately sold these generation assets to an unaffiliated third party in November of 2006 that we were required to pay this deferred tax obligation. The increase in income taxes paid was partially offset by an expected reduction in regulatory refunds related to Competitive Transition Assessment (CTA) made to our customers during 2007 as compared to 2006. The change in CTA refunds and other regulatory collections or refunds amounted to approximately $85 million in cash flow improvements in 2007 compared to 2006. In addition to lower regulatory refunds paid, we made lower payments to the Yankee Companies for nuclear decommissioning and closure costs in 2007 as compared to 2006, primarily as a result of the extension of the collection period for decommissioning and closure costs at CYAPC, and had a positive change in working capital requirements.

In 2008, we project consolidated operating cash flows of approximately $380 million, rising to approximately $550 million in 2012 due to expected returns from our capital growth program. These projections assume that we receive timely recovery of our capital investments and purchased power costs through appropriate rates.

We issued $250 million in 30-year first mortgage bonds and $250 million in 10-year first mortgage bonds in 2007. The coupon rates on these bonds range from 5.375 percent to 6.375 percent. Because of interest rate swaps we entered into earlier in the year to offset the impact of a potential rise in interest rates, we paid $10.3 million to counterparties at the closing of these transactions.

In 2008, we expect to issue approximately $300 million of long-term debt to finance our capital program.

Our first mortgage bonds are rated A3, BBB+, and A- with a stable outlook by Moody’s Investors Service, Standard & Poor’s and Fitch Ratings, respectively. To ensure the consistency of these ratings, which aid in the achievement of competitive market rates for our debt issuances, we seek to maintain certain credit metrics satisfactory to the rating agencies, which include a target capitalization structure of approximately 55 percent debt and 45 percent equity. The three agencies each may include in the debt component of capitalization additional factors, such as the net present value of remaining operating leases and postretirement benefit obligations. Before the application of such adjustments, our ratio of consolidated total debt to total capitalization was approximately 53.2 percent as of December 31, 2007. We seek to maintain our target structure over the long term through a proper balance of capital infusions from NU parent and new debt issuances or borrowings.

In 2007 and 2006, NU contributed equity to us of $570.7 million and $60.8 million, respectively. In general, we pay approximately 60 percent of our cash earnings to NU in the form of common dividends. In 2007, we paid common dividends to NU of $79.2 million and $63.7 million, respectively.

The Federal Power Act limits the payment of dividends to our retained earnings balance. In addition, certain state statutes may impose additional limitations on us. We also have a revolving credit agreement that imposes a leverage restriction tied to our ratio of consolidated total debt to total capitalization.

Along with other NU subsidiaries, we are party to a $400 million credit facility which expires on November 6, 2010. We can borrow up to $200 million on a short-term basis, or subject to regulatory approvals, on a long-term basis. At December 31, 2007, we had no borrowings outstanding under this facility.

In addition to our revolving credit facility, we have an arrangement with a financial institution under which we can sell up to $100 million of our accounts receivable and unbilled revenues. There was $20 million sold under the facility at December 31, 2007. For more information regarding the sale of receivables, see Note 1K, "Summary of Significant Accounting Policies - Sale of Customer Receivables," to the consolidated financial statements.

Cash capital expenditures included on the accompanying consolidated statements of cash flows and described in the liquidity section of this management's discussion and analysis do not include amounts incurred but not paid, cost of removal, the allowance for funds used during construction (AFUDC) related to equity funds, and the capitalized portion of pension expense or income. Our cash capital expenditures totaled $826.2 million in 2007, compared with $567.2 million in 2006 and $444.4 million in 2005. The increase in our cash capital expenditures was primarily the result of higher transmission capital expenditures.

We project 2008 capital expenditures of approximately $872 million, compared to projected operating cash flows of approximately $380 million. As a result, we expect to issue the $300 million in long-term debt mentioned above and borrow on our credit facilities in 2008. We expect to fund the majority of our expected capital expenditures through 2012 with internally generated cash flows. Therefore, we expect to issue debt on a regular basis.

Impact of Credit Markets: As previously discussed, we plan to issue $300 million of long-term debt in 2008 and have entered into forward interest rate swaps to hedge exposure to market rates for these planned issuances. Due to the overall uncertainties in the market, however, the credit spreads on these issuances may be higher than we have experienced in the past. We believe that the credit markets will continue to be supportive of our debt issuances and that, despite volatility in treasury rates and credit spreads, we will be able to issue this debt at competitive rates.

Certain bond insurers have experienced increasing ratings pressure and are on negative watch by the credit rating agencies. Credit ratings of our Pollution Control Revenue Bonds (PCRBs) are enhanced with bond insurance. We do not expect the financial condition of the bond insurers to have a material impact on us, although concerns regarding the bond insurers' credit strength could increase interest expense associated with $62 million of PCRBs that we may remarket in 2008. These PCRBs have a fixed rate through October 1, 2008. We will consider fixing the interest rate on these bonds at that time.

Business Development and Capital Expenditures

Our consolidated capital expenditures including amounts incurred but not paid, cost of removal, AFUDC, and the capitalized portion of pension expense or income, totaled $943.9 million in 2007, compared with $625.9 million in 2006 and $469.9 million in 2005.

We project a total of $3.5 billion in capital expenditures from 2008 through 2012, which also includes amounts incurred but not paid, cost of removal, AFUDC, and the capitalized portion of pension expense or income (all of which are predominately non-cash factors in determining rate base). A summary of these estimated capital expenditures for our transmission segment and distribution segment for 2008 through 2012 is as follows (millions of dollars):


	Year
	2008		2009		2010		2011		2012		Totals

Transmission	$	538	$	311	$	155	$	420	$	530	$	1,954
Distribution		334		291		289		298		297		1,509
Total	$	872	$	602	$	444	$	718	$	827	$	3,463

Our distribution capital expenditures will primarily address our aging distribution infrastructure, and increase reliability and system capacity. Costs of these capital expenditures have increased from prior years due to higher costs for transformers, cables, conductors, and other materials.

Actual levels of capital expenditures could vary from the estimated amounts for the periods above. Based on these estimated capital expenditures, we project our transmission and distribution rate base at December 31^st of each year will be as follows (millions of dollars):


	Year
	2008		2009		2010		2011		2012

Transmission	$	1,763	$	2,168	$	2,199	$	2,515	$	2,828
Distribution		2,130		2,296		2,450		2,584		2,705
Total	$	3,893	$	4,464	$	4,649	$	5,099	$	5,533

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

Transmission Segment: Our transmission rate base totaled approximately $1.2 billion at December 31, 2007, including approximately $290 million of incurred construction costs, or construction work in progress (CWIP), compared with approximately $800 million at December 31, 2006, including approximately $108 million of CWIP. In addition, the transmission segment recorded $345 million and $142 million of CWIP at December 31, 2007 and 2006, respectively, that were not in rate base. The projected transmission rate base amounts reflected above include CWIP for 50 percent of the southwest Connecticut projects (Middletown to Norwalk, Connecticut; Norwalk to Stamford, Connecticut; and Norwalk, Connecticut to Northport-Long Island, New York) and, assuming FERC will allow related CWIP in rate base, 100 percent of our portion of the New England East-West 345 kilovolt (KV) and 115 KV Overhead project referred to below. The CWIP amounts included in rate base for these projects are $233 million, $33 million, $96 million, $352 million, and $372 million, respectively, for the 2008 to 2012 periods.

Transmission segment capital expenditures were $660.6 million, $415.6 million, and $215.3 million for the years ended December 31, 2007, 2006 and 2005, respectively.

The increase in transmission segment capital expenditures in 2007 as compared with 2006 and 2005 primarily relates to a significant enhancement of our transmission system in southwest Connecticut. We completed one major transmission project, the 21-mile 115 KV/345 KV transmission project between Bethel, Connecticut and Norwalk, Connecticut, in 2006 and have three major projects currently under construction in southwest Connecticut, including:

A 69-mile, 345 KV/115 KV transmission project from Middletown to Norwalk, Connecticut. Our portion of this project is estimated to cost approximately $1.05 billion. At December 31, 2007, our portion of this project was approximately 62 percent complete and at the end of February of 2008, was approximately 70 percent complete. As of December 31, 2007, we had capitalized $593 million associated with this project. Although the project is scheduled to be completed at the end of 2009, construction of the project is currently ahead of schedule, and we have reviewed the remaining work to determine whether it can be completed at an earlier date. As a result of this review, we now expect to complete this project in mid-2009. This early completion date would not have a significant impact on our earnings guidance.

A two-cable, nine-mile, 115 KV underground transmission project between Norwalk and Stamford, Connecticut (Glenbrook Cables), construction of which began in October of 2006. This project is estimated to cost approximately $223 million. This project is scheduled to be completed by the end of 2008. At December 31, 2007, this project was approximately 69 percent complete, and at the end of February of 2008, was approximately 74 percent complete. As of December 31, 2007, we had capitalized $133 million associated with this project.

The replacement of the 138 KV 11-mile undersea electric transmission cable between Norwalk, Connecticut and Northport-Long Island, New York (Long Island Replacement Cable). We and the Long Island Power Authority (LIPA) each own approximately 50 percent of the line. Our portion of the project is estimated to cost $72 million. After the final regulatory permits were received, marine construction activities commenced in October of 2007, and the project is expected to be placed in service in the second half of 2008. The pre-existing cables were decommissioned in September of 2007, and approximately 94 percent of the cables was removed as of December 31, 2007, including all portions located in Connecticut. Installation of the new cable began in early February of 2008. At December 31, 2007, the project was approximately 63 percent complete, and at the end of February of 2008, was approximately 72 percent complete. As of December 31, 2007, we had capitalized $45 million associated with this project, including the cost of the new cable, which was delivered in the fourth quarter of 2007.

In addition to our current transmission construction in southwest Connecticut, NU continues to work with ISO-NE to refine the design criteria of its next series of major transmission projects, including the New England East-West 345 KV and 115 KV Overhead project (NEEWS Overhead project). The NEEWS Overhead project includes three 345 KV transmission upgrades that will collectively address the region's transmission needs and better connect the major east-west transmission interfaces in Southern New England: 1) the Greater Springfield 345 KV Reliability Project, 2) the Central Connecticut Reliability Project, and 3) the Interstate Reliability Project. A fourth upgrade, National Grid's Rhode Island Reliability Project, is also included in the NEEWS Overhead project. In early 2007, NU entered into a formal agreement with National Grid to plan and permit these projects and expects the ISO-NE technical review process with respect to the NEEWS Overhead project to conclude by mid- to late- 2008. NU will make the filing of the first project applications with the various state siting authorities shortly after receiving the technical approvals from ISO-NE. NU continues to work with ISO-NE to ensure that the design of these projects balances needs and reliability, operational flexibility, and cost. At this time, NU expects the siting process for the NEEWS Overhead project to be completed by 2010 and to complete construction in 2013. NU has not yet updated its detailed estimate of the total cost for the NEEWS Overhead project, and the timing of expenditures is highly dependent upon receipt of technical and siting approvals.

Assuming that virtually all of the 345 KV portions of the NEEWS Overhead project are constructed overhead and on existing rights of way, NU are maintaining its estimate of its share of the cost of the NEEWS Overhead project at approximately $1.05 billion, of which a significant portion will be incurred by us. However, as NU continues to review the designs of the NEEWS Overhead project with ISO-NE over the coming months, these figures are expected to change. NU anticipates having additional information on the scope and costs of these projects by mid-2008.

In October of 2006, the Bethel, Connecticut to Norwalk 345 KV transmission project was completed and energized and it has operated reliably since then. In addition to improving reliability, we believe the completion of that project is the primary reason for the decrease in Connecticut congestion costs, which were lower by nearly $150 million in the project's first full year of operation.

Distribution: Our distribution segment capital expenditures were $283.3 million, $210.3 million and $254.6 million in 2007, 2006 and 2005, respectively.

Strategic Initiatives: NU is evaluating certain development projects for CL&P and other NU subsidiaries that would benefit our customers, such as new regulated generating facilities, investments in advanced metering infrastructure (AMI) systems to provide time-of-use rates to our customers, and transmission projects to better interconnect new renewable generation in northern New England and Canada with southern New England. The estimated capital expenditures and projected rate base amounts discussed above do not include expenditures related to these initiatives.

Transmission Rate Matters and FERC Regulatory Issues

Most New England utilities, including our company, generation owners and marketers are parties to a series of agreements that provide for coordinated planning and operation of the region's generation and transmission facilities and the market rules by which these parties participate in the wholesale markets and acquire transmission services. Under these arrangements, ISO-NE, a non-profit corporation whose board of directors and staff are independent from all market participants, has served as the Regional Transmission Operator

(RTO) for New England since February 1, 2005. ISO-NE works to ensure the reliability of the New England transmission system, administers the independent system operator tariff (ISO Tariff), subject to FERC approval, oversees the efficient and competitive functioning of the regional wholesale power market and determines which portion of the costs of our major transmission facilities are regionalized throughout New England.

Transmission - Wholesale Rates: Wholesale transmission revenues are based on formula rates that are approved by the FERC. Most of NU’s wholesale transmission revenues, including ours, are collected under the ISO-NE FERC Electric Tariff No. 3, Transmission, Markets and Services Tariff (Tariff No. 3). Tariff No. 3 includes Regional Network Service (RNS) and Local Network Service (LNS) rate schedules to recover transmission and other services. The RNS rate, administered by ISO-NE and billed to all New England transmission users, including our transmission business, is reset on June 1^st of each year and recovers the revenue requirements associated with transmission facilities that benefit the New England region. The LNS rate, which NU administers, is reset on January 1^st and June 1^st of each year and recovers the revenue requirements for local transmission facilities and other transmission costs not recovered under the RNS rate, including 50 percent of the CWIP that is included in rate base on the remaining three southwest Connecticut projects (Middletown-Norwalk, Glenbrook Cables and Long Island Replacement Cable). The LNS rate calculation recovers total transmission revenue requirements net of revenues received from other sources (i.e., RNS, rentals, etc.), thereby ensuring that NU recovers all regional and local revenue requirements as prescribed in Tariff No. 3. Both the RNS and LNS rates provide for annual true-ups to actual costs. The financial impacts of differences between actual and projected costs are deferred for future recovery from or refund to retail customers. At December 31, 2007, the LNS rates for our transmission segment were in an underrecovery position of approximately $18 million, which will be recovered from LNS customers in mid-2008. We believe that these rates will provide us with timely recovery of transmission costs, including costs of our major transmission projects.

FERC ROE Decision: As a result of an order issued by the FERC on October 31, 2006 relating to incentives on new transmission facilities in New England (FERC ROE decision), we recorded an estimated regulatory liability for refunds of $17.9 million as of December 31, 2006. In 2007, we completed the customer refunds that were calculated in accordance with the compliance filing required by the FERC ROE decision and refunded approximately $17 million to regional, local and localized transmission customers. The $0.9 million positive pre-tax difference ($0.5 million after-tax) between the estimated regulatory liability recorded and the actual amount refunded was recognized in earnings in 2007.

Pursuant to this FERC ROE decision, the New England transmission owners submitted a compliance filing that calculated the refund amounts for transmission customers for the February 1, 2005 to October 31, 2006 time period. Subsequently, on July 26, 2007, the FERC disagreed with the ROEs the transmission owners used in their refund calculations for the 15-month period between June 3, 2005 and September 3, 2006, rejected a portion of the compliance filing, and required another compliance filing within 30 days. On August 27, 2007, NU, on our behalf, submitted a revised compliance filing with the other New England transmission owners, which outlined the regional refund process to comply with the FERC’s July 26, 2007 order. In addition, the transmission owners filed a request for rehearing claiming that the FERC improperly set the floor for refunds based on the lower rates that the FERC approved in its October 31, 2006 order, rather than the last approved rates, for the period from June 3, 2005 to September 3, 2006. The FERC denied this request on January 17, 2008, and the transmission owners have until March 17, 2008 to appeal, if they so choose.

Our transmission segment refunded approximately $1.6 million of revenues and interest related to the July 26, 2007 order (approximately $1 million after-tax), which was recorded in 2007.

Legislative Matters

Environmental Legislation: The Regional Greenhouse Gas Initiative (RGGI) is a cooperative effort by certain northeastern states, including Connecticut, to develop a regional program for stabilizing and reducing Carbon Dioxide (CO₂) emissions from fossil fuel-fired electric generators. This initiative proposed to stabilize CO₂ emissions at current levels and requires a ten percent reduction by 2018 from the initial 2009 permitted levels. Each signatory state committed to propose for approval legislative and regulatory mechanisms to implement the program.

On December 28, 2007, the Connecticut Department of Environmental Protection (DEP) released draft RGGI regulations and conducted a public hearing on February 8, 2008. The DEP plans to have these rules finalized by May of 2008 and to participate in a proposed open regional auction of CO₂ allowances in June of 2008. The DEP has proposed an auction of 91 percent of allocated CO₂ allowances, with the remainder set aside for certain clean energy projects. The DEP has also proposed the first compliance period affecting facilities to begin on January 1, 2009. Although we currently do not have any facilities subject to the RGGI program, we expect the cost of purchased energy supply to increase due to RGGI requirements.

Many states and environmental groups have challenged certain of the federal laws and regulations relating to air emissions as not being sufficiently strict. As a result, it is possible that state and federal regulations could be developed that will impose more stringent limitations on emissions than are currently in effect.

Energy Efficiency Act: On June 4, 2007, Connecticut Governor Rell signed into law the Energy Efficiency Act. Among other provisions, the Act:

Required electric distribution companies to file an integrated resource plan with the Connecticut Energy Advisory Board (CEAB). We filed a joint plan with UI on January 2, 2008. The CEAB has 120 days to approve or modify it before forwarding the plan to the DPUC;

Provides incentives for customers to reduce consumption, particularly during peak load periods;

Requires electric distribution companies, including CL&P, to file proposals with the DPUC to build cost-of-service peaking generation facilities. We filed a qualification submission with the DPUC on February 1, 2008 and we expect to file a detailed proposal on or about March 3, 2008;

Requires the DPUC to allow us and other Connecticut electric distribution companies to buy generation assets that are for sale in Connecticut if the purchase is in the public interest;

Requires the DPUC to decouple electric distribution revenues from sales volumes in future rate cases in an effort to align the interests of customers and the utilities in pursuit of conservation and energy efficiency; and

Requires us and other Connecticut electric distribution companies to offer advanced metering to customers which will support time-based pricing.

Subsequent regulatory developments that resulted from the passage of the Energy Efficiency Act are described in "Regulatory Developments and Rate Matters," included in this Management's Discussion and Analysis.

In 2007, the DPUC approved $85 million for energy efficiency and renewable programs to restore, in effect, funding to previously authorized levels. The fund is allocated 80 percent to us and 20 percent to UI, and will be used to prepay securitization obligations previously incurred by Connecticut. This will enable us to increase our annual energy efficiency spending by approximately $20 million beginning in mid-2008. We anticipate that we will be allowed to earn incentives on these higher levels of spending.

Regulatory Developments and Rate Matters

Transmission Revenues - Retail Rates: A significant portion of the NU transmission segment revenue comes from ISO-NE charges to the distribution segments of CL&P and other NU companies, which recover these costs through rates charged to their retail customers. We have a retail transmission cost tracking mechanism as part of our rates. This tracking mechanism allows us to charge our retail customers for transmission charges on a timely basis.

Forward Capacity Market: On March 6, 2006, ISO-NE and a broad cross-section of critical stakeholders from around the region, including us, filed a comprehensive settlement agreement at the FERC proposing an auction-based forward capacity market (FCM) mechanism in place of the previously proposed locational installed capacity (LICAP) mechanism, an administratively determined electric generation capacity pricing mechanism. The settlement agreement provided for a fixed level of compensation to generators from December 1, 2006 through May 31, 2010 without regard to location in New England, and annual forward capacity auctions, beginning in 2008 for the 1-year period beginning on June 1, 2010, and annually thereafter. On June 16, 2006, the FERC approved the March of 2006 settlement agreement, and the payment of fixed compensation to generators began on December 1, 2006. The FERC denied rehearing of the decision on October 31, 2006. Several parties have challenged the FERC's approval of the settlement agreement, and that challenge is now pending in the Court of Appeals. We are currently recovering related costs from our customers.

The first forward capacity auction concluded in early February of 2008 for the capacity year of June of 2010 through May of 2011. The bidding reached the establishment minimum of $4.50 per kilowatt-month with 2,047 MW of excess remaining capacity, which means the effective capacity price will be $4.25 per kilowatt-month compared to the previously established price of $4.10 for the capacity year preceding June of 2010. These costs are recoverable in all jurisdictions through the currently established rate structures.

Distribution Rates: On January 1, 2007, we implemented a $7 million annualized increase in distribution rates, the fourth of four annual increases in distribution rates approved by the DPUC in December of 2003. On July 30, 2007, we filed an application with the DPUC to raise distribution rates by approximately $189 million (later revised to $182 million) effective on January 1, 2008, and approximately $21.9 million effective in January of 2009. In our application, we cited a weak actual Regulatory ROE, which has been significantly lower than our 9.85 percent authorized Regulatory ROE since the end of 2004, and requested an authorized Regulatory ROE of 11 percent. The application also cited the December 31, 2007 expiration of $30 million of refunds per year to customers for four years totaling $120 million from previous overrecoveries and the need to upgrade our aging distribution facilities. On January 28, 2008, the DPUC approved $77.8 million, or 11.7 percent, and $20.1 million, or 2.6 percent, in annualized increases over our current distribution rates, effective on February 1, 2008 and 2009, respectively, which also represent a 0.9 percent increase on a total rates basis over December of 2007 rates and a 0.4 percent increase on a total rates basis over February 2008 rates, respectively. These increases are based on an authorized Regulatory ROE of 9.4 percent. In addition, the DPUC approved substantially all of our requested distribution segment capital program of $294 million for 2008 and $288 million for 2009.

As required by the Energy Efficiency Act, our rate case application included a proposal to implement distribution revenue decoupling from the volume of electricity sales. We proposed using a revenue per customer tracking mechanism in our rate case filing. In lieu of this proposal, the DPUC authorized a rate design that includes greater fixed recovery of distribution revenue. As compared to previous tariffs, this authorization intends for us to recover proportionately greater revenue through the fixed customer and demand charges and proportionately lesser revenue through the per KWH charges. The DPUC intends for this rate design to leave our distribution revenue recovery less susceptible to changes in KWH sales and KWH usage per customer.

Time-of-Use Rates: On March 30, 2007, we filed a metering compliance plan with the DPUC that would meet the DPUC's objective of making time-of-use rates available to all of our customers. Our filing discussed the technology, implementation options and costs comparing an open AMI system deployed on a geographic basis to a fixed automated metering reading (AMR) network system deployed on a usage-based priority schedule. The plan provided for full deployment by 2010. On July 2, 2007, we filed a revised AMI plan consistent with the requirements of the Energy Efficiency Act, which provided for a less aggressive implementation schedule.

On December 19, 2007, the DPUC issued a final decision on our compliance plan that authorizes a pilot program involving 10,000 AMI meters and a rate design pilot to test new time-of-use and real-time rates to determine customer acceptance and load response to various pricing structures. We will file a plan to implement the pilot by March 15, 2008 and are required to submit a report on the technical capability of the meters, customer response to the pilot and other related results by December 1, 2009. The costs associated with the pilot are authorized to be recovered from customers, initially through our Federally Mandated Congestion Charges (FMCC) mechanism.

Standard Service and Last Resort Service Rates: Our residential and small commercial customers who do not choose competitive suppliers are served under Standard Service (SS) rates, and large commercial and industrial customers who do not choose competitive suppliers are served under Last Resort Service (LRS) rates. On January 1, 2007, our combined average SS and LRS rates increased approximately 10.4 percent and remained in effect until July 1, 2007. On July 1, 2007, our combined average SS and LRS rates decreased approximately 3.5 percent and remained in effect until January 1, 2008. On January 1, 2008, our combined average SS and LRS rates decreased approximately 1.1 percent. We are fully recovering the cost of our SS and LRS services on a timely basis.

FMCC Filings: On August 2, 2007, we filed with the DPUC our semi-annual reconciliation to document actual FMCC charges (including Energy Independence Act charges, as defined below), Generation Service Charge (GSC) revenue and expenses and Energy Adjustment Clause (EAC) charges for the period January 1, 2007 through June 30, 2007. For the first half of 2007, the filing identified overrecoveries totaling approximately $64 million related to these charges. On January 23, 2008, the DPUC issued a final decision covering this period that approved all costs as filed. On February 5, 2008, we filed with the DPUC our semi-annual FMCC, GSC and EAC reconciliation for the period July 1, 2007 through December 31, 2007, which also contained our revenue and cost information from the January 1, 2007 through June 30, 2007 period. This filing identified overrecoveries totaling approximately $105 million for the full year 2007. Of this total, approximately $88 million was included in our annual rate change effective January 1, 2008. Therefore, there is a net remaining overrecovery of approximately $17 million to be given to our customers in the future.

CTA and SBC Reconciliation: On March 30, 2007, we filed our 2006 CTA and System Benefits Charge (SBC) reconciliation, which compared CTA and SBC revenues to revenue requirements, with the DPUC. On December 27, 2007, the DPUC approved our request to collect SBC revenues at an annual level of $37.6 million, effective on January 1, 2008.

Energy Independence and Energy Efficiency Acts: In April of 2007, pursuant to Public Act 05-01, "An Act Concerning Energy Independence" (Energy Independence Act), we entered into a 15-year agreement beginning in 2010 to purchase energy, capacity and renewable energy credits from a biomass energy plant yet to be built. The agreement has been approved by the DPUC. Our annual payments under this agreement will depend on the price and quantity of energy purchased, and are currently estimated to be approximately $15 million beginning in 2010 escalating to $20 million in 2025. We have signed a sharing agreement with UI, which has been filed with and approved by the DPUC, under which we will share the costs and benefits of this contract and other contracts under this program, with 80 percent to us and 20 percent to UI. Our portion of the costs and benefits of this contract will be paid by or returned to our customers.

On January 30, 2008, the DPUC approved contracts with seven additional renewable energy projects including biomass, landfill gas and fuel cell projects generating a total of 109 megawatts (MW) of renewable energy. Our share of the future costs of such contracts will be paid by our customers. A third round of solicitations is expected to be conducted by the Connecticut Clean Energy Fund (CCEF) for an additional 26 MW of renewable energy generation to be selected by October 1, 2008.

Also pursuant to the Energy Independence Act, the DPUC conducted a request for proposal process and selected three generating projects to be built or modified that would be eligible to sign contracts for differences (CfDs) with us and UI for a total of approximately 782 MW of capacity. The process also selected one new demand response project for 5 MW. The CfDs obligate the utilities to pay the difference between a set capacity price and the value that the projects receive in the ISO-NE capacity markets. The contracts are for periods of up to 15 years and are subject to another similar sharing agreement between us and UI. These contracts have been approved by the DPUC and signed by us or UI, whichever is the primary obligor. Our portion of the costs and benefits of these contracts will be paid by or refunded to our customers. Our costs under these agreements will depend on the capacity prices that the projects receive in the ISO-NE capacity markets. For further information, see Note 3, "Derivative Instruments," to the consolidated financial statements.

The Energy Efficiency Act requires Connecticut electric distribution companies to negotiate in good faith to potentially enter into cost-of-service based contracts for the energy associated with the three above-mentioned generation projects that were awarded CfDs by the DPUC, for terms equivalent to the term lengths of the associated CfDs. These energy contracts must be approved by the DPUC if it finds that they will stabilize the cost of electricity for Connecticut ratepayers. Depending on its terms, a long-term contract to purchase energy from a project that is also under a CfD could result in us consolidating these projects into our financial statements. We would seek to recover from customers any costs that result from consolidation of a project. As of this date, only one of the three CfD project developers has requested that we enter into negotiations for a potential energy purchase agreement.

Customer Service Docket: On February 27, 2007, the DPUC issued a final decision in a docket examining the manner of operation and accuracy of our electric meters. While finding that the meters generally operated within industry standards, the DPUC imposed significant new testing, analytical and reporting requirements on the company. The DPUC also found that we failed to be responsive to customer complaints by refusing meter tests or not allowing customers to speak with supervisors. The decision acknowledges recent corrective actions we have taken but requires changes in numerous customer service practices of ours. The decision also places substantial new tracking and reporting obligations on the company. The decision does not fine us but holds that possibility open if we fail to meet benchmarks to be established in this docket.

Contingent Matters:

The item summarized below contains contingencies that may have an impact on our net income, financial position or cash flows. See Note 5A, "Commitments and Contingencies - Regulatory Developments and Rate Matters," to the consolidated financial statements for further information regarding these matters.

Procurement Fee Rate Proceedings: We submitted to the DPUC our proposed methodology to calculate the variable incentive portion of the procurement fee, which was effective through 2006, and requested approval of the pre-tax $5.8 million 2004 incentive fee. We have not recorded amounts related to the 2005 or 2006 procurement fee in earnings, although we estimate that if our methodology is upheld, we would record after-tax amounts of $3.3 million for 2006 and $3.6 million for 2005 in 2008.

We have recovered the $5.8 million pre-tax amount, which was recorded in 2005 earnings through the CTA reconciliation process. If the DPUC does not allow recovery of $5.8 million for procurement fees in its final decision, then we would record a loss and establish an obligation to refund our customers. Hearings were held on December 10, 2007 and January 3, 2008. The new schedule calls for a draft decision in this docket to be issued on March 7, 2008.

Deferred Contractual Obligations

We have significant decommissioning and plant closure cost obligations to the Yankee Companies, which have completed the physical decommissioning of all three of their facilities and are now engaged in the long-term storage of their spent fuel. The Yankee Companies collect decommissioning and closure costs through wholesale, FERC-approved rates charged under power purchase agreements with several New England utilities, including us. We recover these costs through DPUC-approved retail rates. We own 34.5 percent of CYAPC, 24.5 percent of YAEC, and 12 percent of MYAPC.

Our percentage share of the obligation to support the Yankee Companies under FERC-approved rate tariffs is the same as the ownership percentages above.

CYAPC: Under the terms of the settlement agreement between CYAPC, the DPUC, the Connecticut Office of Consumer Counsel, and Maine regulators, the parties agreed to a revised decommissioning estimate of $642.9 million (in 2006 dollars). Annual collections began in January of 2007, and were reduced from the $93 million originally requested for years 2007 through 2010 to lower levels ranging from $37 million in 2007 rising to $46 million in 2015. The reduction to annual collections was achieved by extending the collection period by 5 years through 2015 by reflecting the proceeds from a settlement agreement with Bechtel Power Corporation, by reducing collections in 2007, 2008 and 2009 by $5 million per year, and making other adjustments. We believe we will recover our share of this obligation from our customers.

YAEC: On July 31, 2006, the FERC approved a settlement agreement with the DPUC, the Massachusetts Attorney General and the Vermont Department of Public Service previously filed by YAEC. This settlement agreement did not materially affect the level of 2006 charges. Under the settlement agreement, YAEC agreed to reduce its November 2005 decommissioning cost increase from $85 million to $79 million. Other terms of the settlement agreement include extending the collection period for charges through December 2014, reconciling and adjusting future charges based on actual decontamination and decommissioning expenses. We believe that our $19.4 million share of the increase in decommissioning costs will ultimately be recovered from our customers.

MYAPC: MYAPC is collecting revenues from us and other owners that are adequate to recover the remaining cost of decommissioning its plant, and we expect to recover our respective share of such costs through future rates.

Spent Nuclear Fuel Litigation: In 1998, CYAPC, YAEC and MYAPC filed separate complaints against the United States Department of Energy (DOE) in the Court of Federal Claims seeking monetary damages resulting from the DOE's failure to begin accepting spent nuclear fuel for disposal by January 31, 1998 pursuant to the terms of the 1983 spent fuel and high level waste disposal contracts between the Yankee Companies and the DOE. In a ruling released on October 4, 2006, the Court of Federal Claims held that the DOE was liable for damages to CYAPC for $34.2 million through 2001, YAEC for $32.9 million through 2001 and MYAPC for $75.8 million through 2002. The Yankee Companies had claimed actual damages for the same periods as follows: CYAPC: $37.7 million; YAEC: $60.8 million; and MYAPC: $78.1 million. Most of the reduction in the claimed actual damages related to disallowed spent nuclear fuel pool operating expenses.

The Court of Federal Claims, following precedent set in another case, did not award the Yankee Companies future damages covering the period beyond the 2001/2002 damages award dates. In December of 2007, the Yankee Companies filed lawsuits against the DOE seeking recovery of actual damages incurred in the years following 2001/2002.

In December of 2006, the DOE appealed the ruling, and the Yankee Companies filed a cross-appeal. The refund to us of any damages that may be recovered from the DOE will be realized through the Yankee Companies' FERC-approved rate settlement agreements, subject to final determination of the FERC. The appeal is expected to be argued in 2008 with a decision from the Court of Appeals to follow.

Our aggregate share of these damages is $29 million. We cannot at this time determine the timing or amount of any ultimate recovery from the DOE, through the Yankee Companies, on this matter. However, we do believe that any net settlement proceeds we receive would be incorporated into FERC-approved recoveries, which would be passed on to our customers through reduced charges.

Off-Balance Sheet Arrangements

The CL&P Receivables Corporation (CRC) is a wholly-owned subsidiary of CL&P. CRC has an agreement with us to purchase our accounts receivable and unbilled revenues and has an arrangement with a highly-rated financial institution under which CRC can sell up to $100 million of an undivided interest in accounts receivable and unbilled revenues. At December 31, 2007, there were $20 million of these sales. At December 31, 2006, we had made no such sales.

CRC was established for the sole purpose of acquiring and selling our accounts receivable and unbilled revenues and is included in our consolidated financial statements. On July 3, 2007, we extended the bank commitment under the Receivables Purchase and Sale Agreement with CRC and the financial institution through June 30, 2008 and extended the facility termination date to June 21, 2012. Our continuing involvement with the receivables that are sold to CRC and the financial institution is limited to the servicing of those receivables.

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

While a part of our cash management facilities, this off-balance sheet arrangement is not significant to our liquidity. 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 us under this off-balance sheet arrangement.

Enterprise Risk Management

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

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with GAAP 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 our financial statements. 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 we believe are the most critical in nature. See Note 1, "Summary of Significant Accounting Policies," to our consolidated financial statements for other accounting policies, estimates and assumptions used in the preparation of our consolidated financial statements.

Income Taxes: Income tax expense is calculated in each reporting period in each of the jurisdictions in which we operate. This process involves estimating actual current tax expense or benefit as well as the income tax impact of temporary differences resulting from differing treatment of items, such as timing of the deduction and expenses for tax and book accounting purposes. These differences result in deferred tax assets and liabilities that are recorded on the consolidated balance sheets. Adjustments made to income tax estimates can significantly affect our consolidated financial statements. Actual income taxes could vary from estimated amounts due to the future impacts of various items, including changes in tax laws, our financial conditions in future periods and the final review of filed tax returns by taxing authorities. We must 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 is established. Significant judgment is required in determining income tax expense, deferred tax assets and liabilities and valuation allowances.

We account for deferred taxes under SFAS No. 109, "Accounting for Income Taxes." We have established a regulatory asset for temporary differences recorded as deferred tax liabilities that will be recovered in rates in the future. The regulatory asset amounted to $279.4 million and $266.6 million at December 31, 2007 and 2006, respectively. Regulatory agencies in certain jurisdictions in which we operate require the tax effect of specific temporary differences to be "flowed through" to our 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 our net income. Flow through treatment can result in effective income tax rates that are significantly different than expected income tax rates.

A reconciliation of expected tax expense at the statutory federal income tax rate to actual tax expense recorded is included in Note 1G, "Summary of Significant Accounting Policies - Income Taxes," to the consolidated financial statements.

Effective on January 1, 2007, we implemented Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 48, "Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109." FIN 48 applies to all income tax positions reflected on our balance sheets that have been included in previous tax returns or are expected to be included in future tax returns. FIN 48 addresses the methodology to be used prospectively in recognizing, measuring and classifying the amounts associated with tax positions that are deemed to be uncertain, including related interest and penalties. As a result of implementing FIN 48, we recognized a cumulative effect of a change in accounting principle of $24 million as a reduction to the January 1, 2007 balance of retained earnings.

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

Derivative Accounting: Certain contracts for the purchase or sale of energy or energy related products are derivatives.

The application of derivative accounting under SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended, is complex and requires our 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 our consolidated earnings.

The fair value of derivatives is based upon the contract terms and conditions and the underlying market price or fair value per unit. When quantities are not specified in the contract, the company determines whether it is a derivative using amounts referenced in default provisions and other relevant sections of the contract. The estimated quantities to be served are updated during the term of the contract, and such updates can have a material impact on mark-to-market amounts.

The judgment applied in the election of the normal purchases and sales exception (and resulting accrual accounting) includes the conclusion 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. We currently have elected normal on many of our derivative contracts. If facts and circumstances change and we can no longer support this conclusion, then the normal exception and accrual accounting is terminated and fair value accounting is applied.

In 2007, we entered into CfDs with owners of plants to be built or modified. The CfDs are derivatives that are required to be marked to market on the balance sheet. However, due to the significance of the non-observable capacity prices associated with modeling the fair values of these contracts, their initial fair values were not recorded in our financial statements pursuant to EITF Issue No. 02-3, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities." This guidance applies to initial fair values only, and not to subsequent changes in value. Subsequent changes in the values of these contracts were substantial, primarily due to reductions in the expected market prices of capacity. Accordingly, at December 31, 2007, we estimated and recorded on our balance sheet approximately $110 million of total negative changes in fair value of the derivative contracts since inception. The initial estimated negative fair values of these contracts of approximately $100 million will be recorded as part of the effect on derivatives of implementing FAS 157 in the first quarter of 2008. The $110 million net change in contract value was recorded as a regulatory asset as the costs of the contracts are recoverable from our customers. Significant judgment was involved in estimating the fair values of the contracts, including projections of capacity prices and reflecting the probabilities of cash flows considering the risks and uncertainties associated with the contracts.

We have entered into agreements which are derivatives and do not meet the normal purchases and sales exception. These contracts are marked to market and included in derivative assets and liabilities on the accompanying consolidated balance sheets. The offset to these derivatives are recorded as regulatory assets or liabilities as these amounts are recoverable from or refunded to our customers as they are incurred. The measurement of many of these contracts is extremely complex, as contracts are long-dated and many of the variables, such as discount rates, future energy and energy-related product prices, and the risk associated with projects that have not been completed, require significant management judgment.

For further information, see Note 1E, "Summary of Significant Accounting Policies - Derivative Accounting," and Note 3, "Derivative Instruments," to the consolidated financial statements.

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

Unbilled revenues represent an estimate of electricity delivered to customers that has not yet been billed. Unbilled revenues are included in revenue on the statement of income and are assets on the balance sheet that are reclassified to accounts receivable in the following month as customers are billed. Such estimates are subject to adjustment when actual meter readings become available, when changes in estimating methodology occur and under other circumstances. There were no changes in estimating methodology in 2007.

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

The estimate of unbilled revenues is sensitive to numerous factors, such as energy demands, weather and changes in the composition of customer classes that can significantly impact the amount of revenues recorded. Estimating the impact of these factors is complex and requires our judgment. The estimate of unbilled revenues is important to our consolidated financial statements, as adjustments to that estimate could significantly impact operating revenues and earnings.

For further information, see Note ID, "Summary of Significant Accounting Policies - Revenues," to the consolidated financial statements and "Transmission Rate Matters and FERC Regulatory Issues" to this Management’s Discussion and Analysis.

Regulatory Accounting: Our accounting policies conform to GAAP 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."

During 2007, several items of a regulatory nature required our judgment. These items included:

Procurement Fee: We submitted to the DPUC our proposed methodology to calculate the variable incentive portion of the procurement fee, which was effective through 2006, and requested approval of the $5.8 million 2004 incentive fee. We have not recorded amounts related to the 2005 or 2006 procurement fee in earnings, though we estimate that if our methodology is upheld, we would record after-tax amounts of $3.3 million for 2006 and $3.6 million for 2005 in 2008.

For more information, see Note 5A, "Commitments and Contingencies - Regulatory Developments and Rate Matters," to the accompanying 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, we record regulatory assets before approval for recovery has been received from the applicable regulatory commission. We must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery. We base our conclusion on certain factors, including but not limited to 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 probable future refunds to customers.

We use our 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 our consolidated financial statements. We believe it is probable that we will recover the regulatory assets that have been recorded. If we determined that we could no longer apply SFAS No. 71 to our operations, or if we could not conclude that it is probable that revenues or costs would be recovered or reflected in future rates, the revenues or costs would be charged to income in the period in which they were incurred. If we determine that a regulatory asset is no longer probable of recovery in rates, then SFAS No. 71 requires that we record the charge in earnings at that time.

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

Pension and PBOP: We participate in a uniform noncontributory defined benefit retirement plan (Pension Plan), sponsored by NU, covering substantially all our regular employees. In addition to the Pension Plan, we also participate in a Postretirement Benefits Other Than Pensions (PBOP Plan), sponsored by NU, to provide certain health care benefits, primarily medical and dental, and life insurance benefits to retired employees. For each of these plans, the development of the benefit obligation, fair value of plan assets, funded status and net periodic benefit credit or cost is based on several significant assumptions. If these assumptions were changed, the

resulting changes in benefit obligations, fair values of plan assets, funded status and net periodic expense could have a material impact on our consolidated financial statements.

Pre-tax periodic pension expense for the Pension Plan was a benefit of $15.6 million in 2007, an expense of $2.4 million in 2006, and a benefit of $0.6 million for 2005. The pension benefit and expense amounts exclude one-time items such as Pension Plan curtailments and termination benefits.

The pre-tax net PBOP Plan cost, excluding curtailments and termination benefits, was $16.1 million, $21.6 million and $21.5 million for the years ended December 31, 2007, 2006 and 2005, respectively.

Long-Term Rate of Return Assumptions: In developing the expected long-term rate of return assumptions for the Pension Plan and the PBOP Plan, NU evaluated input from actuaries and consultants, as well as long-term inflation assumptions and our historical 25-year compounded return of 11.8 percent. NU’s expected long-term rates of return on assets are based on certain target asset allocation assumptions. NU believes that 8.75 percent is an appropriate aggregate long-term rate of return on Pension Plan and PBOP Plan assets (life assets and non-taxable health assets) and 6.85 percent for PBOP health assets, net of tax, for 2007. NU continues to evaluate these actuarial assumptions, including the expected rate of return, at least annually and will adjust the appropriate assumptions as necessary. The Pension Plan’s and PBOP Plan’s target asset allocation assumptions and expected long-term rates of return assumptions by asset category are as follows:


	At December 31,
	Pension Benefits				Postretirement Benefits
	2007		2006		2007 and 2006
	Target Asset Allocation	Assumed Rate of Return	Target Asset Allocation	Assumed Rate of Return	Target Asset Allocation	Assumed Rate of Return
Equity Securities:
United States	40%	9.25%	45%	9.25%	55%	9.25%
Non-United States	17%	9.25%	14%	9.25%	11%	9.25%
Emerging markets	5%	10.25%	3%	10.25%	2%	10.25%
Private	8%	14.25%	8%	14.25%	-	-
Debt Securities:
Fixed income	25%	5.50%	20%	5.50%	27%	5.50%
High yield fixed income	-	-	5%	7.50%	5%	7.50%
Real Estate	5%	7.50%	5%	7.50%	-	-

The actual asset allocations at December 31, 2007 and 2006 approximated these target asset allocations. NU routinely reviews the actual asset allocations and periodically rebalances the investments to the targeted asset allocations when appropriate. For information regarding actual asset allocations, see Note 4A, "Employee Benefits - Pension Benefits and Postretirement Benefits Other Than Pensions," to the consolidated financial statements.

Pension and other post-retirement benefit funds are held in external trusts. Trust assets, including accumulated earnings, must be used exclusively for pension and post-retirement benefit payments. Investment securities are exposed to various risks, including interest rate, credit and overall market volatility. As a result of these risks, it is reasonably probable that the market values of investment securities could increase or decrease in the near term, resulting in a material impact on the value of the pension assets. Increases or decreases in the market values could materially affect the current value of the trusts and the future level of pension and other-post retirement benefit expense. The current conditions in the credit market could negatively impact the assets in the trusts, but at this time NU still believes the 8.75 percent rate and the 6.85 percent rate for respective Pension and PBOP Plan assets are appropriate long-term rate of return assumptions.

Actuarial Determination of Expense: NU bases the actuarial determination of Pension Plan and PBOP Plan expense on a market-related value of assets (MRVA), which reduces year-to-year volatility. This MRVA 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 MRVA and the actual return based on the fair value of assets. At December 31, 2007, total investment gains to be recognized in the MRVA over the next four years are gains of $49.7 million for the Pension Plan and losses of $0.9 million for the PBOP Plan. As these asset gains/losses are reflected in MRVA over the next four years, they will be subject to amortization with other unrecognized gains/losses. The Plans currently amortize unrecognized gains/losses as a component of pension and PBOP expense over approximately 12 years, which is the average future service lives of the employees at December 31, 2007. At December 31, 2007, the net actuarial loss subject to amortization over the next 12 years was $15.9 million and $43.9 million, respectively, which excludes $49.7 million of gains and $0.9 million of losses on previous investment amounts not currently reflected in the MRVA for the Pension Plan and PBOP Plan, respectively.

Discount Rate: The discount rate that is utilized in determining future pension and PBOP obligations is based on a yield-curve approach where each cash flow related to the Pension Plan or PBOP Plan liability stream is discounted at an interest rate specifically applicable to the timing of the cash flow. The yield curve is developed from the top quartile of AA rated Moody’s and S&P’s bonds without callable features outstanding at December 31, 2007. 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 6.6 percent for the Pension Plan and 6.35 percent for the PBOP Plan at December 31, 2007. Discount rates used at December 31, 2006 were 5.9 percent for the Pension Plan and 5.8 percent for the PBOP Plan.

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


	Pension Plan				Postretirement Plan
Year	Expected Contributions		Forecasted Income		Expected Contributions		Forecasted Expense
2008	$	-	$	21.4	$	15.7	$	15.7
2009	$	-	$	23.9	$	14.5	$	14.5
2010	$	-	$	30.8	$	13.3	$	13.3

Future actual Pension and PBOP expense will depend on future investment performance, changes in future discount rates and various other factors related to the populations participating in the plans and amounts capitalized. Beginning in 2007, we made an additional contribution to the PBOP Plan for the amounts received from the federal Medicare subsidy. This amount was $1.1 million in 2007 and is estimated to be $1.8 million in 2008.

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


	At December 31,
	Pension Plan Cost				Postretirement Plan Cost
Assumption Change		2007		2006	2007		2006
Lower long-term rate of return	$	(5.1)	$	4.8	$	0.5	$	0.5
Lower discount rate	$	(4.0)	$	4.7	$	0.4	$	0.3
Lower compensation increase	$	2.5	$	(2.5)		N/A		N/A

Plan Assets: The market-related value of the Pension Plan assets has increased by $40.7 million to $1.1 billion at December 31, 2007. The projected benefit obligation (PBO) for the Pension Plan decreased by $51 million to $809.5 million at December 31, 2007. These changes have increased the overfunded status of the Pension Plan on a PBO basis by $91.7 million to $334.8 million at December 31, 2007. The PBO includes expectations of future employee compensation increases. We have not made any employer contributions to the Pension Plan since 1991.

The accumulated benefit obligation (ABO) of the Pension Plan was approximately $421.1 million and $332.5 million less than Pension Plan assets at December 31, 2007 and 2006. The ABO is the obligation for employee service and compensation provided through December 31, 2007.

The value of PBOP Plan assets has increased by $5 million to $106.3 million at December 31, 2007. The benefit obligation for the PBOP Plan has decreased by $2.2 million to $184.9 million at December 31, 2007. These changes have decreased the underfunded status of the PBOP Plan on an accumulated projected benefit obligation basis from $85.8 million at December 31, 2006 to $78.6 million at December 31, 2007. We have made a contribution each year equal to the PBOP Plan’s postretirement benefit cost, excluding curtailment and termination benefits.

Health Care Cost: The health care cost trend assumption used to project increases in medical costs was reset at 8.5 percent for 2008, decreasing one half percentage point per year to an ultimate rate of 5 percent in 2015. The effect of increasing the health care cost trend by one percentage point would have increased service and interest cost components of the PBOP Plan cost by $0.4 million in 2007 and $0.5 million in 2006. Changes in the long-term health care cost trend assumption could have a material impact on our financial statements.

Presentation: In accordance with GAAP, our consolidated financial statements include all subsidiaries over which control is maintained and would include any variable interest entities (VIE) for which we are the primary beneficiary. Determining whether we are the primary beneficiary of a VIE is complex, subjective and requires our judgment. There are certain variables taken into consideration to determine whether we are considered the primary beneficiary of a VIE. A change in any one of these variables could require us to reconsider whether or not we are the primary beneficiary of the VIE.

The Energy Independence Act requires the DPUC to investigate the financial impact on distribution companies of entering into long-term contracts for capacity or contracts to purchase renewable energy products from new generating plants. We reviewed each contract to determine the appropriate accounting treatment based on the terms of the contracts. Determining whether or not consolidation is required involves our judgment.

Pursuant to the Energy Independence Act, in April of 2007 we entered into a 15-year agreement beginning in 2010 to purchase energy, capacity and renewable energy credits from a biomass energy plant yet to be built. We evaluated whether entering into the contract would require consolidation and determined that consolidation of the project would not be required. The review of this contract required significant management judgment.

In 2007, the DPUC approved two of our contracts associated with the capacity of two generating projects to be built or modified and two capacity-related contracts entered into by UI, one with a generating project to be built and one with a new demand response project. The contracts, referred to as CfDs, obligate us and UI to pay the difference between a set capacity price and the value that the projects

receive in the ISO-NE capacity markets for periods of up to 15 years beginning in 2009. We have an agreement with UI under which we will share the costs and benefits of these four CfDs with 80 percent to us and 20 percent to UI. The ultimate cost to us under the contracts will depend on the capacity prices that the projects receive in the ISO-NE capacity markets. We determined that these contracts do not require consolidation.

Changes in facts and circumstances resulting in reevaluation of the accounting treatment of these contracts could have a significant impact on the accompanying consolidated financial statements.

Other Matters

Accounting Standards Issued But Not Yet Adopted:

Fair Value Measurements: On September 15, 2006, the FASB issued SFAS No. 157, "Fair Value Measurements," which establishes a framework for identifying and measuring fair value and is required to be implemented in the first quarter of 2008. The statement defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. SFAS No. 157 provides a fair value hierarchy, giving the highest priority to quoted prices in active markets, and is applicable to fair value measurements of derivative contracts that are subject to mark-to-market accounting and to other assets and liabilities that are reported at fair value or subject to fair value measurements.

We are currently evaluating the effects of implementing SFAS No. 157, which are only expected to impact our consolidated balance sheet. These effects will include adjustments to reflect the initial fair value of derivative contracts that were in a gain or loss position at inception that was not recognized under previous accounting standards. SFAS No. 157 requires these adjustments to be recorded in retained earnings as of January 1, 2008. However, the cost or benefit of the contracts is expected to be fully recovered from or refunded to our customers. Therefore, adjustments to reflect these previously unrecorded balances will be recorded as regulatory assets or liabilities. In addition, updates to the fair values of our previously recorded derivatives to reflect their exit prices and nonperformance risk will also be recorded as regulatory assets or liabilities.

The Fair Value Option: On February 15, 2007, the FASB issued SFAS No. 159, "The Fair Value Option for Financial Assets and Financial Liabilities - including an amendment of FAS 115." SFAS No. 159 allows entities to choose, at specified election dates, to measure at fair value eligible financial assets and liabilities that are not otherwise required to be measured at fair value. SFAS No. 159 is effective in the first quarter of 2008, with the effect of application to eligible items as of January 1, 2008 required to be reflected as a cumulative-effect adjustment to the opening balance of retained earnings. If a company elects the fair value option for an eligible item, changes in that item's fair value at subsequent reporting dates must be recognized in earnings. We are currently evaluating whether or not to elect the fair value option for our securities held in trust as of January 1, 2008. Implementation of SFAS No. 159 for our securities held in trust is not expected to have a material effect on the consolidated financial statements.

Contractual Obligations and Commercial Commitments:

Information regarding our contractual obligations and commercial commitments at December 31, 2007 is summarized through 2012 and thereafter as follows:


(Millions of Dollars)	2008		2009		2010		2011		2012		Thereafter		Totals
Long-term debt maturities ^{(a) (b)}	$	-	$	-	$	-	$	-	$	-	$	1,793.7	$	1,793.7
Estimated interest payments on existing debt^(c)		104.3		104.3		104.3		104.3		104.3		1,613.2		2,134.7
Capital leases ^{(d) (e)}		3.2		3.5		1.7		1.7		1.8		16.8		28.7
Operating leases ^{(e) (f)}		18.8		17.2		15.3		12.0		10.2		45.0		118.5
Required funding of other post- retirement benefit obligations ^(f)		15.7		14.5		13.3		12.7		12.1		N/A		68.3
Estimated future annual costs ^{(e) (g)}		783.3		278.3		307.1		532.3		531.7		1,753.4		4,186.1
Other purchase commitments ^{(f) (h)}		450.9		-		-		-		-		-		450.9
Totals ⁽ⁱ⁾	$	1,376.2	$	417.8	$	441.7	$	663.0	$	660.1	$	5,222.1	$	8,780.9

^(a)

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

^(b)

Long-term debt disclosed above excludes $238.7 million of fees and interest due for spent nuclear fuel disposal costs and a negative $3.9 million of net unamortized premium and discount as of December 31, 2007.

^(c)

Estimated interest payments on fixed-rate debt are calculated by multiplying the coupon rate on the debt by its scheduled notional amount outstanding for the period of measurement.

^(d)

The capital lease obligations include imputed interest of $15.1 million as of December 31, 2007.

^(e)

We have no provisions in our capital or operating lease agreements or agreements related to our future estimated annual costs that could trigger a change in terms and conditions, such as acceleration of payment obligations.

^(f)

Amounts are not included on our consolidated balance sheets.

^(g)

Other than the mark-to-market on respective derivative contracts, these obligations are not included on our consolidated balance sheets. Estimated costs for 2008 are higher than costs in future years due to the timing of completion of transmission segment development projects. For further information on these estimated future annual costs, see Note 5D, “Commitments and Contingencies – Long-Term Contractual Arrangements.”

^(h)

Amount represents open purchase orders, excluding those obligations that are included in the capital leases, operating leases and estimated future annual costs. These payments are subject to change as certain purchase orders include estimates based on projected quantities of material and/or services that are provided on demand, the timing of which cannot be determined. Because payment timing cannot be determined, we include all open purchase order amounts in 2008.

⁽ⁱ⁾

Excludes FIN 48 unrecognized tax benefits of $75.9 million as of December 31, 2007 as we cannot make reasonably reliable estimates of the periods or the potential amounts of cash settlement with the respective taxing authorities.

Rate reduction bond amounts are non-recourse to us, have no required payments over the next five years and are not included in this table. Our standard offer service contracts and default service contracts also are not included in this table. The estimated payments under interest rate swap agreements are not included in this table as the estimated payment amounts are not determinable. In addition, there are no Pension Plan contributions expected and therefore no amounts are included in this table. For further information regarding our contractual obligations and commercial commitments, see Note 2, "Short-Term Debt," Note 4A, “Employee Benefits – Pension Benefits and Postretirement Benefits Other Than Pensions,” Note 5D, "Commitments and Contingencies - Long-Term Contractual Arrangements," Note 7, "Leases," and Note 11, "Long-Term Debt," to the consolidated financial statements.

Forward Looking Statements: This discussion and analysis includes statements concerning our expectations, beliefs, plans, objectives, goals, strategies, assumptions of future events, financial performance or growth 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. You can generally identify these "forward looking statements" through the use of words or phrases such as "estimate," "expect," "anticipate," "intend," "plan," "project," "believe," "forecast," "should," "could," and similar expressions. Forward looking statements involve risks and uncertainties that may cause actual results or outcomes to differ materially from those included in the forward looking statements. Factors that may cause actual results to differ materially from those included in the forward looking statements include, but are not limited to, actions by state and federal regulatory bodies, competition and industry restructuring, changes in economic conditions, changes in weather patterns, changes in laws, regulations or regulatory policy, changes in levels or timing of capital expenditures, developments in legal or public policy doctrines, technological developments, changes in accounting standards and financial reporting regulations, actions of rating agencies, and other presently unknown or unforeseen factors. Other risk factors are detailed from time to time in our reports to the Securities and Exchange Commission. We undertake no obligation to update the information contained in any forward looking statements to reflect events or circumstances after the date on which such statements are made or to reflect the occurrence of unanticipated events.

Web Site: Additional financial information is available through our web site at www.cl-p.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	2007 over/(under) 2006				2006 over/(under) 2005
(Millions of Dollars)	Amount		Percent		Amount		Percent
Operating Revenues	$	(298)	(7)	%	$	513	15	%

Operating Expenses:
Operation -
Fuel, purchased and net interchange power		(327)	(13)			458	21
Other operation		(79)	(13)			57	10
Maintenance		7	6			6	7
Depreciation		4	3			14	11
Amortization of regulatory assets/(liabilities), net		32	(a)			(71)	(a)
Amortization of rate reduction bonds		9	7			9	7
Taxes other than income taxes		7	4			6	4
Total operating expenses		(347)	(9)			479	15
Operating Income		49	21			34	17
Interest expense, net		21	17			(2)	(2)
Other income, net		2	5			(7)	(16)
Income before income tax expense		30	19			29	23
Income tax expense		96	(a)			(76)	(a)
Net income	$	(66)	(33)	%	$	105	(a)	%

(a) Percent greater than 100.

Comparison of the Year 2007 to the Year 2006

Operating Revenues

Operating revenues decreased $298 million due to lower distribution segment revenues ($373 million), partially offset by higher transmission segment revenues ($75 million).

The distribution segment revenue decrease of $373 million is primarily due to the components of revenues, which are included in regulatory commission approved tracking mechanisms that track the recovery of certain incurred costs ($388 million). The distribution segment revenue tracking components decreased $388 million primarily due to a decrease in revenues associated with the recovery of generation service and related congestion charges ($265 million) and lower delivery-related FMCC revenue ($104 million). The lower generation service and related congestion charge revenue was primarily due to a reduction in load caused primarily by customer migration to third party suppliers, partially offset by an increase in these rate components to recover higher 2007 supply prices. The lower delivery-related FMCC revenue was primarily due to a decrease in this rate component in 2007 as a result of the use of prior year over recoveries to recover current year costs, as well as lower anticipated RMR costs in 2007. The tracking mechanisms allow for rates to be changed periodically with over collections refunded to customers or under collections collected from customers in future periods.

The distribution component of revenues which impacts earnings increased $14 million as a result of the rate increase effective January 1, 2007 and higher retail sales. Retail sales increased 1.7 percent in 2007 compared to the same period in 2006.

Transmission segment revenues increased $75 million primarily due to a higher rate base and higher operating expenses, which are recovered under FERC-approved transmission tariffs.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expense decreased $327 million primarily due to a decrease in generation service supply costs ($286 million) and lower other purchased power costs ($73 million), partially offset by an increase in deferred fuel costs of $32 million, all of which are included in regulatory commission-approved tracking mechanisms. The $286 million decrease in supply costs was primarily due to a reduction in load caused primarily by customer migration to third party suppliers, partially offset by higher 2007 supply prices. These supply costs are the contractual amounts the company must pay to various suppliers that have earned the right to supply Standard Service and Last Resort Service load through a competitive solicitation process. The $32 million increase in deferred fuel costs was largely the result of the deferral of significant refunds received from the ISO-NE associated with previously remitted reliability must run payments that must be returned to customers.

Other Operation

Other operation expenses decreased $79 million primarily due to lower RMR costs ($133 million), which are tracked and recovered through the FMCC, partially offset by higher Energy Independence Act (EIA) expenses which will also be recovered through the FMCC deferral mechanism ($29 million), Summer Saver Rewards Program which was implemented in 2007 as a result of a legislative act ($14 million) and higher administrative expense ($8 million).

Maintenance

Maintenance expenses increased $7 million primarily due to higher transmission segment expenses ($5 million) and higher distribution segment expenses ($2 million).

Higher transmission segment expenses of $5 million in 2007 are primarily due to higher levels of employee support, compliance inspections, deferred maintenance, training, and unplanned repairs to transmission cables at CL&P.

Higher distribution segment expenses of $2 million in 2007 are primarily due to higher expenses related to substation maintenance, underground network inspection activities, line transformer maintenance, partially offset by lower expenses related to overhead lines maintenance primarily due to less storm-related expenses.

Depreciation

Depreciation expense increased $4 million primarily due to higher utility plant balances resulting from the ongoing construction program.

Amortization of Regulatory Assets/(Liabilities), Net

Amortization of regulatory assets/(liabilities), net increased $32 million primarily due to higher amortization related to the recovery of transition charges ($32 million), higher SFAS No. 109 amortization ($7 million), partially offset by a lower system benefit charge deferral ($8 million).

Amortization of Rate Reduction Bonds

Amortization of rate reduction bonds increased $9 million. The higher portion of principal within the rate reduction bonds’ payment results in a corresponding increase in the amortization of regulatory assets.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $7 million primarily due to higher property taxes primarily related to new transmission projects such as the Bethel-Norwalk project that were completed in 2006, but not reflected in our tax assessment until 2007.

Interest Expense, Net

Interest expense, net increased $21 million primarily due to higher interest on long-term debt ($19 million) mainly as a result of $250 million of new debt issued in June of 2006, $300 million of new debt issued in March of 2007 and $200 million of new debt issued in September of 2007, higher FMCC deferral interest ($6 million) and higher interest on short-term debt ($2 million), partially offset by lower rate reduction bond interest resulting from lower principal balances outstanding ($9 million).

Other Income, Net

Other income, net increased $2 million primarily due to a higher equity AFUDC income ($7 million) as a result of higher eligible construction work in progress due to the transmission construction program, higher Energy Independence Act (EIA) incentives ($4 million) and higher equity of earnings of regional nuclear generating companies ($3 million), partially offset by the elimination of the TSO procurement fee approved by the DPUC associated with the TSO supply procurement that expired at the end of 2006 ($11 million).

Income Tax Expense/(Benefit)

Income tax expense/(benefit) increased $96 million primarily due to the nonrecurring tax items in 2006 which included a $74 million tax benefit from the removal of deferred tax balances associated with a PLR received from the IRS, a decrease in favorable tax adjustments, lower state tax credits and higher pre-tax earnings.

Comparison of the Year 2006 to the Year 2005

Operating Revenues

Operating revenues increased $513 million due to higher distribution segment revenues ($471 million) and higher transmission segment revenues ($42 million).

The distribution segment revenue increase of $471 million is primarily due to the components of revenues which are included in regulatory commission approved tracking mechanisms that track the recovery of certain incurred costs ($472 million). The distribution segment revenue tracking components increased $472 million primarily due to higher TSO related revenues ($458 million) as a result of the pass through of higher energy supply costs, an increase in revenues associated with the recovery of FMCC charges ($36 million) and higher retail transmission revenues ($24 million), partially offset by lower wholesale revenues ($45 million), as a result of the expiration or sale of market-based contracts. The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections collected from customers in future periods.

The distribution component of revenues which impacts earnings was flat, with an increase in rates offset by lower sales. Retail sales decreased 4.9 percent in 2006 compared to the same period of 2005.

Transmission segment revenues increased $42 million primarily due to a higher rate base and higher operating expenses which are recovered under FERC-approved transmission tariffs.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expense increased $458 million primarily due to higher standard offer supply costs and higher purchased power costs as a result of higher energy prices, which are included in regulatory commission approved tracking mechanisms, partially offset by lower fuel costs for wholesale transactions.

Other Operation

Other operation expenses increased $57 million primarily due to higher reliability must run (RMR) costs ($36 million) which are tracked and recovered through the FMCC, higher other power pool related costs ($7 million), higher conservation and load management (C&LM) expenses ($7 million) which are included in a regulatory rate tracking mechanism, and higher uncollectible account expenses ($5 million).

Maintenance

Maintenance expenses increased $6 million primarily due to higher tree trimming expenses ($3 million), higher expenses related to overhead lines ($1 million) and underground lines ($1 million), and higher station equipment expenses ($1 million).

Depreciation

Depreciation expense increased $14 million primarily due to higher utility plant balances resulting from the ongoing construction program.

Amortization of Regulatory Assets/(Liabilities), Net

Amortization of regulatory assets/(liabilities), net decreased $71 million primarily due to lower amortization related to the recovery of transition charges ($70 million).

Amortization of Rate Reduction Bonds

Taxes Other Than Income Taxes

Taxes other than income taxes increased $6 million primarily due to higher gross earnings taxes ($5 million) and higher property taxes ($2 million).

Interest Expense, Net

Interest expense, net decreased $2 million primarily due to lower rate reduction bond interest resulting from lower principal balances outstanding, partially offset by higher interest on long-term debt mainly as a result of $250 million of new debt issued in June of 2006 and $200 million of new debt issued in April of 2005.

Other Income, Net

Other income, net decreased $7 million primarily due to a lower TSO procurement fee ($7 million) and lower equity AFUDC income resulting from the partial inclusion of transmission CWIP in rate base ($4 million), partially offset by Energy Independence Act (EIA) incentives ($5 million).

Income Tax Benefit/(Benefit)

Income tax expense/(benefit) decreased $76 million in 2006 due to favorable tax adjustments, partially offset by higher equity pre-tax earnings. Deferred tax adjustments included a tax benefit of $74 million to remove the UITC and EDIT deferred tax balances in conformity with an IRS PLR and pursuant to a DPUC order. Additional tax benefits resulted from higher state tax credits, a deferred tax adjustment related to generation plant sold to an affiliate, a Connecticut tax settlement and year over year change in estimate to actual adjustments. These additional benefits were partially offset by less favorable plant related differences.

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 The Connecticut Light and Power Company and subsidiaries (CL&P or the Company) and of other sections of this annual report.

Management is responsible for establishing and maintaining adequate internal controls over financial reporting. The Company’s internal control framework and processes have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. There are inherent limitations of internal controls over financial reporting that could allow material misstatements due to error or fraud to occur and not be prevented or detected on a timely basis by employees during the normal course of business. Additionally, internal controls over financial reporting may become inadequate in the future due to changes in the business environment.

Under the supervision and with the participation of management, including our principal executive officer and principal financial officer, CL&P conducted an evaluation of the effectiveness of internal controls over financial reporting based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation under the framework in COSO, management concluded that our internal controls over financial reporting were effective as of December 31, 2007.

February 28, 2008

Report of Independent Registered Public Accounting Firm

To the Board of Directors of
The Connecticut Light and Power Company:

We have audited the accompanying consolidated balance sheets of The Connecticut Light and Power Company and subsidiaries (a Connecticut corporation and a wholly owned subsidiary of Northeast Utilities) (the "Company") as of December 31, 2007 and 2006, and the related statements of income, comprehensive income, common stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2007. 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, 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 The Connecticut Light and Power Company and subsidiaries as of December 31, 2007 and 2006, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 1.G., the Company adopted Financial Accounting Standards Board Interpretation No. 48, Accounting for Uncertainty in Income Taxes – an Interpretation of FASB Statement No. 109, as of January 1, 2007.


/s/	Deloitte & Touche LLP
	Deloitte & Touche LLP

Hartford, Connecticut

February 28, 2008


THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS


At December 31,	2007	2006
	(Thousands of Dollars)

ASSETS

Current Assets:
Cash	$ 538	$ 3,310
Investments in securitizable assets	308,182	375,656
Receivables, less provision for uncollectible
accounts of $7,874 in 2007 and $1,679 in 2006	118,342	73,052
Accounts receivable from affiliated companies	3,339	1,965
Unbilled revenues	8,225	8,044
Taxes receivable	16,245	-
Materials and supplies	55,477	39,447
Derivative assets - current	57,003	45,031
Prepayments and other	17,387	15,945
	584,738	562,450

Property, Plant and Equipment:
Electric utility	4,899,075	4,557,231
Less: Accumulated depreciation	1,279,697	1,260,526
	3,619,378	3,296,705
Construction work in progress	782,468	337,665
	4,401,846	3,634,370

Deferred Debits and Other Assets:
Regulatory assets	1,329,963	1,477,375
Prepaid pension	334,786	243,139
Derivative assets - long-term	278,726	249,423
Other	88,040	154,537
	2,031,515	2,124,474









Total Assets	$ 7,018,099	$ 6,321,294



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


THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS


At December 31,	2007		2006
	(Thousands of Dollars)

LIABILITIES AND CAPITALIZATION

Current Liabilities:
Notes payable to affiliated companies	$ 38,825	$ 258,925
Accounts payable	368,356	326,163
Accounts payable to affiliated companies	53,096	47,906
Accrued taxes	-	186,647
Accrued interest	29,532	29,587
Derivative liabilities - current	4,234	4,101
Other	107,940	80,543
	601,983	933,872

Rate Reduction Bonds	548,686	743,899

Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	698,789	719,470
Accumulated deferred investment tax credits	21,412	24,019
Deferred contractual obligations	152,735	185,195
Regulatory liabilities	601,455	582,841
Derivative liabilities - long-term	135,991	31,923
Accrued postretirement benefits	78,587	85,768
Other	191,464	127,638
	1,880,433	1,756,854
Capitalization:
Long-Term Debt	2,028,546	1,519,440

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

Common Stockholder's Equity:
Common stock, $10 par value - authorized
24,500,000 shares; 6,035,205 shares outstanding
in 2007 and 2006	60,352	60,352
Capital surplus, paid in	1,243,940	672,693
Retained earnings	538,138	513,344
Accumulated other comprehensive (loss)/income	(179)	4,640
Common Stockholder's Equity	1,842,251	1,251,029
Total Capitalization	3,986,997	2,886,669

Commitments and Contingencies (Note 5)
.
Total Liabilities and Capitalization	$ 7,018,099	$ 6,321,294


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


THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME



For the Years Ended December 31,	2007	2006	2005
	(Thousands of Dollars)


Operating Revenues	$ 3,681,817	$ 3,979,811	$ 3,466,420

Operating Expenses:
Operation -
Fuel, purchased and net interchange power	2,277,054	2,603,882	2,145,834
Other	535,750	614,372	557,587
Maintenance	108,001	101,443	95,076
Depreciation	152,005	147,460	133,135
Amortization of regulatory assets/(liabilities), net	20,593	(11,251)	59,632
Amortization of rate reduction bonds	135,929	126,909	118,488
Taxes other than income taxes	167,943	160,926	154,619
Total operating expenses	3,397,275	3,743,741	3,264,371
Operating Income	284,542	236,070	202,049

Interest Expense:
Interest on long-term debt	84,292	64,873	59,019
Interest on rate reduction bonds	37,728	46,692	55,796
Other interest	16,413	6,281	5,220
Interest expense, net	138,433	117,846	120,035
Other Income, Net	39,808	37,822	45,005
Income Before Income Tax Expense/(Benefit)	185,917	156,046	127,019
Income Tax Expense/(Benefit)	52,353	(43,961)	32,174
Net Income	$ 133,564	$ 200,007	$ 94,845

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Net Income	$ 133,564	$ 200,007	$ 94,845
Other comprehensive (loss)/income, net of tax:
Qualified cash flow hedging instruments	(4,814)	4,537	-
Unrealized (losses)/gains on securities	(5)	17	(22)
Minimum SERP liability	-	364	120
Other comprehensive (loss)/income, net of tax	(4,819)	4,918	98
Comprehensive Income	$ 128,745	$ 204,925	$ 94,943



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


THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY



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

Balance at January 1, 2005	6,035,205	$ 60,352	$ 415,140	$ 347,176	$ (376)	$ 822,292

Net income for 2005				94,845		94,845
Dividends on preferred stock				(5,559)		(5,559)
Dividends on common stock				(53,834)		(53,834)
Allocation of benefits - ESOP			(476)			(476)
Tax deduction for stock options exercised and Employee
Stock Purchase Plan disqualifying dispositions			171			171
Capital stock expenses, net			186			186
Capital contribution from NU parent			197,794			197,794
Other comprehensive income					98	98
Balance at December 31, 2005	6,035,205	60,352	612,815	382,628	(278)	1,055,517

Net income for 2006				200,007		200,007
Dividends on preferred stock				(5,559)		(5,559)
Dividends on common stock				(63,732)		(63,732)
Allocation of benefits - ESOP			(157)			(157)
Tax deduction for stock options exercised and Employee
Stock Purchase Plan disqualifying dispositions			(995)			(995)
Capital stock expenses, net			275			275
Capital contribution from NU parent			60,755			60,755
Other comprehensive income					4,918	4,918
Balance at December 31, 2006	6,035,205	60,352	672,693	513,344	4,640	1,251,029

Adoption of FIN48 - accounting
for uncertainty of income taxes				(24,030)		(24,030)
Net income for 2007				133,564		133,564
Dividends on preferred stock				(5,559)		(5,559)
Dividends on common stock				(79,181)		(79,181)
Allocation of benefits - ESOP			446			446
Capital stock expenses, net			140			140
Capital contribution from NU parent			570,661			570,661
Other comprehensive loss					(4,819)	(4,819)
Balance at December 31, 2007	6,035,205	$ 60,352	$1,243,940	$ 538,138	$ (179)	$ 1,842,251



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


THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31,	2007	2006	2005
	(Thousands of Dollars)
Operating Activities:
Net income	$ 133,564	$ 200,007	$ 94,845
Adjustments to reconcile to net cash flows
provided by operating activities:
Bad debt expense	18,121	13,582	12,834
Depreciation	152,005	147,460	133,135
Deferred income taxes	28,725	(154,260)	(16,585)
Amortization of regulatory assets/(liabilities), net	20,593	(11,251)	59,632
Amortization of rate reduction bonds	135,929	126,909	118,488
Amortization of recoverable energy costs	3,440	3,839	36,090
Pension (income)/expense, net of capitalized portion	(8,271)	438	1,491
Regulatory overrecoveries/(refunds)	4,441	(80,888)	(73,442)
Deferred contractual obligations	(28,019)	(61,273)	(60,444)
Other non-cash adjustments	(17,930)	(7,223)	(8,730)
Other sources of cash	89	15,728	702
Other uses of cash	(13,436)	(804)	(14,192)
Changes in current assets and liabilities:
Receivables and unbilled revenues, net	(44,025)	22,924	25,648
Materials and supplies	(16,030)	(6,518)	284
Investments in securitizable assets	33,531	(158,254)	(113,410)
Other current assets	(3,208)	6,786	(1,779)
Accounts payable	3,457	56,628	25,312
Taxes (receivable)/accrued	(216,714)	126,116	61,297
Other current liabilities	13,471	11,421	16,097
Net cash flows provided by operating activities	199,733	251,367	297,273

Investing Activities:
Investments in property and plant	(826,248)	(567,151)	(444,384)
Proceeds from sales of investment securities	2,015	2,210	1,883
Purchases of investment securities	(2,154)	(2,369)	(1,993)
Net proceeds from sale of property	-	-	21,993
Rate reduction bond escrow and other deposits	56,872	(51,985)	(5,048)
Other investing activities	3,923	12,032	6,126
Net cash flows used in investing activities	(765,592)	(607,263)	(421,423)

Financing Activities:
Issuance of long-term debt	500,000	250,000	200,000
Retirement of rate reduction bonds	(195,213)	(112,580)	(138,754)
(Decrease)/increase in NU Money Pool borrowings	(220,100)	232,100	(63,200)
Capital contributions from NU parent	570,661	60,756	197,794
Decrease in short-term debt	-	-	(15,000)
Cash dividends on preferred stock	(5,559)	(5,559)	(5,559)
Cash dividends on common stock	(79,181)	(63,732)	(53,834)
Other financing activities	(7,521)	(4,080)	(604)
Net cash flows provided by financing activities	563,087	356,905	120,843
Net (decrease)/increase in cash	(2,772)	1,009	(3,307)
Cash - beginning of year	3,310	2,301	5,608
Cash - end of year	$ 538	$ 3,310	$ 2,301

Supplemental Cash Flow Information:
Cash paid/(received) during the year for:
Interest, net of amounts capitalized	$ 156,445	$ 117,856	$ 125,249
Income taxes	$ 241,219	$ (16,364)	$ (12,761)

Non-cash investing activities:
Capital expenditures incurred but not paid	$ 126,148	$ 76,248	$ 53,725

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

Notes To Consolidated Financial Statements

Summary of Significant Accounting Policies

About The Connecticut Light and Power Company

The Connecticut Light and Power Company (CL&P or the company) is a wholly-owned subsidiary of Northeast Utilities (NU). CL&P is a reporting company under the Securities Exchange Act of 1934. Until February 8, 2006, NU was registered with the Securities and Exchange Commission (SEC) as a holding company under the Public Utility Holding Company Act of 1935 (PUHCA). On February 8, 2006, PUHCA was repealed. NU is now registered with the Federal Energy Regulatory Commission (FERC) as a public utility holding company under the PUHCA of 2005. Arrangements among CL&P, other NU companies, outside agencies, and other utilities covering interconnections, interchange of electric power and sales of utility property, are subject to regulation by the FERC. CL&P is subject to further regulation for rates, accounting and other matters by the FERC and the Connecticut Department of Public Utility Control (DPUC). CL&P furnishes franchised retail electric service in Connecticut. CL&P’s results include the operations of its distribution and transmission segments.

Several wholly-owned subsidiaries of NU provide support services for NU’s companies, including CL&P. 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 CL&P.

At December 31, 2007 and 2006, CL&P had a long-term receivable from NUSCO in the amount of $25 million that is included in deferred debits and other assets - other on the accompanying consolidated balance sheets related to the funding of investments held in trust by NUSCO in connection with certain postretirement benefits for CL&P employees.

Included in the consolidated balance sheet at December 31, 2007, are accounts receivable from affiliated companies and accounts payable to affiliated companies totaling $3.3 million and $53.1 million, respectively, relating to transactions between CL&P and other subsidiaries that are wholly-owned by NU. At December 31, 2006, these amounts totaled $2 million and $47.9 million, respectively.

Total CL&P purchases from Select Energy, Inc. (Select Energy), another NU subsidiary, were $6.1 million and $53.4 million for the years ended December 31, 2006 and 2005, respectively. There were no such purchases in 2007.

The Rocky River Realty Company (RRR), a subsidiary of NU, conveyed a Conservation Easement (CE) on a parcel of land to the Connecticut Forest and Park Association in 2007, as a mitigation requirement for CL&P’s Middletown to Norwalk, Connecticut transmission project. Pursuant to this transaction, CL&P paid $1.4 million for the fair value of the land to RRR and RRR maintains ownership of the land. This payment has been recorded as a permitting cost for the Middletown to Norwalk project and is included as construction work in progress (CWIP) on the accompanying consolidated balance sheet as of December 31, 2007.

In 2007, CL&P made a discretionary contribution of $0.6 million to the NU Foundation, Inc. (Foundation), an independent not-for-profit charitable entity designed to invest in projects that emphasize economic development, workforce training and education, and a clean and healthy environment. The board of directors of the Foundation consists of certain NU officers. Any donations made to the Foundation negatively impact the earnings of CL&P.

Presentation

The consolidated financial statements of CL&P include the accounts of its subsidiaries, CL&P Receivables Corporation (CRC) and CL&P Funding LLC. Intercompany transactions have been eliminated in consolidation.

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

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

Accounting Standards Issued But Not Yet Adopted

Fair Value Measurements: On September 15, 2006, the Financial Accounting Standards Board (FASB) issued SFAS No. 157, "Fair Value Measurements," which establishes a framework for identifying and measuring fair value and is required to be implemented in the first quarter of 2008. The statement defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. SFAS No. 157 provides a fair value hierarchy, giving the highest priority to quoted prices in active markets, and is applicable to fair value measurements of derivative contracts that are subject to mark-to-market accounting and to other assets and liabilities that are reported at fair value or subject to fair value measurements.

Management is currently evaluating the effects of implementing SFAS No. 157, which are only expected to impact the consolidated balance sheet. These effects will include adjustments to reflect the initial fair value of derivative contracts that were in a gain or loss position at inception that was not recognized under previous accounting standards. SFAS No. 157 requires these adjustments to be recorded in retained earnings as of January 1, 2008. However, the cost or benefit of the contracts is expected to be fully recovered from or refunded to its customers. Therefore, adjustments to reflect these previously unrecorded balances will be recorded as regulatory assets or liabilities. In addition, updates to the fair values of previously recorded derivatives to reflect their exit prices and nonperformance risk will also be recorded as regulatory assets or liabilities.

The Fair Value Option: On February 15, 2007, the FASB issued SFAS No. 159, "The Fair Value Option for Financial Assets and Financial Liabilities - including an amendment of FAS 115." SFAS No. 159 allows entities to choose, at specified election dates, to measure at fair value eligible financial assets and liabilities that are not otherwise required to be measured at fair value. SFAS No. 159 is effective in the first quarter of 2008, with the effect of application to eligible items as of January 1, 2008 required to be reflected as a cumulative-effect adjustment to the opening balance of retained earnings. If a company elects the fair value option for an eligible item, changes in that item's fair value at subsequent reporting dates must be recognized in earnings. Management is currently evaluating whether or not to elect the fair value option for CL&P’s securities held in trust as of January 1, 2008. Implementation of SFAS No. 159 for CL&P's securities held in trust is not expected to have a material effect on the consolidated financial statements.

Revenues

CL&P’s retail revenues are based on rates approved by the DPUC. In general, rates can only be changed through formal proceedings with the DPUC. However, CL&P utilizes DPUC-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.

Unbilled Revenues: Unbilled revenues represent an estimate of electricity delivered to customers for which customers have not yet been billed. Unbilled revenues are included in revenue on the statement of income and are assets on the balance sheet that are reclassified to accounts receivable in the following month as customers are billed. Such estimates are subject to adjustment when actual meter readings become available or under other circumstances.

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

Transmission Revenues - Wholesale Rates: Wholesale transmission revenues are based on formula rates that are approved by the FERC. Most of NU’s wholesale transmission revenues, including CL&P's, are collected under the New England Independent System Operator (ISO-NE) FERC Electric Tariff No. 3, Transmission, Markets and Services Tariff (Tariff No. 3). Tariff No. 3 includes Regional Network Service (RNS) and Local Network Service (LNS) rate schedules to recover transmission and other services. The RNS rate, administered by ISO-NE and billed to all New England transmission users is reset on June 1^st of each year and recovers the revenue requirements associated with transmission facilities that benefit the New England region. The LNS rate, administered by NU, is reset on January 1^st and June 1^st of each year and recovers the revenue requirements for local transmission facilities and other transmission costs not recovered under the RNS rate, including 50 percent of the CWIP that is included in rate base on the remaining three southwest Connecticut projects (Middletown-Norwalk, Glenbrook Cables and Long Island Replacement Cable). The LNS rate calculation recovers total transmission revenue requirements net of revenues received from other sources (i.e., RNS, rentals, etc.), thereby ensuring that NU recovers all regional and local revenue requirements as prescribed in Tariff No. 3. Both the RNS and LNS rates provide for annual true-ups to actual costs. The financial impacts of differences between actual and projected costs are deferred for future recovery from or refund to retail customers. At December 31, 2007, the LNS rates for CL&P’s transmission segment were in an underrecovery position of approximately $18 million, which will be recovered from LNS customers in mid-2008. CL&P believes that these rates will provide it with timely recovery of transmission costs, including costs of its major transmission projects.

Transmission Revenues - Retail Rates: A significant portion of the NU transmission segment revenue comes from ISO-NE charges to the distribution segments of CL&P and other NU companies, which recover these costs through the rates charged to their retail customers. CL&P has a retail transmission cost tracking mechanism as part of its rates. This tracking mechanism allows CL&P to charge its retail customers for transmission charges on a timely basis.

Derivative Accounting

The accounting treatment for energy contracts entered into varies and depends on the intended use of the particular contract and on whether or not the contract is a derivative. Non-derivative contracts are recorded at the time of delivery or settlement.

The application of derivative accounting under SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," 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, could have a significant impact on CL&P’s consolidated financial statements.

The fair value of derivatives is based upon the contract terms and conditions and the underlying market price or fair value per unit. When quantities are not specified in the contract, the company determines whether it is a derivative by using amounts referenced in default provisions and other relevant sections of the contract. The estimated quantities to be served are updated during the term of the contract, and such updates can have a material impact on mark-to-market amounts.

The judgment applied in the election of the normal purchases and sales exception (and resulting accrual accounting) includes the conclusion that it is probable at the inception of the contract and throughout its term that it will result in physical delivery and that the quantities will be used or sold by the business over a reasonable period in the normal course of business. If facts and circumstances change and management can no longer support this conclusion, then the normal exception and accrual accounting is terminated and fair value accounting is applied.

Contracts that are hedging an underlying transaction and that qualify as derivatives that hedge exposure to the variable cash flows of a forecasted transaction (cash flow hedges) are recorded on the consolidated balance sheets at fair value with changes in fair value reflected in accumulated other comprehensive income. Cash flow hedges include forward interest rate swap agreements on proposed debt issuances. When a cash flow hedge is settled, the settlement amount is recorded in accumulated other comprehensive income and is amortized into earnings over the term of the debt. In addition, cash flow hedges impact earnings when hedge ineffectiveness is measured and recorded or when the forecasted transaction being hedged is no longer probable of occurring.

Emerging Issues Task Force (EITF) Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,” prohibits recording the initial gains and losses on derivative contracts if their estimated fair values are based on significant non-observable inputs. Based upon the significance of non-observable capacity prices to their valuation, the estimated initial fair values of CL&P’s contracts for differences (CfDs) are not recorded on the balance sheet as of December 31, 2007.

For further information regarding CL&P's derivative contracts, and their accounting, see Note 3, "Derivative Instruments," to the consolidated financial statements.

Regulatory Accounting

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

The transmission and distribution segments of CL&P continue to be cost-of-service, rate regulated. Management believes that the application of SFAS No. 71 to those segments continues to be appropriate. Management also believes it is probable that CL&P will recover its investments in long-lived assets, including regulatory assets. All material net regulatory assets are earning an equity return, except for securitized regulatory assets and the majority of deferred benefit costs, which are not supported by equity. Amortization and deferrals of regulatory assets/(liabilities) are included on a net basis in amortization expense on the accompanying consolidated statements of income.

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


	At December 31,
(Millions of Dollars)	2007		2006
Securitized assets	$	548.2	$	707.2
Income taxes, net		279.4		266.6
Unrecovered contractual obligations		148.0		163.7
Regulatory assets offsetting derivative liabilities		119.8		36.0
CTA and SBC undercollections		90.6		100.5
Deferred benefit costs		72.2		155.8
Other regulatory assets		71.8		47.6
Totals	$	1,330.0	$	1,477.4

Additionally, CL&P had $11.9 million and $11.1 million of regulatory costs at December 31, 2007 and 2006, respectively, that were included in deferred debits and other assets - other on the accompanying consolidated balance sheets. These amounts represent regulatory costs that have not yet been approved for recovery by the DPUC. Management believes these costs are recoverable in future cost-of-service, regulated rates.

Securitized Assets: In March of 2001, CL&P issued $1.4 billion in rate reduction certificates. CL&P used $1.1 billion of the proceeds from that issuance to buyout or buydown certain contracts with independent power producers (IPP). The unamortized CL&P securitized asset balance was $468.6 million and $604.5 million at December 31, 2007 and 2006, respectively. CL&P used the remaining proceeds from the issuance of the rate reduction certificates to securitize a portion of its SFAS No. 109, "Accounting for Income Taxes," regulatory asset. The securitized SFAS No. 109 regulatory asset had an unamortized balance of $79.6 million and $102.7 million at December 31, 2007 and 2006, respectively.

Securitized regulatory assets, which are not earning an equity return, are being recovered over the amortization period of their associated rate reduction certificates. All outstanding CL&P rate reduction certificates are scheduled to fully amortize by December 30, 2010.

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, including those differences relating to uncertain tax positions) is accounted for in accordance with the rate-making treatment of the DPUC, SFAS No. 109 and FASB Interpretation No. (FIN) 48, "Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109." Differences in income taxes between SFAS No. 109, FIN 48 and the rate-making treatment of the DPUC are recorded as regulatory assets which totaled $279.4 million and $266.6 million at December 31, 2007 and 2006, respectively. For further information regarding income taxes, see Note 1G, "Summary of Significant Accounting Policies - Income Taxes," to the consolidated financial statements.

Unrecovered Contractual Obligations: Under the terms of contracts with the Connecticut Yankee Atomic Power Company (CYAPC), Yankee Atomic Electric Company (YAEC), and Maine Yankee Atomic Power Company (MYAPC) (Yankee Companies), CL&P is responsible for its proportionate share of the remaining costs of the units, including decommissioning. A portion of these amounts, $148 million and $163.7 million at December 31, 2007 and 2006, respectively, were recorded as unrecovered contractual obligations regulatory assets. A portion of these obligations was securitized in 2001 and was included in securitized regulatory assets.

Regulatory Assets Offsetting Derivative Liabilities: The regulatory assets offsetting derivative liabilities relate to the fair value of contracts used to purchase power and other related contracts that will be collected from customers in the future. These amounts totaled $119.8 million and $36 million at December 31, 2007 and 2006, respectively. See Note 3, "Derivative Instruments," for further information. This asset is excluded from rate base.

CTA and SBC Undercollections: The Competitive Transition Assessment (CTA) allows CL&P to recover stranded costs, such as securitization costs associated with the rate reduction bonds, amortization of regulatory assets, and IPP over market costs. The System Benefits Charge (SBC) allows CL&P to recover certain regulatory and energy public policy costs, such as public education outreach costs, hardship protection costs, transition period property taxes and displaced workers protection costs. At December 31, 2007 and 2006, CTA undercollections totaled $54 million and $75.5 million, respectively. At December 31, 2007 and 2006, SBC undercollections totaled $36.6 million and $25 million, respectively.

Deferred Benefit Costs: On December 31, 2006, the company implemented SFAS No. 158, "Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans." SFAS No. 158 applies to NU’s Pension Plan, Supplemental Executive Retirement Plan (SERP), and postretirement benefits other than pension (PBOP) Plan and requires an additional benefit liability to be recorded with an offset to accumulated other comprehensive income in shareholders' equity which is remeasured annually. However, because CL&P is a cost-of-service, rate regulated entity under SFAS No. 71, offsets were recorded as a regulatory asset of $72.2 million at December 31, 2007 and $155.8 million at December 31, 2006 as these amounts have been and continue to be recoverable in cost-of-service, regulated rates. Regulatory accounting was also applied to the portions of the NUSCO costs that support CL&P, as these amounts are also recoverable. The deferred benefit costs are not in rate base.

Other Regulatory Assets: Included in other regulatory assets are the regulatory assets associated with the implementation of FIN 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143," totaling $22.2 million and $25.8 million at December 31, 2007 and 2006, respectively. Management believes that recovery of these regulatory assets is probable.

At December 31, 2007 and 2006, other regulatory assets also include $15.4 million and $17.1 million, respectively, related to losses on reacquired debt, $10.4 million for the year ended December 31, 2007 related to the write-off of uncollectible hardship receivables and $23.8 million and $4.7 million, respectively, related to various other items.

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


	At December 31,
(Millions of Dollars)	2007		2006
Regulatory liabilities offsetting derivative assets	$	313.0	$	294.5
GSC and FMCC overcollections		119.2		108.2
Cost of removal		116.6		134.4
Other regulatory liabilities		52.7		45.7
Totals	$	601.5	$	582.8

Regulatory Liabilities Offsetting Derivative Assets: The regulatory liabilities offsetting derivative assets relate to the fair value of contracts used to purchase power and other related contracts that will benefit customers in the future. These amounts totaled $313 million and $294.5 million at December 31, 2007 and 2006, respectively. See Note 3, "Derivative Instruments," for further information. This liability is excluded from rate base.

GSC and FMCC Overcollections: The Generation Service Charge (GSC) allows CL&P to recover the costs of the procurement of energy for standard service, which includes forward capacity market charges. The Federally Mandated Congestion Charges (FMCC) mechanism allows CL&P to recover the costs of power market rules by the FERC, including Reliability Must Run costs. At December 31, 2007 and 2006, GSC and FMCC overcollections totaled $119.2 million and $108.2 million, respectively.

Cost of Removal: CL&P currently recovers amounts in rates for future costs of removal of plant assets. These amounts, which totaled $116.6 million and $134.4 million at December 31, 2007 and 2006, respectively, are classified as regulatory liabilities on the accompanying consolidated balance sheets. This liability is included in rate base.

Other Regulatory Liabilities: Other regulatory liabilities included a $17.9 million liability at December 31, 2006 related to transmission refunds to be provided to customers as a result of the FERC ROE decision, $21.4 million and $6.6 million for the years ended December 31, 2007 and 2006, respectively, related to a 50 percent reserve for allowance for funds used during construction (AFUDC) currently recovered in rate base as a result of FERC approved transmission incentives, and $31.3 million and $21.2 million related to various other items at December 31, 2007 and 2006, respectively.

Income Taxes

The tax effect of temporary differences is accounted for in accordance with the rate-making treatment of the DPUC, SFAS No. 109 and FIN 48. Details of income tax expense/(benefit) are as follows:


	For the Years Ended December 31,
	2007		2006		2005
	(Millions of Dollars)
The components of the federal and state income tax provisions are:

Current income taxes:
Federal	$	36.3	$	104.9	$	44.7
State		(10.0)		3.8		4.1
Total current		26.3		108.7		48.8
Deferred income taxes, net:
Federal		23.5		(69.2)		(1.8)
State		5.2		(21.5)		(12.2)
Total deferred		28.7		(90.7)		(14.0)
Investment tax credits, net		(2.6)		(62.0)		(2.6)
Income tax expense/(benefit)	$	52.4	$	(44.0)	$	32.2

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


	For the Years Ended December 31,
	2007			2006		2005
	(Millions of Dollars, except percentages)
Income before income tax expense/(benefit)	$	185.9		$	156.0	$	127.0

Expected federal income tax expense		65.1			54.6		44.5
Tax effect of differences:
Depreciation		(6.6)			(1.8)		(3.9)
Investment tax credit amortization (including $59.3 million related to the PLR in 2006)		(2.6)			(62.0)		(2.6)
State income taxes, net of federal impact		(11.9)			(7.4)		(5.3)
Excess deferred income taxes - PLR		-			(14.7)		-
Deferred tax adjustment - sale to affiliate		-			(4.4)		-
Tax asset valuation reserve adjustment		9.8			(3.8)		-
Medicare subsidy		(1.8)			(2.2)		(2.4)
Other, net		0.4			(2.3)		1.9
Income tax expense/(benefit)	$	52.4		$	(44.0)	$	32.2
Effective tax rate		28.2	%		*		25.4	%

*Not meaningful.

NU and its subsidiaries, including CL&P, file a consolidated federal income tax return and file state income tax returns. These entities are also parties to a tax allocation agreement under which taxable subsidiaries do not pay any more taxes than they would have otherwise paid had they filed a separate company tax return, and subsidiaries generating tax losses, if any, are paid for their losses when utilized.

In 2000, CL&P requested from the Internal Revenue Service (IRS) a Private Letter Ruling (PLR) regarding the treatment of unamortized investment tax credits (UITC) and excess deferred income taxes (EDIT) related to generation assets that were sold. In 2006, the IRS issued a PLR in response to CL&P's request for a ruling, which held that it would be a violation of tax regulations if the EDIT or UITC are used to reduce customers' rates following the sale of the generation assets. CL&P's UITC and EDIT balances related to generation assets that have been sold totaled $59 million and $15 million, respectively, and $74 million combined. Later in 2006, the DPUC determined that the UITC and EDIT amounts were no longer required to be held in their existing accounts. As a result of this determination, the $74 million balance was reflected as a reduction to CL&P's 2006 income tax expense with an increase to CL&P's earnings by the same amount.

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)	2007		2006

Deferred tax liabilities - current:
Property tax accruals	$	35.3	$	27.1
Derivative asset		21.8		17.9
Total deferred tax liabilities - current		57.1		45.0
Deferred tax assets - current:
Allowance for uncollectible accounts		14.6		15.9
Other		1.7		1.6
Total deferred tax assets - current		16.3		17.5
Net deferred tax liabilities - current		40.8		27.5
Deferred tax liabilities - long-term:
Accelerated depreciation and other plant-related differences		546.8		529.6
Employee benefits		133.2		94.5
Regulatory amounts:
Securitized contract termination costs		28.2		36.6
Other regulatory deferrals		70.8		101.9
Income tax gross-up		161.3		168.4
Derivative assets		111.1		99.5
Other		16.0		20.2
Total deferred tax liabilities - long-term		1,067.4		1,050.7
Deferred tax assets - long-term:
Regulatory deferrals		168.5		194.9
Employee benefits		63.6		64.7
Income tax gross-up		18.2		21.3
Derivative liability		54.2		12.7
Other		64.1		37.6
Total deferred tax assets - long-term		368.6		331.2
Net deferred tax liabilities - long-term		698.8		719.5
Net deferred tax liabilities	$	739.6	$	747.0

At December 31, 2007, CL&P had state tax credit carry forwards of $38 million that expire by 2012. At December 31, 2006, CL&P had state tax credit carry forwards of $11.7 million that expire by 2011.

Effective on January 1, 2007, CL&P implemented FIN 48. FIN 48 applies to all income tax positions previously filed in a tax return and income tax positions expected to be taken in a future tax return that have been reflected on the balance sheets. FIN 48 addresses the methodology to be used prospectively in recognizing, measuring and classifying the amounts associated with income tax positions that are deemed to be uncertain, including related interest and penalties. Previously, CL&P recorded estimates for uncertain tax positions in accordance with SFAS No. 5, "Accounting for Contingencies."

As a result of implementing FIN 48, CL&P recognized a cumulative effect of a change in accounting principle of $24 million as a reduction to the January 1, 2007 balance of retained earnings. Refer to the accompanying consolidated quarterly financial data (unaudited) that discusses a correction in the company’s initial adoption of FIN 48.

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

Interest on uncertain tax positions is recorded and classified as a component of other interest expense. CL&P recorded accrued interest expense of $8.7 million, which is included in the cumulative effect of a change in accounting principle, as of January 1, 2007. For the year ended December 31, 2007, CL&P recorded interest expense of $2.3 million. At December 31, 2007, $11 million of accrued interest expense was recognized on the accompanying consolidated balance sheet.

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

Unrecognized Tax Benefits: Upon adoption of FIN 48 on January 1, 2007, CL&P had unrecognized tax benefits totaling $62.6 million, of which $39.7 million would impact the effective tax rate, if recognized. As of December 31, 2007, CL&P’s unrecognized tax benefits totaled $75.9 million, of which $62.3 million would impact the effective tax rate, if recognized.

A reconciliation of the activity in unrecognized tax benefits from January 1, 2007 to December 31, 2007 is as follows:


(Millions of Dollars)
Balance at beginning of year	$	62.6
Gross increases - current year		23.5
Gross decreases - prior year		10.2
Balance at end of year	$	75.9

Tax Positions: NU is currently working to resolve all open tax years. It is reasonably possible that one or more of these open tax years could be resolved within the next twelve months. Management estimates that potential resolutions could result in a zero to $12 million decrease in unrecognized tax benefits by CL&P. This estimated change is primarily related to the timing of deducting expenses for book versus tax purposes, which is not expected to have a material impact on earnings.

Tax Years: The following table summarizes CL&P’s tax years that remain subject to examination by major tax jurisdictions at December 31, 2007:


Description		Tax Years
Federal (NU consolidated)		2002 - 2007
Connecticut		1997 - 2007

Property, Plant and Equipment and Depreciation

The following table summarizes CL&P's investments in utility plant at December 31, 2007 and 2006 and the average depreciable life at December 31, 2007:


			At December 31,
	Average Depreciable Life		2007		2006
	(Years)		(Millions of Dollars)
Distribution		28.7	$	3,559.3	$	3,458.3
Transmission		46.1		1,339.8		1,098.9
Total property, plant and equipment				4,899.1		4,557.2
Less: Accumulated depreciation				(1,279.7)		(1,260.5)
Net property, plant and equipment				3,619.4		3,296.7
Construction work in progress				782.4		337.7
Total property, plant and equipment, net			$	4,401.8	$	3,634.4

The provision for depreciation on utility assets is calculated using the straight-line method based on the estimated remaining useful lives of depreciable plant in-service, adjusted for salvage value and removal costs, as approved by the DPUC. Depreciation rates are applied to plant-in-service from the time it is placed in service. When a plant is retired from service, the original cost of the plant is charged to the accumulated provision for depreciation which includes cost of removal less salvage. Cost of removal is classified as a regulatory liability. The depreciation rates for the several classes of utility plant-in-service are equivalent to a composite rate of 3.3 percent in 2007, and 3.5 percent in 2006 and 2005.

Equity Method Investments

At December 31, 2007, CL&P owned common stock in three regional nuclear companies (Yankee Companies). Each of the Yankee Companies owned a single nuclear generating plant which has been decommissioned. CL&P’s ownership interests in the Yankee Companies at December 31, 2007, which are accounted for on the equity method, were 34.5 percent of CYAPC, 24.5 percent of YAEC and 12 percent of MYAPC. The total carrying value of CL&P’s ownership interest in CYAPC, MYAPC and YAEC, which is included in deferred debits and other assets - other on the accompanying consolidated balance sheets and the distribution reportable segment, totaled $4.6 million and $6.6 million at December 31, 2007 and 2006, respectively. Earnings related to these equity investments are included in other income, net on the accompanying consolidated statements of income. For further information, see Note 1P, "Summary of Significant Accounting Policies - Other Income, Net," to the consolidated financial statements.

For further information, see Note 5E, "Commitments and Contingencies - Deferred Contractual Obligations," to the consolidated financial statements.

Allowance for Funds Used During Construction

AFUDC is included in the cost of CL&P's 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 AFUDC related to equity funds is recorded as other income on the consolidated statements of income.


	For the Years Ended December 31,
(Millions of Dollars, except percentages)	2007			2006			2005
AFUDC:
Borrowed funds	$	10.9		$	6.6		$	6.7
Equity funds		14.2			7.6			9.8
Totals	$	25.1		$	14.2		$	16.5
Average AFUDC rate		8.0	%		7.9	%		7.9	%

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

Sale of Customer Receivables

CRC, a consolidated, wholly-owned subsidiary of CL&P, is permitted to sell up to $100 million of an undivided interest in CL&P's accounts receivable and unbilled receivables to a financial institution. At December 31, 2007, there were $20 million in sales. At December 31, 2006, there were no such sales.

At December 31, 2007 and 2006, amounts sold to CRC by CL&P but not sold to the financial institution totaling $308.2 million and $375.7 million, respectively, were 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 3, 2007, CL&P extended the bank commitment under the Receivables Purchase and Sale Agreement with CRC and the financial institution through June 30, 2008 and extended the facility termination date to June 21, 2012. 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."

Asset Retirement Obligations

CL&P implemented FIN 47 on December 31, 2005. FIN 47 requires an entity to recognize a liability for the fair value of an asset retirement obligation (ARO) on the obligation date if the liability's fair value can be reasonably estimated and is conditional on a future event. FIN 47 provides that settlement dates and future costs should be reasonably estimated when sufficient information becomes available and provides guidance on the definition and timing of sufficient information in determining expected cash flows and fair values. Management has identified various categories of AROs, primarily certain assets containing asbestos and hazardous contamination. A fair value calculation, reflecting expected probabilities for settlement scenarios, has been performed.

Because it is a cost-of-service, rate regulated entity, CL&P applies regulatory accounting in accordance with SFAS No. 71, and the costs associated with CL&P’s AROs were included in other regulatory assets at December 31, 2007 and 2006.

The fair value of the AROs was recorded as a liability in deferred credits and other liabilities – other with an offset included in property, plant and equipment on the accompanying consolidated balance sheets. The ARO assets are depreciated, and the ARO liabilities are accreted over the estimated life of the obligation with corresponding credits recorded as accumulated depreciation and ARO liabilities, respectively. Both the depreciation and accretion were recorded as increases to regulatory assets on the accompanying consolidated balance sheets at December 31, 2007 and 2006.

The following tables present the ARO asset, the related accumulated depreciation, the regulatory asset, and the ARO liabilities at December 31, 2007 and 2006:


	At December 31, 2007
(Millions of Dollars)	ARO Asset		Accumulated Depreciation of ARO Asset		Regulatory Asset		ARO Liabilities
Asbestos	$	1.6	$	(1.0)	$	11.2	$	(11.8)
Hazardous contamination		3.5		(0.9)		7.6		(10.2)
Other AROs		5.7		(2.5)		3.4		(6.6)
Total AROs	$	10.8	$	(4.4)	$	22.2	$	(28.6)


	At December 31, 2006
(Millions of Dollars)	ARO Asset		Accumulated Depreciation of ARO Asset		Regulatory Asset		ARO Liabilities
Asbestos	$	2.3	$	(1.3)	$	10.8	$	(11.8)
Hazardous contamination		4.9		(1.2)		8.5		(12.2)
Other AROs		10.4		(5.1)		6.5		(11.8)
Total AROs	$	17.6	$	(7.6)	$	25.8	$	(35.8)

A reconciliation of the beginning and ending carrying amounts of CL&P’s AROs is as follows:


(Millions of Dollars)		2007		2006
Balance at beginning of year	$	(35.8)	$	(35.9)
Liabilities incurred during the period		(2.8)		(4.7)
Liabilities settled during the period		7.1		1.6
Accretion		(0.8)		(0.2)
Change in estimates		4.2		1.7
Revisions in estimated cash flows		(0.5)		1.7
Balance at end of year	$	(28.6)	$	(35.8)

Changes in estimates and revisions in estimated cash flows supporting the carrying amounts of AROs include changes in estimated quantities and removal costs, discount rates and inflation rates.

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.

Special Deposits

CL&P had amounts on deposit related to a special purpose entity used to facilitate the issuance of rate reduction certificates. These amounts totaled $14.4 million and $70.1 million at December 31, 2007 and 2006, respectively. In addition, the company had $5.8 million and $6.5 million in other cash deposits held with unaffiliated parties at December 31, 2007 and 2006, respectively, primarily related to CL&P's transmission projects. These amounts are included in deferred debits and other assets - other on the accompanying consolidated balance sheets.

Other Taxes

Certain excise taxes levied by state or local governments are collected by CL&P 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, 2007, 2006 and 2005, gross receipts taxes, franchise taxes and other excise taxes of $95 million, $92.7 million and $88.2 million, respectively, were included in operating revenues and taxes other than income taxes on the accompanying consolidated statements of income. Certain sales taxes are also collected by CL&P from its customers as the agent for state and local governments and are recorded on a net basis with no impact on the accompanying consolidated statements of income.

Other Income, Net

The pre-tax components of CL&P's other income/(loss) items are as follows:


	For the Years Ended December 31,
(Millions of Dollars)	2007		2006		2005
Other Income:
AFUDC - equity funds	$	14.2	$	7.6	$	9.8
Energy Independence Act incentives		9.9		5.5		-
Investment income		7.7		9.8		10.8
Conservation and load management incentives		5.5		4.2		4.4
Procurement fee		-		11.0		17.8
Equity in earnings of regional nuclear generating companies		1.9		(0.9)		1.2
Rental investment revenue		0.7		0.7		1.1
Total Other Income		39.9		37.9		45.1
Other Loss:
Rental investment expenses		(0.1)		(0.1)		(0.1)
Total Other Loss		(0.1)		(0.1)		(0.1)
Total Other Income, Net	$	39.8	$	37.8	$	45.0

The Energy Independence Act incentives relate to incentives earned under the Act to encourage regulated companies to construct distributed generation, new large-scale generation and implement conservation and load management initiatives to reduce FMCC charges.

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

Equity in earnings of regional nuclear generating companies relates to CL&P's investment in the Yankee Companies.

Provision for Uncollectible Accounts

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

In November of 2006, the DPUC issued an order allowing CL&P to accelerate the recovery of uncollectible hardship accounts receivable outstanding for greater than 90 days. At December 31, 2007, CL&P had uncollectible hardship accounts receivable reserves in the amount of $24 million. At December 31, 2006, these amounts totaled $17 million. CL&P recorded regulatory assets for the unamortized portion as these amounts are probable of recovery. Prior to the order, any write-offs of these amounts were deferred for recovery at the time of write-off. The CL&P reserve offsets amounts sold to CRC by CL&P but not sold to the financial institution, which are classified as investments in securitizable assets on the accompanying consolidated balance sheets.

Short-Term Debt

Limits: The amount of short-term borrowings that may be incurred by CL&P is subject to periodic approval by either the FERC or the DPUC. On December 12, 2007, the FERC granted authorization to allow CL&P to incur total short-term borrowings up to a maximum of $450 million, effective from December 31, 2007, through December 31, 2009.

The charter of CL&P contains preferred stock provisions restricting the amount of unsecured debt that CL&P may incur. In November of 2003, CL&P obtained authorization from its preferred stockholders for a ten-year period expiring in March of 2014 to issue unsecured indebtedness with a maturity of less than 10 years in excess of the 10 percent of total capitalization limitation in CL&P's charter, provided that all unsecured indebtedness would not exceed 20 percent of total capitalization. On March 18, 2004, the SEC approved this change in CL&P's charter. As of December 31, 2007, CL&P was permitted to incur $765.7 million of additional unsecured debt under this provision.

Credit Agreement: CL&P is a party, along with other NU subsidiaries, to a five-year unsecured revolving credit facility which expires on November 6, 2010. CL&P may draw up to $200 million under this facility on a short-term basis or long-term basis, subject to regulatory approvals. At December 31, 2007 and 2006, CL&P had no borrowings outstanding under this facility.

Pool: CL&P is a member of the NU Money Pool (Pool). The Pool provides a more efficient use of cash resources of NU and reduces outside short-term borrowings. NUSCO administers the Pool as agent for the member companies. Short-term borrowing needs of the member companies are first met with available funds of other member companies, including funds borrowed by NU. NU may lend to the Pool but may not borrow. Funds may be withdrawn from or repaid to the Pool at any time without prior notice. Investing and borrowing subsidiaries receive or pay interest based on the average daily federal funds rate. Borrowings based on loans from NU, however, bear interest at NU's cost and must be repaid based upon the terms of NU's original borrowing. At December 31, 2007 and

2006, CL&P had borrowings of $38.8 million and $258.9 million from the Pool, respectively. The weighted average interest rate on borrowings from the Pool for the years ended December 31, 2007 and 2006 was 5.04 percent and 4.97 percent, respectively.

Derivative Instruments

Supply/Stranded Costs: CL&P has contracts with two IPPs to purchase power that contain pricing provisions that are not clearly and closely related to the price of power and therefore do not qualify for the normal purchases and sales exception. The fair values of these derivatives at December 31, 2007 included a derivative asset with a fair value of $311.2 million and a derivative liability with a fair value of $31.8 million. 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 cost-of-service, regulated rates. At December 31, 2006, the fair values of these derivatives included a derivative asset with a fair value of $289.6 million and a derivative liability with a fair value of $35.6 million.

CL&P has entered into Financial Transmission Rights contracts and bilateral basis swaps to limit the congestion costs associated with its standard offer contracts. An offsetting regulatory asset or liability has been recorded as management believes that these costs will be recovered or refunded in rates. At December 31, 2007, the fair value of these derivative contracts was recorded as a derivative asset of $1.4 million and a derivative liability of $1.3 million on the accompanying consolidated balance sheets. At December 31, 2006, the fair value of those derivative contracts was recorded as a derivative asset of $4.9 million and a derivative liability of $0.4 million on the accompanying consolidated balance sheets.

Pursuant to Public Act 05-01, "An Act Concerning Energy Independence," in August of 2007 the DPUC approved two CL&P contracts associated with the capacity of two generating projects to be built or modified. The DPUC also approved two capacity-related contracts entered into by The United Illuminating Company (UI), one with a generating project to be built and one with a new demand response project. The total capacity of these four projects is expected to be approximately 787 megawatts (MW). The contracts, referred to as CfDs, obligate the utilities' customers to pay the difference between a set capacity price and the value that the projects receive in the ISO-NE capacity markets for periods of up to 15 years beginning in 2009. CL&P has an agreement with UI under which it will share the costs and benefits of these four CfDs, with 80 percent to CL&P and 20 percent to UI. The ultimate cost to CL&P under the derivative contracts will depend on the capacity prices that the projects receive in the ISO-NE capacity markets. Due to the significance of the non-observable capacity prices associated with modeling the fair values of these derivative contracts, their initial negative fair values at inception of approximately $100 million have not been reflected in the accompanying consolidated financial statements. At December 31, 2007, the changes in fair value of these CfDs since inception are recorded as a $107.1 million derivative liability on the consolidated balance sheet. A derivative asset of $20.8 million has been recorded to reflect UI’s 20 percent share of these amounts and the change in fair value of one of the CfD contracts. An offsetting regulatory asset and liability for the remaining 80 percent of the changes in fair value of the contracts since inception has been recorded as management believes these amounts will be recovered or refunded in cost-of-service, regulated rates. On October 5, 2007, NRG Energy, Inc. (NRG) filed in New Britain Superior Court an appeal of the DPUC's decision selecting the CfDs. This appeal was taken into consideration in valuing the CfDs and had the effect of reducing the net negative derivative values by approximately $215 million at December 31, 2007. On February 13, 2008, the New Britain Superior Court judge denied NRG's appeal. The effect of this denial will be reflected as an increase in negative derivative values in the first quarter of 2008.

Interest Rate Hedging: In December of 2007, CL&P entered into two forward interest rate swap agreements to hedge the interest cash outflows associated with two proposed debt issuances of $150 million each in November of 2008. The interest rate swaps are based on a 10-year LIBOR swap rate and match the index used for the debt issuances. As cash flow hedges, at December 31, 2007, the fair value of these hedges was recorded as a $2.3 million derivative asset on the consolidated balance sheet with an offsetting amount, net of tax, included in accumulated other comprehensive income.

Employee Benefits

Pension Benefits and Postretirement Benefits Other Than Pensions

On December 31, 2006, CL&P implemented SFAS No. 158, which applies to NU’s Pension Plan, SERP, and PBOP Plan and required CL&P to record the funded status of these plans based on the projected benefit obligation for the Pension Plan and accumulated postretirement benefit obligation (APBO) for the PBOP Plan on the consolidated balance sheets at December 31, 2007 and 2006. SFAS No. 158 requires the additional liability to be recorded with an offset to accumulated other comprehensive income in shareholders' equity. This amount is remeasured annually, or as circumstances dictate. However, because CL&P is a cost-of-service, rate regulated entity under SFAS No. 71, regulatory assets were recorded in the amount of $72.2 million and $155.8 million at December 31, 2007 and 2006, respectively, as these benefits expense amounts have been and continue to be recoverable in cost-of-service, regulated rates. Regulatory accounting was also applied to the portions of the NUSCO costs that support CL&P, as these amounts are also recoverable.

Pension Benefits: CL&P participates in a uniform non-contributory defined benefit retirement plan (Pension Plan) covering substantially all regular CL&P employees. Benefits are based on years of service and the employees’ highest eligible compensation during 60 consecutive months of employment. CL&P uses a December 31^st measurement date for the Pension Plan. Pension (income)/expense affecting earnings is as follows:


	For the Years Ended December 31,
(Millions of Dollars)	2007		2006		2005
Total pension (income)/expense	$	(15.6)	$	0.3	$	3.0
Income/(expense) capitalized as utility plant		7.3		0.1		(1.5)
Total pension (income)/expense, net of amounts capitalized	$	(8.3)	$	0.4	$	1.5

Total pension (income)/expense above includes pension curtailments and termination benefits of $2.1 million in 2006 and expense of $3.6 million in 2005, respectively. No pension curtailments and termination benefits were recorded in 2007.

Pension Curtailments and Termination Benefits: In December of 2005, a new program was approved allowing then current employees to elect to receive retirement benefits under a new 401(k) benefit rather than under the Pension Plan. The approval of the new plan resulted in recording an estimated pre-capitalization, pre-tax curtailment expense of $1.3 million in 2005, as a certain number of employees were expected to elect the new 401(k) benefit, resulting in a reduction in aggregate estimated future years of service under the Pension Plan. Because the predicted level of elections of the new benefit did not occur, CL&P recorded a pre-capitalization, pre-tax reduction in the curtailment expense of $0.8 million in 2006.

As a result of its corporate reorganization in 2005, CL&P recorded a combined pre-capitalization, pre-tax curtailment expense and related termination benefits for the Pension Plan totaling $2.3 million. Based on a revised estimate of expected headcount reduction in 2006, CL&P recorded an adjustment to the curtailment and related termination benefits. This adjustment resulted in a pre-capitalization, pre-tax reduction in the curtailment expense of $0.5 million and a reduction in termination benefits expense of $0.8 million totaling a net $1.3 million reduction to pension expense.

Pension Plan COLA: On May 4, 2007, NU's Board of Trustees approved a cost of living adjustment (COLA) that increased retiree pension benefits for certain participants in the Pension Plan. The COLA was announced on May 8, 2007 at the annual meeting of NU's shareholders, which resulted in a plan amendment in 2007 and a remeasurement of the Pension Plan's benefit obligation as of May 8, 2007.

The COLA increased CL&P's Pension Plan benefit obligation by $17.1 million and was reflected as a prior service cost and as a decrease in the funded status of the Pension Plan. This amount will be amortized over a 12-year period representing average remaining service lives of employees.

Market-Related Value of Pension Plan Assets: CL&P 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 and are included in actuarial gains and losses. Since the market-related valuation calculation recognizes gains or losses over a four-year period, the future value of the market-related assets will be impacted as previously deferred gains or losses are recognized.

SERP: NU has maintained a SERP since 1987. The SERP provides its eligible participants, some of which are officers of CL&P, 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.

PBOP: CL&P provides certain health care benefits, primarily medical and dental, and life insurance benefits through a PBOP Plan. These benefits are available for employees retiring from CL&P 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. CL&P uses a December 31^st measurement date for the PBOP Plan.

CL&P annually funds postretirement costs through external trusts with amounts that have been and will continue to be recovered in rates and that are tax deductible. Currently, there are no pending regulatory actions regarding postretirement benefit costs.

PBOP Curtailments and Termination Benefits: CL&P recorded an estimated $2.5 million pre-tax curtailment expense at December 31, 2005 relating to its corporate reorganization. CL&P also accrued a $0.2 million pre-tax termination benefit expense at December 31, 2005 relating to certain benefits provided under the terms of the PBOP Plan. Based on refinements to its estimates, CL&P recorded an adjustment to the curtailment and related termination benefits in 2006. This adjustment resulted in a combined pre-capitalization, pre-tax reduction in the curtailment expense and termination benefits of $1.5 million in 2006. There were no curtailments or termination benefits recorded in 2007.

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


	At December 31,
	Pension Benefits				SERP Benefits				Postretirement Benefits
(Millions of Dollars)	2007		2006		2007		2006		2007		2006
Change in benefit obligation
Benefit obligation at beginning of year	$	(860.5)	$	(859.3)	$	(2.6)	$	(2.6)	$	(187.1)	$	(200.7)
Service cost		(16.2)		(17.0)		-		(0.1)		(2.3)		(2.9)
Interest cost		(48.8)		(47.9)		(0.1)		(0.1)		(10.2)		(11.1)
Transfers		-		-		-		-		(0.3)		3.4
Actuarial gain/(loss)		80.7		21.6		0.2		0.1		(1.6)		9.5
Prior service cost		(17.1)		-		-		-		-		-
Federal subsidy on benefits paid		-		-		-		-		(1.4)		(1.3)
Benefits paid - excluding lump sum payments		52.4		49.6		0.1		0.1		18.0		16.1
Curtailment/impact of plan changes		-		(8.3)		-		-		-		(0.1)
Termination benefits		-		0.8		-		-		-		-
Benefit obligation at end of year	$	(809.5)	$	(860.5)	$	(2.4)	$	(2.6)	$	(184.9)	$	(187.1)
Change in plan assets
Fair value of plan assets at beginning of year	$	1,103.7	$	990.7		N/A		N/A	$	101.3	$	85.1
Actual return on plan assets		93.0		162.5		N/A		N/A		5.9		12.7
Employer contribution		-		-		N/A		N/A		16.9		21.5
Transfers		-		-		N/A		N/A		0.2		(1.9)
Benefits paid - excluding lump sum payments		(52.4)		(49.6)		N/A		N/A		(18.0)		(16.1)
Fair value of plan assets at end of year	$	1,144.3	$	1,103.6	$	N/A	$	N/A	$	106.3	$	101.3
Funded status at December 31^st	$	334.8	$	243.1	$	(2.4)	$	(2.6)	$	(78.6)	$	(85.8)

The amounts recognized on the accompanying consolidated balance sheets for the funded status above at December 31, 2007 and 2006 is as follows:


	At December 31,
	Pension Benefits				SERP Benefits				Postretirement Benefits
(Millions of Dollars)	2007		2006		2007		2006		2007		2006
Prepaid pension	$	334.8	$	243.1	$	-	$	-	$	-	$	-
Other current liabilities		-		-		(0.1)		(0.1)		-		-
Other deferred credits and other liabilities		-		-		(2.3)		(2.5)		-		-
Accrued postretirement benefits		-		-		-		-		(78.6)		(85.8)

In 2005, as a result of the expected transition of employees into the new 401(k) benefit and the company's corporate reorganization, NU reduced CL&P’s share of the Pension Plan’s obligation via a curtailment benefit related to the reduction in the future years of service expected to be rendered by plan participants. This overall reduction in plan obligation served to reduce the previously unrecognized actuarial losses. In 2006, $8.3 million of this curtailment was reversed because actual levels of elections of the new 401(k) benefit were much lower than expected and is reflected above as an increase to the obligation.

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

Although the SERP does not have any plan assets, benefit payments are supported by earnings on marketable securities held by NU.

The accumulated benefit obligation for the Pension Plan was $723.2 million and $771.1 million at December 31, 2007 and 2006, respectively, and $2.2 million and $2.4 million for the SERP at December 31, 2007 and 2006, respectively.

The following is a summary of amounts recorded as regulatory assets as a result of SFAS No. 158 at December 31, 2007 and 2006 and the changes in those amounts recorded during the years (millions of dollars):


	At December 31,
	Pension				SERP				PBOP
	2007		2006		2007		2006		2007			2006
Transition obligation at beginning of year	$	-	$	-	$	-	$	-	$	36.7	$		-
Amounts recorded upon adoption of SFAS No. 158		-		-		-		-		-			36.7
Amounts reclassified as net periodic benefit expense		-		-		-		-		(6.1)			-
Transition obligation at end of year	$	-	$	-	$	-	$	-	$	30.6	$		36.7

Prior service cost at beginning of year	$	16.4	$	-	$	0.2	$	-	$	-	$		-
Amounts reclassified as net periodic benefit expense		(3.8)		-		(0.1)		-		-			-
Prior service cost arising during the year (1)		17.1		16.4		-		0.2		-			-
Prior service cost at end of year	$	29.7	$	16.4	$	0.1	$	0.2	$	-	$		-

Net actuarial losses at beginning of year	$	55.7	$	-	$	1.0	$	-	$	45.8	$		-
Amounts reclassified as net periodic benefit expense		(6.3)		-		(0.1)		-		(4.7)			-
Actuarial (gains)/losses arising during the year (1)		(83.1)		55.7		(0.2)		1.0		3.7			45.8
Actuarial (gains)/losses at end of year	$	(33.7)	$	55.7	$	0.7	$	1.0	$	44.8	$		45.8

Total deferred benefit costs as regulatory assets	$	(4.0)		72.1	$	0.8	$	1.2	$	75.4	$		82.5

(1)

Amounts arising for prior service cost and actuarial (gains)/losses in 2006 relate to the initial adoption of SFAS No. 158.

The estimates of the above amounts that are expected to be recognized as portions of net periodic benefit expense in 2008 are as follows (millions of dollars):


	Estimated Expense in 2008
	Pension		SERP		PBOP
Transition obligation	$	-	$	-	$	6.1
Prior service cost		4.3		-		-
Net actuarial loss		1.3		0.1		4.4
Total	$	5.6	$	0.1	$	10.5

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


	At December 31,
	Pension and SERP Benefits				Postretirement Benefits
Balance Sheets	2007		2006		2007		2006
Discount rate	6.60	%	5.90	%	6.35	%	5.80	%
Compensation/progression rate	4.00	%	4.00	%	N/A		N/A
Health care cost trend rate	N/A		N/A		8.50	%	9.00	%

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


	For the Years Ended December 31,
	Pension Benefits						SERP Benefits						Postretirement Benefits
(Millions of Dollars)	2007		2006		2005		2007		2006		2005		2007		2006			2005
Service cost	$	16.2	$	17.0	$	17.2	$	-	$	0.1	$	-	$	2.3	$	2.9	$	2.8
Interest cost		48.8		47.9		46.8		0.1		0.1		0.1		10.2		11.1		10.2
Expected return on plan assets		(90.7)		(81.2)		(80.1)		-		-		-		(7.2)		(5.6)		(4.9)
Net transition obligation cost		-		-		-		-		-		-		6.1		6.1		6.3
Prior service cost		3.8		2.8		3.0		0.1		-		-		-		-		-
Actuarial loss		6.3		15.9		12.5		0.1		0.1		0.1		4.7		7.1		7.1
Net periodic (income)/expense - before curtailments and termination (benefits)/expense		(15.6)		2.4		(0.6)		0.3		0.3		0.2		16.1		21.6		21.5
Curtailment (benefits)/expense		-		(1.3)		2.3		-		-		-		-		(1.4)		2.5
Termination (benefits)/expense		-		(0.8)		1.3		-		-		-		-		(0.1)		0.2
Total curtailments and termination (benefits)/expense		-		(2.1)		3.6		-		-		-		-		(1.5)		2.7
Total - net periodic (income)/expense	$	(15.6)	$	0.3	$	3.0	$	0.3	$	0.3	$	0.2	$	16.1	$	20.1	$	24.2

Not included in the pension (income)/expense amounts above are pension related intercompany allocations totaling $9.3 million, $10.3 million, and $8.8 million for the years ended December 31, 2007, 2006 and 2005, respectively, including curtailment and termination benefits income of $1.5 million and expense of $2.4 million for the years ended December 31, 2006 and 2005, respectively. Excluded from postretirement benefits expense are related intercompany allocations of $7.4 million, $7.6 million and $7.9 million for the years ended December 31, 2007, 2006, and 2005, respectively, including curtailments and termination benefits of $0.3 million and expense of $0.7 million, for the years ended December 31, 2006 and 2005, respectively. Excluded from SERP expenses are related intercompany allocations of $1.9 million, $2 million and $1.9 million for the years ended December 31, 2007, 2006 and 2005, respectively. These amounts are included in other operating expenses on the accompanying consolidated statements of income.

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


	For the Years Ended December 31,
Statements of Income	Pension Benefits and SERP							Postretirement Benefits
	2007			2006		2005		2007		2006		2005
Discount rate	5.95	%	(1)	5.80	%	6.00	%	5.80	%	5.65	%	5.50	%
Expected long-term rate of return	8.75	%		8.75	%	8.75	%	N/A		N/A		N/A
Compensation/progression rate	4.00	%		4.00	%	4.00	%	N/A		N/A		N/A
Expected long-term rate of return -
Health assets, net of tax	N/A			N/A		N/A		6.85	%	6.85	%	6.85	%
Life assets and non-taxable health assets	N/A			N/A		N/A		8.75	%	8.75	%	8.75	%

(1) The 2007 discount rate for the SERP was 5.9 percent.

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,
	2007		2006
Health care cost trend rate assumed for next year	8.50	%	9.00	%
Rate to which health care cost trend rate is assumed to decline (the ultimate trend rate)	5.00	%	5.00	%
Year that the rate reaches the ultimate trend rate	2015		2011

At December 31, 2007, the health care cost trend assumption was reset for 2008 at 8.5 percent, decreasing one-half percentage point per year to an ultimate rate of 5 percent in 2015.

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


(Millions of Dollars)	One Percentage Point Increase	One Percentage Point Decrease
Effect on total service and interest cost components	$0.4	$(0.3)
Effect on postretirement benefit obligation	$5.5	$(4.8)

NU's investment strategy for its Pension Plan and PBOP Plan is to maximize the long-term rate of return on those plans' assets within an acceptable level of risk. The investment strategy establishes target allocations, which are routinely reviewed and periodically rebalanced. NU's expected long-term rates of return on Pension Plan assets and PBOP Plan assets are based on these target asset allocation assumptions and related expected long-term rates of return. In developing its expected long-term rate of return assumptions for the Pension Plan and the PBOP Plan, NU also evaluated input from actuaries and consultants, as well as long-term inflation assumptions and NU's historical 25-year compounded return of approximately 11.8 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
	2007		2006		2007 and 2006
	Target Asset Allocation	Assumed Rate of Return	Target Asset Allocation	Assumed Rate of Return	Target Asset Allocation	Assumed Rate of Return
Equity Securities:
United States	40%	9.25%	45%	9.25%	55%	9.25%
Non-United States	17%	9.25%	14%	9.25%	11%	9.25%
Emerging markets	5%	10.25%	3%	10.25%	2%	10.25%
Private	8%	14.25%	8%	14.25%	-	-
Debt Securities:
Fixed income	25%	5.50%	20%	5.50%	27%	5.50%
High yield fixed income	-	-	5%	7.50%	5%	7.50%
Real Estate	5%	7.50%	5%	7.50%	-	-

The actual asset allocations at December 31, 2007 and 2006 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	2007	2006	2007	2006
Equity Securities:
United States	40%	46%	55%	54%
Non-United States	17%	16%	14%	14%
Emerging markets	5%	4%	1%	1%
Private	7%	5%	-	-
Debt Securities:
Fixed income	26%	19%	29%	29%
High yield fixed income	-	5%	1%	2%
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/(received) for the Pension, SERP and PBOP Plans:


(Millions of Dollars)	Pension Benefits		SERP Benefits		Postretirement Benefits		Government Benefits
2008	$	53.4		0.1		18.9		(1.7)
2009		54.8		0.1		19.1		(1.8)
2010		55.7		0.1		19.1		(1.9)
2011		56.5		0.1		19.0		(2.0)
2012		57.5		0.2		18.9		(2.2)
2013-2017		305.1		1.0		90.9		(12.4)

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

Contributions: Currently, CL&P’s policy is to annually fund the Pension Plan an amount at least equal to that which will satisfy the requirements of the Employee Retirement Income Security Act and Internal Revenue Code. CL&P does not expect to make any contributions to the Pension Plan in 2008. For the PBOP plan, it is currently CL&P's policy to annually fund an amount equal to the PBOP Plan's postretirement benefit cost, excluding curtailment and termination benefits. CL&P contributed $15.8 million for the year ended December 31, 2007 to fund the PBOP Plan and expects to make $15.7 million in contributions to the PBOP Plan in 2008. Beginning in 2007, CL&P made an additional contribution to the PBOP Plan for the amounts received from the federal Medicare subsidy. This amount was $1.1 million in 2007 and is estimated to be $1.8 million in 2008.

Defined Contribution Plans

NU maintains a 401(k) Savings Plan for substantially all CL&P employees. This savings plan provides for employee contributions up to specified limits. NU matches employee contributions up to a maximum of three percent of eligible compensation with one percent in cash and two percent in NU common shares. The 401(k) matching contributions of cash and NU common shares made by NU to CL&P employees were $3.6 million in both 2007 and 2006 and $3.7 million in 2005.

Effective on January 1, 2006, all newly hired and non-bargaining unit employees of CL&P participate in a new defined contribution savings plan called the K-Vantage benefit. These employees are not eligible to participate in the existing defined benefit Pension Plan. In addition, participants in the Pension Plan at January 1, 2006 were given the opportunity to choose to become a participant in the K-Vantage benefit beginning in 2007, in which case their benefit under the Pension Plan would be frozen. NU makes contributions to the K-Vantage benefit based on a percentage of participants' eligible compensation, as defined by the benefit document. The contributions made by NU to CL&P employees were approximately $71 thousand in 2007 and $6 thousand in 2006.

Share-Based Payments

NU maintains an Employee Share Purchase Plan (ESPP) and other long-term equity-based incentive plans under the Northeast Utilities Incentive Plan (Incentive Plan) in which CL&P employees and officers are entitled to participate. CL&P records compensation cost related to these plans, as applicable, for shares issued or sold to CL&P employees and officers, as well as the allocation of costs associated with shares issued or sold to NUSCO employees and officers that support CL&P. In the first quarter of 2006, NU adopted SFAS No. 123(R), "Share-Based Payments," under the modified prospective method. Adoption of SFAS No. 123(R) had an immaterial effect on CL&P's net income.

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

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

For grants of restricted shares and restricted share units (RSUs), NU records compensation expense over the vesting period based upon the fair value of NU's common shares at the date of grant but records this expense net of estimated forfeitures.

Dividend equivalents on RSUs are charged to retained earnings, net of estimated forfeitures.

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

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

Incentive Plan: Under the Incentive Plan in which CL&P participates, NU is authorized to grant up to 4.5 million new shares for various types of awards, including restricted shares, RSUs, performance units, and stock options to eligible employees and board members. At December 31, 2007 and 2006, NU had 3,055,083 and 570,494 common shares, respectively, available for issuance under the Incentive Plan.

Restricted Shares and RSUs: NU has granted restricted shares under the 2002 through 2004 incentive programs that are subject to three-year and four-year graded vesting schedules. NU has granted RSUs under the 2004 through 2007 incentive programs that are subject to three-year and four-year graded vesting schedules. RSUs are paid in shares, including amounts sufficient to satisfy withholdings, subsequent to vesting. A summary of total NU restricted share and RSU transactions for the year ended December 31, 2007 is as follows:


Restricted Shares	Restricted Shares	Weighted Average Grant - Date Fair Value	Total Grant - Date Fair Value (Millions)	Remaining Compensation Cost (Millions)	Weighted Average Remaining Period (Years)
Outstanding at December 31, 2006	65,674	$15.00
Granted	-	-
Vested	(59,424)	$14.14	$0.8
Outstanding at December 31, 2007	6,250	$18.65	$0.1	$ -	0.2

The per share and total weighted average grant date fair value for restricted shares vested was $14.52 and $1.1 million, respectively, for the year ended December 31, 2006 and $14.60 and $1.4 million, respectively, for the year ended December 31, 2005.

The total compensation cost recognized by CL&P for its portion of the restricted shares above was approximately $39 thousand, net of taxes of approximately $26 thousand for the year ended December 31, 2007 and $0.3 million, net of taxes of $0.2 million for the years ended December 31, 2006 and 2005.


RSUs	RSUs (Units)	Weighted Average Grant - Date Fair Value	Total Grant - Date Fair Value (Millions)	Remaining Compensation Cost (Millions)	Weighted Average Remaining Period (Years)
Outstanding at December 31, 2006	715,299	$19.41
Granted	330,785	$28.83	$ 9.5
Issued	(161,137)	$19.77	$ 3.2
Forfeited	(53,947)	$20.16	$ 1.1
Outstanding at December 31, 2007	831,000	$22.99	$19.1	$7.7	1.8

The per share and total weighted average grant date fair value for RSUs granted was $19.87 and $7.4 million, respectively, for the year ended December 31, 2006 and $18.89 and $5.8 million, respectively, for the year ended December 31, 2005. The weighted average grant date fair value per share for RSUs issued was $18.50 and $19.06 for the years ended December 31, 2006 and 2005, respectively. The total weighted average fair value of RSUs issued was $2.2 million and $1.9 million for the years ended December 31, 2006 and 2005, respectively.

The compensation cost recognized by CL&P for its portion of the RSUs above was $2.3 million, net of taxes of $1.5 million for the year ended December 31, 2007, $1.6 million, net of taxes of $1 million for the year ended 2006 and $0.8 million, net of taxes of $0.5 million for the year ended December 31, 2005.

Stock Options: Prior to 2003, NU granted stock options to certain CL&P employees. These options were fully vested as of December 31, 2005, and no compensation expense was recorded as a result of the adoption of SFAS No. 123(R). The fair value of each stock option grant was estimated on the date of grant using the Black-Scholes option pricing model.

Commitments and Contingencies

Regulatory Developments and Rate Matters

Procurement Fee Rate Proceedings: CL&P was allowed to collect a fixed procurement fee of 0.50 mills per kilowatt-hour (KWH) from customers that purchased TSO service from 2004 through the end of 2006. One mill is equal to one tenth of a cent. That fee could increase to 0.75 mills per KWH if CL&P outperforms certain regional benchmarks. CL&P submitted to the DPUC its proposed methodology to calculate the variable incentive portion of the procurement fee and requested approval of $5.8 million in incentive fees. On December 8, 2005, a draft decision was issued in this docket, which accepted the methodology as proposed by CL&P and authorized payment of the pre-tax $5.8 million incentive fee. On October 19, 2007, the DPUC released a recommendation prepared by its consultant relative to statistical adjustments to the incentive calculations. The DPUC has set a new schedule allowing for rebuttal of the consultant’s report. The new schedule calls for a draft decision in this docket to be issued on March 7, 2008. Management continues to believe that final regulatory approval of the $5.8 million pre tax amount, which was reflected in 2005 earnings, is probable.

Environmental Matters

General: CL&P 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, CL&P 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 when assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated. The approach used estimates the liability based on the most likely action plan from a variety of available remediation options including no action 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, the extent of CL&P's responsibility or the extent of remediation required, 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 if reasonably estimable, and take into consideration site assessment and remediation costs. Based on currently available information for estimated site assessment and remediation costs at December 31, 2007 and 2006, CL&P had $2.9 million and $2.8 million, respectively, recorded as environmental reserves. A reconciliation of the activity in these reserves at December 31, 2007 and 2006 is as follows:


	For the Years Ended December 31,
(Millions of Dollars)	2007		2006
Balance at beginning of year	$	2.8	$	2.7
Additions and adjustments		0.6		0.2
Payments and adjustments		(0.5)		(0.1)
Balance at end of year	$	2.9	$	2.8

Of the 13 sites CL&P has currently included in the environmental reserve, four sites are in the remediation or long-term monitoring phase, eight sites have had some level of site assessment completed, and one site is in the preliminary phase of site assessment.

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

At December 31, 2007, in addition to the 13 sites, there were five sites for which there are unasserted claims; however, any related site assessment or remediation costs are not probable or estimable at this time. CL&P'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: Manufactured gas plant (MGP) sites comprise the largest portion of CL&P's environmental liability. MGPs are sites that manufactured gas from coal which produced certain byproducts that may pose a risk to human health and the environment. At both December 31, 2007 and 2006, $1.5 million represents the amount for the site assessment and remediation of MGPs.

For the three of the 13 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 the company to estimate the range of losses for environmental costs. At December 31, 2007, $1.8 million had 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 $1.6 million to $6 million. For the ten remaining sites included in the environmental reserve, determining an estimated range of loss is not possible at this time.

CERCLA Matters: The federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA) and amendments or state equivalents impose joint and several strict liabilities, regardless of fault, upon generators of hazardous substances resulting in removal and remediation costs and environmental damages. Liabilities under these laws can be material and in some instances may be imposed without regard to fault or for past acts that may have been lawful at the time they occurred. Of the 13 sites, two are superfund sites under CERCLA for which CL&P has been notified that it is a potentially responsible party (PRP) but for which the site assessment and remediation are not being managed by CL&P. At December 31, 2007, a liability of $0.4 million accrued on these sites of represents CL&P’s estimate of its potential remediation costs with respect to these two superfund sites.

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.

Environmental Rate Recovery: 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.

Spent Nuclear Fuel Disposal Costs

Under the Nuclear Waste Policy Act of 1982, CL&P must pay the United States Department of Energy (DOE) for the costs of disposal of spent nuclear fuel and high-level radioactive waste for the period prior to the sale of its ownership in the Millstone nuclear power stations.

The DOE is responsible for the selection and development of repositories for, and the disposal of, spent nuclear fuel and high-level radioactive waste. For nuclear fuel used to generate electricity prior to April 7, 1983 (Prior Period Spent Nuclear Fuel), CL&P has recorded an accrual for the full liability, and payment must be made by CL&P to the DOE prior to the first delivery of spent fuel to the DOE. After the sale of Millstone, CL&P remained responsible for its share of the disposal costs associated with the Prior Period Spent Nuclear Fuel. Until such payment to the DOE is made, the outstanding liability will continue to accrue interest at the 3-month treasury bill yield rate. At December 31, 2007 and 2006, fees due to the DOE for the disposal of Prior Period Spent Nuclear Fuel are included in long-term debt and were $238.7 million and $227.5 million, respectively, including accumulated interest costs of $172.2 million and $160.9 million, respectively.

Long-Term Contractual Arrangements

Estimated Future Annual Costs: The estimated future annual costs of CL&P’s significant long-term contractual arrangements at December 31, 2007 are as follows:


(Millions of Dollars)	2008		2009		2010		2011		2012		Thereafter		Totals
VYNPC	$	16.6	$	18.1	$	17.3	$	17.7	$	4.3	$	-	$	74.0
Supply/stranded cost contracts		202.2		176.3		154.0		190.4		217.6		1,301.5		2,242.0
Renewable energy contract		-		-		2.5		15.0		15.0		192.4		224.9
Hydro-Quebec		12.3		12.2		12.1		12.2		12.2		97.9		158.9
Transmission segment project commitments		529.2		52.4		100.6		278.6		264.2		108.6		1,333.6
Yankee Companies billings		23.0		19.3		20.6		18.4		18.4		53.0		152.7
Totals	$	783.3	$	278.3	$	307.1	$	532.3	$	531.7	$	1,753.4	$	4,186.1

VYNPC: CL&P has commitments to buy approximately 9.5 percent of the Vermont Yankee Nuclear Power Corporation (VYNPC) plant’s output through March of 2012 at a range of fixed prices. The total cost of purchases under contracts with VYNPC amounted to
$15.2 million in 2007, $19.1 million in 2006 and $15.3 million in 2005.

Supply/Stranded Cost Contracts: CL&P has entered into various IPP contracts that extend through 2024 for the purchase of electricity, including payment obligations resulting from the buydown of electricity purchase contracts. The total cost of purchases and obligations under these contracts amounted to $206 million in 2007, $206.1 million in 2006 and $148 million in 2005. The majority of the contracts expire by 2014.

In addition, CL&P and UI have entered into four CfDs for a total of approximately 787 MW of capacity with three generation projects to be built or modified and one new demand response project. The CfDs extend through 2026 and obligate the utilities to pay the difference between a set capacity price and the value that the projects receive in the ISO-NE capacity markets. The contracts have terms of up to 15 years beginning in 2009 and are subject to a sharing agreement with UI whereby UI will share 20 percent of the costs and benefits of these contracts. The amount of CL&P's portion of the costs and benefits of these contracts included in the above table is subject to changes in capacity prices that the projects receive in the ISO-NE capacity markets and will be paid by or refunded to CL&P's customers.

These amounts do not include contractual commitments related to CL&P’s standard or TSO service.

Renewable Energy Contract: CL&P has entered into an agreement to purchase energy, capacity and renewable energy credits from a biomass energy plant yet to be built. The contract, beginning in 2010, is an operating lease for a 15 year period with no minimum lease payments. Amounts payable under this contract are subject to a sharing agreement with UI whereby UI will share 20 percent of the costs and benefits of this contract. CL&P’s portion of the costs and benefits of this contract will be paid by or refunded to CL&P’s customers.

Hydro-Quebec: Along with other New England utilities, CL&P have entered into an agreement to support transmission and terminal facilities which were built to import electricity from the Hydro-Quebec system in Canada. CL&P is obligated to pay, over a 30-year period ending in 2020, its proportionate share of the annual O&M expenses and capital costs of those facilities. The total cost of this agreement amounted to $10.8 million in 2007, $11.7 million in 2006 and $12 million in 2005.

Transmission Segment Project Commitments: These amounts primarily represent commitments for various services and materials associated with CL&P's Middletown to Norwalk, Glenbrook Cables and Norwalk to Northport-Long Island, New York projects and other projects, including the New England East-West 115 kilovolt (KV) and 345 KV Overhead projects.

Yankee Companies Billings: CL&P has significant decommissioning and plant closure cost obligations to the Yankee Companies. Each Yankee Company has completed the physical decommissioning of its facility and is now engaged in the long-term storage of its spent fuel. The Yankee Companies collect decommissioning and closure costs through wholesale, FERC-approved rates charged under power purchase agreements with several New England utilities, including CL&P. CL&P in turn recovers these costs from its customers through DPUC-approved retail rates. The table of estimated future annual costs includes the estimated decommissioning and closure costs for CYAPC, MYAPC and YAEC.

See Note 5E, "Commitments and Contingencies - Deferred Contractual Obligations," to the consolidated financial statements for information regarding the collection of the Yankee Companies' decommissioning costs.

Deferred Contractual Obligations

CL&P has significant decommissioning and plant closure cost obligations to the Yankee Companies, which have completed the physical decommissioning of all three of their facilities and are now engaged in the long-term storage of their spent fuel. The Yankee Companies collect decommissioning and closure costs through wholesale, FERC-approved rates charged under power purchase agreements with several New England utilities, including CL&P. CL&P in turn recovers these costs through DPUC-approved retail rates. CL&P's ownership interest in the Yankee Companies is 34.5 percent of CYAPC, 24.5 percent of YAEC, and 12 percent of MYAPC.

CL&P’s percentage share of the obligation to support the Yankee Companies under FERC-approved rate tariffs is the same as the ownership percentages above.

CYAPC: Under the terms of the settlement agreement between CYAPC, the DPUC, the Connecticut Office of Consumer Counsel and Maine Regulators, the parties agreed to a revised decommissioning estimate of $642.9 million (in 2006 dollars). Annual collections began in January of 2007, and were reduced from the $93 million originally requested for years 2007 through 2010 to lower levels ranging from $37 million in 2007 rising to $46 million in 2015. The reduction to annual collections was achieved by extending the collection period by 5 years through 2015 by reflecting the proceeds from a settlement agreement with Bechtel Power Corporation, by reducing collections in 2007, 2008 and 2009 by $5 million per year, and making other adjustments. Management believes CL&P will recover its share of this obligation from its customers.

YAEC: On July 31, 2006, the FERC approved a settlement agreement with the DPUC, the Massachusetts Attorney General and the Vermont Department of Public Service previously filed by YAEC. This settlement agreement did not materially affect the level of 2006 charges. Under the settlement agreement, YAEC agreed to reduce its November 2005 decommissioning cost increase from $85 million to $79 million. Other terms of the settlement agreement include extending the collection period for charges through December 2014, reconciling and adjusting future charges based on actual decontamination and decommissioning expenses. Management believes that CL&P’s $19.4 million share of the increase in decommissioning costs will ultimately be recovered from its customers.

MYAPC: MYAPC is collecting revenues from CL&P and other owners that are adequate to recover the remaining cost of decommissioning its plant, and management expects to recover CL&P’s respective share of such costs from its customers.

Spent Nuclear Fuel Litigation: In 1998, CYAPC, YAEC and MYAPC filed separate complaints against the DOE in the Court of Federal Claims seeking monetary damages resulting from the DOE's failure to begin accepting spent nuclear fuel for disposal by January 31, 1998 pursuant to the terms of the 1983 spent fuel and high level waste disposal contracts between the Yankee Companies and the DOE. In a ruling released on October 4, 2006, the Court of Federal Claims held that the DOE was liable for damages to CYAPC for $34.2 million through 2001, YAEC for $32.9 million through 2001 and MYAPC for $75.8 million through 2002. The Yankee Companies had claimed actual damages for the same periods as follows: CYAPC: $37.7 million; YAEC: $60.8 million; and MYAPC: $78.1 million. Most of the reduction in the claimed actual damages related to disallowed spent nuclear fuel pool operating expenses.

In December of 2006, the DOE appealed the ruling, and the Yankee Companies filed a cross-appeal. The refund to CL&P of any damages that may be recovered from the DOE will be realized through the Yankee Companies' FERC-approved rate settlement agreements, subject to final determination of the FERC. The appeal is expected to be argued in 2008 with a decision from the Court of Appeals to follow.

CL&P’s aggregate share of these damages is $29 million. Management cannot at this time determine the timing or amount of any ultimate recovery from the DOE, through the Yankee Companies, on this matter. However, management does believe that any net settlement proceeds CL&P receives would be incorporated into FERC-approved recoveries, which would be passed on to its customers through reduced charges.

NRG Energy, Inc. Exposures

CL&P has entered into transactions with NRG Energy, Inc. (NRG) and certain of its subsidiaries. On May 14, 2003, NRG and certain subsidiaries of NRG filed voluntary bankruptcy petitions, and on December 5, 2003, NRG emerged from bankruptcy. CL&P's NRG-related exposures as a result of these transactions relate to 1) the refunding of approximately $28 million of congestion charges previously withheld from NRG prior to the implementation of standard market design (SMD) on March 1, 2003, and 2) the recovery of approximately $30.2 million of CL&P's station service billings from NRG, which is currently the subject of an arbitration.

On July 20, 2007, the United States District Court for the District of Connecticut issued a ruling granting CL&P's motion for summary judgment against NRG in the pre-SMD congestion litigation. In this decision, the court held that NRG was contractually obligated to pay for congestion charges imposed during the term of the October 29, 1999 standard offer service wholesale sales agreement between CL&P and NRG and found in favor of CL&P and against NRG on each of NRG's two counterclaims. NRG did not appeal the judgment and the matter is closed.

On January 8, 2008, CL&P and NRG filed a proposed confidential settlement with the DPUC, which would settle the pending dispute concerning the scope of NRG’s responsibility to pay for certain delivery service charges to CL&P. On January 28, 2008, the DPUC issued a final decision in CL&P’s rate case proceeding in which it also approved the settlement between CL&P and NRG. The payment that CL&P will receive from NRG under the settlement and the rate relief approved in the January 28, 2008 DPUC decision essentially reimburses CL&P for its net station service receivable from NRG. This settlement did not and will not have an adverse effect on CL&P's consolidated net income, financial position or cash flows for the years ended December 31, 2007 and 2008, respectively.

Guarantees

NU provides credit assurances on behalf of subsidiaries, including CL&P, in the form of guarantees and letters of credit (LOCs) in the normal course of business. At December 31, 2007, 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 on behalf of CL&P totaled $5.5 million. A majority of these guarantees do not have established expiration dates, and some guarantees have unlimited exposure to commodity price movements. Additionally, NU had $20 million of LOCs issued on behalf of CL&P at December 31, 2006, but did not have any LOCs issued on behalf of CL&P at December 31, 2007. CL&P has no guarantees of the performance of third parties.

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

Transmission Rate Matters and FERC Regulatory Issues

As a result of an order issued by the FERC on October 31, 2006 relating to incentives on new transmission facilities in New England (FERC ROE decision), CL&P recorded an estimated regulatory liability for refunds of $17.9 million as of December 31, 2006. In 2007, CL&P completed the customer refunds that were calculated in accordance with the compliance filing required by the FERC ROE decision, and refunded approximately $17 million to regional, local and localized transmission customers. The $0.9 million positive pre-tax difference ($0.5 million after-tax) between the estimated regulatory liability recorded and the actual amount refunded was recorded in 2007.

Pursuant to the October 31, 2006 FERC ROE decision, the New England transmission owners submitted a compliance filing that calculated the refund amounts for transmission customers for the February 1, 2005 to October 31, 2006 time period. Subsequently, on July 26, 2007, the FERC disagreed with the ROEs the transmission owners used in their refund calculations for the 15-month period between June 3, 2005 and September 3, 2006, rejected a portion of the compliance filing, and required another compliance filing within 30 days. On August 27, 2007, NU, on behalf of CL&P, and the other New England transmission owners submitted a revised compliance filing, which outlined the regional refund process to comply with the FERC’s July 26, 2007 order. In addition, the transmission owners filed a request for rehearing claiming that the FERC improperly set the floor for refunds based on the lower rates that the FERC approved in its October 31, 2006 order, rather than the last approved rates, for the period from June 3, 2005 to September 3, 2006. The FERC denied this request on January 17, 2008, and the transmission owners have until March 17, 2008 to appeal, if they so choose.

CL&P’s transmission segment refunded approximately $1.6 million of revenues and interest related to the July 26, 2007 order (approximately $1 million after-tax), which was recorded in 2007.

Other Litigation and Legal Proceedings

NU and its subsidiaries, including CL&P, are involved in other legal, tax and regulatory proceedings regarding matters arising in the ordinary course of business, some of which involve management’s best estimate of probable loss as defined by SFAS No. 5. The company records and discloses losses when these losses are probable and reasonably estimable in accordance with SFAS No. 5, discloses matters when losses are probable but not estimable, and expenses legal costs related to the defense of loss contingencies as incurred.

Fair Value of Financial Instruments

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

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


	At December 31, 2007
(Millions of Dollars)	Carrying Amount		Fair Value
Preferred stock not subject to mandatory redemption	$	116.2	$	88.2
Long-term debt -
First mortgage bonds		1,369.8		1,362.9
Other long-term debt		662.6		674.1
Rate reduction bonds		548.7		586.2


	At December 31, 2006
(Millions of Dollars)	Carrying Amount		Fair Value
Preferred stock not subject to mandatory redemption	$	116.2	$	92.4
Long-term debt -
First mortgage bonds		869.8		901.2
Other long-term debt		651.4		665.0
Rate reduction bonds		743.9		783.3

Other long-term debt includes $238.7 million and $227.5 million of fees and interest due for spent nuclear fuel disposal costs at December 31, 2007 and 2006, respectively.

Other Financial Instruments: The carrying value of other financial instruments included in current assets and current liabilities, including investments in securitizable assets, approximates their fair value due to the short-term nature of these instruments.

Leases

CL&P has entered into lease agreements, some of which are capital leases, for the use of data processing and office equipment, vehicles, and office space. In addition, CL&P incurs costs associated with leases entered into by NUSCO and RRR. These costs are included below in operating lease payments charged to expense and amounts capitalized as well as future operating lease payments from 2008 through 2012 and thereafter. The provisions of these lease agreements generally contain renewal options. Certain lease agreements contain contingent lease payments. The contingent lease payments are based on various factors, such as the commercial paper rate plus a credit spread or the consumer price index.

Capital lease rental payments were $2.5 million in 2007, $2.9 million in 2006 and $3 million in 2005. Interest included in capital lease rental payments was $1.8 million in 2007, $1.7 million in 2006 and $1.8 million in 2005. Capital lease asset amortization was $0.7 million in 2007 and 2006 and $0.6 million in 2005.

Operating lease rental payments charged to expense were $13.2 million in 2007, $17.3 million in 2006 and $14.3 million in 2005. The capitalized portion of operating lease payments was approximately $6.5 million for the year ended December 31, 2007 and $6.2 million for each of the years ended December 31, 2006 and 2005.

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, 2007 are as follows:


(Millions of Dollars)	Capital Leases		Operating Leases
2008	$	3.2		18.8
2009		3.5		17.2
2010		1.7		15.3
2011		1.7		12.0
2012		1.8		10.2
Thereafter		16.8		45.0
Future minimum lease payments		28.7	$	118.5
Less amount representing interest		(15.1)
Present value of future minimum lease payments	$	13.6

In 2007, CL&P entered into certain contracts for the purchase of energy that qualify as leases under EITF No. 01-8, "Determining Whether an Arrangement Contains a Lease." These contracts do not have minimum lease payments and therefore are not included in the table above. See Note 5D, "Commitments and Contingencies - Long-Term Contractual Arrangements," for further information regarding these contracts.

Dividend Restrictions

The Federal Power Act limits the payment of dividends by CL&P to its retained earnings balance and certain state statutes may impose additional limitations on CL&P. CL&P also has a revolving credit agreement that imposes a leverage restriction tied to its ratio of consolidated total debt to total capitalization.

Accumulated Other Comprehensive Income/(Loss)

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


(Millions of Dollars)	December 31, 2006		Current Period Change		December 31, 2007
Qualified cash flow hedging instruments	$	4.5	$	(4.8)	$	(0.3)
Unrealized gains on securities		0.1		-		0.1
Accumulated other comprehensive income/(loss)	$	4.6	$	(4.8)	$	(0.2)


(Millions of Dollars)	December 31, 2005		Current Period Change		December 31, 2006
Qualified cash flow hedging instruments	$	-	$	4.5	$	4.5
Unrealized gains on securities		0.1		-		0.1
Minimum SERP liability		(0.4)		0.4		-
Accumulated other comprehensive (loss)/income	$	(0.3)	$	4.9	$	4.6

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


(Millions of Dollars)	2007		2006		2005
Qualified cash flow hedging instruments	$	3.2	$	(3.1)	$	-
Unrealized gains on securities		-		-		-
Minimum SERP liability		-		(0.2)		(0.1)
Accumulated other comprehensive income/(loss)	$	3.2	$	(3.3)	$	(0.1)

The unrealized gains on securities above relate to $2.4 million and $2.2 million of SERP securities at December 31, 2007 and 2006, respectively. The fair value of these securities is included in prepayments and other on the accompanying consolidated balance sheets.

Fair value adjustments included in accumulated other comprehensive income/(loss) for CL&P's qualified cash flow hedging instruments are as follows:


	At December 31,
(Millions of Dollars, Net of Tax)	2007		2006
Balance at beginning of year	$	4.5	$	-
Hedged transactions recognized into earnings		0.1		(0.1)
Cash flow transactions entered into for period		(4.9)		4.6
Net change associated with hedging transactions		(4.8)		4.5
Total fair value adjustments included in accumulated other comprehensive income	$	(0.3)	$	4.5

For the years ended December 31, 2007 and 2006, $0.1 million in expense and $0.1 million in income, respectively, net of tax, was reclassified from accumulated other comprehensive income/(loss) into earnings in connection with the consummation of interest rate swap agreements and the amortization of existing interest rate hedges.

In December of 2007, CL&P entered into two forward interest rate swap agreements associated with its planned 2008 long-term debt issuances. As a result, a gain of $1.4 million, net of tax, was recorded in accumulated other comprehensive loss with a corresponding pre-tax offset to derivative assets for the fair value of the derivative instruments as of December 31, 2007. For further information, see Note 3, "Derivative Instruments," to the consolidated financial statements.

In July of 2007, CL&P entered into two forward interest rate swap agreements to hedge the interest rates associated with $50 million of its $100 million, 10-year fixed rate long-term debt issuance and with $50 million of its $100 million, 30-year fixed rate long-term debt issuance. Under the agreements, CL&P had a LIBOR swap rate of 5.718 percent for the 10-year hedge and 5.865 percent for the 30-year hedge, both based on the notional amounts of $50 million in long-term debt that was issued in July of 2007. On July 16, 2007, the hedge was settled and a net of tax charge of $4.7 million ($7.7 million pre-tax), was recorded in accumulated other comprehensive loss to be amortized into earnings over the terms of the long-term debt. In addition, a net of tax charge of $67 thousand ($110 thousand pre-tax) was recorded related to ineffectiveness incurred upon termination of the hedge.

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

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

It is estimated that a charge of $0.2 million will be reclassified from accumulated other comprehensive loss as a decrease to earnings over the next 12 months as a result of amortization of the interest rate swap agreements which have been settled. This amount will be impacted by the settlement of forward interest rate swap agreements.

10.

Preferred Stock Not Subject to Mandatory Redemption

CL&P’s charter authorizes it to issue up to 9 million shares of preferred stock ($50 par value per share) of which 2,324,000 shares were outstanding at December 31, 2007 and 2006. In addition, CL&P’s charter authorizes it to issue up to 8 million shares of Class A preferred stock ($25 par value per share). There were no Class A preferred shares outstanding at December 31, 2007 and 2006. The issuance of additional preferred shares would be subject to approval by the DPUC.

Preferred stockholders have liquidation rights equal to the par value for each class, which they would receive in preference to any distributions to any junior stock. Were there to be a shortfall, all preferred stockholders would share ratably in available liquidation assets. Details of preferred stock not subject to mandatory redemption are as follows (in millions except in redemption price and shares):


Description	December 31, 2007 Redemption Price	Shares Outstanding at December 31, 2007 and 2006	December 31,
Description	December 31, 2007 Redemption Price	Shares Outstanding at December 31, 2007 and 2006	2007		2006
$1.90 Series of 1947	$52.50	163,912	$	8.2	$	8.2
$2.00 Series of 1947	54.00	336,088		16.8		16.8
$2.04 Series of 1949	52.00	100,000		5.0		5.0
$2.20 Series of 1949	52.50	200,000		10.0		10.0
3.90% Series of 1949	50.50	160,000		8.0		8.0
$2.06 Series E of 1954	51.00	200,000		10.0		10.0
$2.09 Series F of 1955	51.00	100,000		5.0		5.0
4.50% Series of 1956	50.75	104,000		5.2		5.2
4.96% Series of 1958	50.50	100,000		5.0		5.0
4.50% Series of 1963	50.50	160,000		8.0		8.0
5.28% Series of 1967	51.43	200,000		10.0		10.0
$3.24 Series G of 1968	51.84	300,000		15.0		15.0
6.56% Series of 1968	51.44	200,000		10.0		10.0
Totals		2,324,000	$	116.2	$	116.2

Dividends of $5.6 million were paid to the preferred stockholders in both 2007 and 2006.

11.

Long-Term Debt

Details of long-term debt outstanding are as follows:


At December 31,	2007		2006
	(Millions of Dollars)
First Mortgage Bonds:
7.875% 1994 Series D due 2024	$	139.8	$	139.8
4.800% 2004 Series A due 2014		150.0		150.0
5.750% 2005 Series B due 2034		130.0		130.0
5.000% 2005 Series A due 2015		100.0		100.0
5.625% 2005 Series B due 2035		100.0		100.0
6.350% 2006 Series A due 2036		250.0		250.0
5.375% 2007 Series A due 2017		150.0		-
5.750% 2007 Series B due 2037		150.0		-
5.750% 2007 Series C due 2017		100.0		-
6.375% 2007 Series D due 2037		100.0		-
Total First Mortgage Bonds		1,369.8		869.8
Pollution Control Notes:
5.85%-5.90%, fixed rate, due 2016-2022		46.4		46.4
5.85%-5.95%, fixed rate tax exempt, due 2028		315.5		315.5
Variable rate, tax exempt, due 2031		62.0		62.0
Total Pollution Control Notes		423.9		423.9
Total First Mortgage Bonds and Pollution Control Notes		1,793.7		1,293.7
Fees and interest due for spent nuclear fuel disposal costs		238.7		227.5
Less amounts due within one year		-		-
Unamortized premium and discount, net		(3.9)		(1.8)
Long-term debt	$	2,028.5	$	1,519.4

There are no cash sinking fund requirements or debt maturities for the years 2008 through 2012.

Essentially all utility plant of CL&P is subject to the liens of CL&P's first mortgage bond indenture.

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

CL&P has $62 million of tax-exempt PCRBs secured by bond insurance and first mortgage bonds. For financial reporting purposes, this debt is not considered to be first mortgage bonds unless CL&P fails to meet its obligations under the PCRBs. The CL&P pollution control note due in 2031 has an interest rate of 3.35 percent effective through October 1, 2008, at which time the bonds will be remarketed and the interest rate will be adjusted.

In 2007, CL&P issued $500 million of first mortgage bonds. The proceeds were used to refinance the company's short-term borrowings, which were previously incurred to fund transmission segment and distribution segment capital expenditures.

CL&P’s long-term debt agreements provide that it 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. CL&P currently is and expects to remain in compliance with these covenants.

For information regarding fees and interest due for spent nuclear fuel disposal costs, see Note 5C, "Commitments and Contingencies - Spent Nuclear Fuel Disposal Costs," to the consolidated financial statements.

12.

Segment Information

Segment information related to the distribution and transmission businesses for CL&P for the years ended December 31, 2007, 2006 and 2005 is as follows:


	For the Year Ended December 31, 2007
(Millions of Dollars)	Distribution		Transmission		Totals
Operating revenues (1)	$	3,452.8	$	229.0	$	3,681.8
Depreciation and amortization		(279.5)		(29.0)		(308.5)
Other operating expenses		(3,004.7)		(84.1)		(3,088.8)
Operating income		168.6		115.9		284.5
Interest expense, net of AFUDC		(108.1)		(30.3)		(138.4)
Interest income		3.0		2.5		5.5
Other income, net		22.6		11.8		34.4
Income tax expense		(20.7)		(31.7)		(52.4)
Net income	$	65.4	$	68.2	$	133.6
Total assets (2)	$	7,018.1	$	-	$	7,018.1
Cash flows for total investments in plant (3)	$	242.3	$	583.9	$	826.2


	For the Year Ended December 31, 2006
(Millions of Dollars)	Distribution		Transmission		Totals
Operating revenues (1)	$	3,825.2	$	154.6	$	3,979.8
Depreciation and amortization		(241.0)		(22.1)		(263.1)
Other operating expenses		(3,416.3)		(64.3)		(3,480.6)
Operating income		167.9		68.2		236.1
Interest expense, net of AFUDC		(100.5)		(17.4)		(117.9)
Interest income		6.6		0.4		7.0
Other income, net		24.6		6.2		30.8
Income tax benefit/(expense)		53.3		(9.3)		44.0
Net income	$	151.9	$	48.1	$	200.0
Total assets (2)	$	6,321.3	$	-	$	6,321.3
Cash flows for total investments in plant (3)	$	183.8	$	383.4	$	567.2


	For the Year Ended December 31, 2005
(Millions of Dollars)	Distribution		Transmission		Totals
Operating revenues (1)	$	3,353.7	$	112.7	$	3,466.4
Depreciation and amortization		(293.5)		(17.7)		(311.2)
Other operating expenses		(2,899.1)		(54.1)		(2,953.2)
Operating income		161.1		40.9		202.0
Interest expense, net of AFUDC		(108.5)		(11.5)		(120.0)
Interest income		2.9		0.4		3.3
Other income, net		34.8		6.9		41.7
Income tax expense		(26.2)		(6.0)		(32.2)
Net income	$	64.1	$	30.7	$	94.8
Cash flows for total investments in plant (3)	$	236.6	$	207.8	$	444.4

(1)

CL&P revenues are primarily derived from residential, commercial and industrial customers and are not dependent on any single customer.

(2)

Information for segmenting total assets between distribution and transmission is not available at December 31, 2007 and 2006. The distribution and transmission assets are disclosed in the distribution columns above.

(3)

Cash flows for total investments in plant included in the segment information above are cash capital expenditures that do not include amounts incurred but not paid, cost of removal, AFUDC, and the capitalized portion of pension expense or income.


Consolidated Quarterly Financial Data (Unaudited)
	Quarter Ended
(Thousands of Dollars)	March 31,		June 30,		September 30,		December 31,
2007
Operating Revenues	$	1,043,686	$	870,379	$	918,418	$	849,334
Operating Income		78,964		63,951		71,423		70,204
Net Income		34,994		25,786		34,976		37,808

2006
Operating Revenues	$	1,004,760	$	939,720	$	1,083,299	$	952,032
Operating Income		60,769		47,938		54,729		72,634
Net Income		33,830		17,472		101,033		47,672


Selected Consolidated Financial Data (Unaudited)
(Thousands of Dollars)	2007		2006		2005		2004		2003
Operating Revenues	$	3,681,817	$	3,979,811	$	3,466,420	$	2,832,924	$	2,704,524
Net Income		133,564		200,007		94,845		88,016		68,908
Dividends on Common Stock		79,181		63,732		53,834		47,074		60,110
Property, Plant and Equipment, net (a)		4,401,846		3,634,370		3,166,692		2,824,877		2,561,898
Total Assets		7,018,099		6,321,294		5,765,072		5,306,913		5,206,894
Rate Reduction Bonds		548,686		743,899		856,479		995,233		1,124,779
Long-Term Debt (b)		2,028,546		1,519,440		1,258,883		1,052,891		830,149
Preferred Stock - Non-Redeemable		116,200		116,200		116,200		116,200		116,200
Obligations Under Capital Leases (b)		13,602		14,264		13,488		14,093		14,879

(a)

Amount includes CWIP.

(b)

Includes portions due within one year, but excludes rate reduction bonds.

During the fourth quarter of 2007, CL&P determined that there was an error in certain assumptions supporting the initial FIN 48 adoption amounts recorded in the first quarter of 2007. The correction of the error resulted in the increase of the initial retained earnings reduction amount from $15.6 million to $24 million. This correction of the initial FIN 48 adoption accounting, which also affected certain liability balances reported in prior interim periods, did not have an effect on the income tax provision for 2007 and did not have a material impact on CL&P’s consolidated financial statements for the quarterly periods ending March 31, 2007, June 30, 2007 and September 30, 2007.


Selected Consolidated Sales Statistics (Unaudited)

	2007		2006		2005		2004		2003
Revenues: (Thousands)
Utility Group:
Residential	$	1,854,404	$	1,709,700	$	1,440,142	$	1,155,492	$	1,151,707
Commercial		1,182,196		1,405,281		1,170,038		939,579		960,678
Industrial		208,087		380,479		327,598		275,730		290,526
Other Utilities		347,514		318,958		344,650		295,833		322,955
Streetlighting and Railroads		35,370		42,099		37,054		31,897		35,358
Miscellaneous		54,246		123,294		146,938		134,393		(56,700)
Total	$	3,681,817	$	3,979,811	$	3,466,420	$	2,832,924	$	2,704,524
Sales: (KWH - Millions)
Residential		10,336		10,053		10,760		10,305		10,359
Commercial		10,128		9,995		10,307		9,922		9,829
Industrial		3,264		3,306		3,501		3,623		3,630
Other Utilities		3,563		3,749		4,179		5,375		5,885
Streetlighting and Railroads		304		284		298		298		298
Total		27,595		27,387		29,045		29,523		30,001
Customers: (Average)
Residential		1,091,799		1,084,937		1,078,723		1,071,249		1,058,247
Commercial		102,411		101,563		108,558		108,865		104,750
Industrial		3,743		3,848		3,976		4,078		3,989
Other		2,583		2,592		2,630		2,694		2,643
Total		1,200,536		1,192,940		1,193,887		1,186,886		1,169,629