CL&P 2005 Annual Report

EX-13.1 11 f2005clpedgar.htm CL&P 2005 Annual Report

Exhibit 13.1

Management’s Discussion and Analysis

Financial Condition and Business Analysis

Executive Summary

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

Results:

The Connecticut Light and Power Company (CL&P or the company) reported earnings of $94.8 million in 2005 compared to $88 million in 2004 and $68.9 million in 2003. Included in earnings were transmission earnings of $30.7 million, $19.8 million and $17.1 million in 2005, 2004 and 2003, respectively, and distribution earnings of $64.1 million, $68.2 million and $51.8 million in 2005, 2004 and 2003, respectively.

Legislative Items:

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

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

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provisions affecting CL&P. As part of this legislation, the Public Utility Holding Company Act of 1935 (PUHCA) was repealed.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

Regulatory Items:

CL&P has received regulatory approval to recover the increased cost of energy being supplied to its customers in 2006. This increased cost is primarily the result of increased fuel and purchased power costs.

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

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

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

Liquidity:

On April 7, 2005, CL&P closed on the sale of $100 million of 10-year first mortgage bonds and $100 million of 30-year first mortgage bonds.

In 2005, CL&P's capital expenditures totaled $444.4 million compared with $389.3 million in 2004. The increased level of capital expenditures was caused primarily by a need to continue to improve the capacity and reliability of CL&P's transmission system.

Cash flows from operations increased by $143.4 million to $297.3 million in 2005 from $153.9 million in 2004.

Overview

CL&P is a wholly owned subsidiary of Northeast Utilities (NU). NU’s other regulated electric subsidiaries include Public Service Company of New Hampshire (PSNH) and Western Massachusetts Electric Company (WMECO).

CL&P earned $94.8 million in 2005, compared with $88 million in 2004 and $68.9 million in 2003. The 2005 decline in CL&P’s distribution earnings to $64.1 million in 2005 from $68.2 million in 2004 resulted from the after-tax employee termination and benefit plan curtailment charges totaling $8.5 million, and higher operation, interest and depreciation expenses, partially offset by a $25 million distribution rate increase that took effect January 1, 2005 and a 3 percent increase in retail electric sales.

The 2005 increase in CL&P's transmission earnings to $30.7 million from $19.8 million in 2004, resulted primarily from increased investment in its transmission system. CL&P's retail electric sales were positively impacted by weather in 2005, particularly by an unseasonably hotter than average third quarter of 2005, which increased electricity consumption. CL&P's retail electric sales increased by only 0.1 percent over 2004 on a weather-adjusted basis.

With a commodity-driven increase taking effect early in 2006 and the weather being much milder to date in 2006, management is concerned that actual sales could be lower in 2006 than in 2005. While sales volume does not affect transmission business earnings positively or negatively, lower electric sales do negatively affect distribution company earnings.

Liquidity

Cash flows from operations increased by $143.4 million to $297.3 million in 2005 from $153.9 million in 2004. The increase in cash flows is primarily due to a decrease in regulatory refunds, an increase in accounts payable related to the timing of payments to standard offer suppliers and a decrease in tax payments.

Cash flows from operations decreased by $351.9 million from $505.8 million in 2003 to $153.9 million in 2004. The decrease in year over year operating cash flows is due to regulatory (refunds)/over-recoveries primarily due to lower CTA and generation service charge (GSC) collections in 2004 as CL&P refunds amounts to its ratepayers for past overcollections or uses those amounts to recover current costs. These refunds are also the primary reason for the positive change in year over year deferred income taxes, which has increased operating cash flows as refunded amounts were currently deducted for tax purposes. The change in lower current taxes paid because of income taxes also benefited cash flows from operations in 2004 due to bonus tax depreciation on newly completed plant assets.

On April 7, 2005, CL&P sold $100 million of 10-year first mortgage bonds carrying a coupon rate of 5.00 percent and $100 million of 30-year first mortgage bonds carrying a coupon rate of 5.625 percent. Proceeds were used to repay short-term borrowings used to finance capital expenditures.

On December 9, 2005, CL&P amended its 5-year unsecured revolving credit facility by extending the termination date by one year to November 6, 2010. Under this facility, CL&P can borrow up to $200 million on a short-term basis, or subject to regulatory approvals, on a long-term basis. At December 31, 2005, there were no borrowings outstanding under this facility. At December 31, 2004, there were $15 million in borrowings under this credit facility.

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

CL&P's senior secured debt is rated A3, BBB+, and A- by Moody's Investors Service (Moody's), Standard & Poor's (S&P), and Fitch Ratings, respectively. All outlooks are stable.

In 2005, CL&P paid approximately $53.8 million to NU in the form of common dividends.

Capital expenditures described herein are cash capital expenditures and do not include cost of removal, allowance for funds used during construction (AFUDC), and the capitalized portion of pension expense or income. CL&P's capital expenditures totaled $444.4 million in 2005, compared with $389.3 million in 2004 and $318.5 million in 2003. The increase in CL&P's capital expenditures was primarily the result of higher transmission capital expenditures.

CL&P expects to fund approximately half of its expected capital expenditures over the next several years through internally generated cash flows. As a result, CL&P expects to issue debt regularly.

Business Development and Capital Expenditures

In 2005, CL&P’s capital expenditures totaled $444.4 million compared with $389.3 million in 2004 and $318.5 million in 2003. In 2006, capital expenditures are projected to approach $600 million and approximately $2.5 billion from 2007 through 2010. The increasing level of capital expenditures relates to the need to continue to improve the capacity and reliability of CL&P’s transmission system. That increased level of capital expenditures is increasing the amount of plant in service and CL&P’s earnings base, provided CL&P achieves timely recovery of its investment. Unless otherwise noted, the capital expenditure amounts below exclude AFUDC.

In 2005, CL&P's distribution capital expenditures totaled $236.6 million, compared with $254.7 million in 2004 and $255.9 million in 2003. In 2006, CL&P projects distribution capital expenditures of approximately $200 million and approximately $1 billion from 2007 through 2010. In December of 2003, the DPUC approved a total of $900 million of distribution capital expenditures for CL&P from 2004 through 2007. Those expenditures are intended to improve the reliability of the distribution system and to meet growth requirements on the distribution system.

CL&P’s transmission capital expenditures totaled $207.8 million in 2005, compared with $134.6 million in 2004 and $62.6 million in 2003. The increase in CL&P's transmission capital expenditures in 2005 was primarily the result of increased spending on a new 21-mile 345

kilovolt (kV) transmission project between Bethel, Connecticut and Norwalk, Connecticut. In 2006, CL&P's transmission capital expenditures are projected to total approximately $400 million and approximately $1.5 billion from 2007 through 2010.

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

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

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

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

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

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

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

Transmission Access and FERC Regulatory Changes

In January of 2005, the New England transmission owners approved activation of the New England Regional Transmission Organization (RTO) which occurred on February 1, 2005. CL&P is now a member of the New England RTO and provides regional open access transmission service over its transmission system under the ISO-NE Transmission, Markets and Services Tariff, FERC Electric Tariff No. 3 and local open access transmission service under the ISO-NE Transmission, Markets and Services Tariff, FERC Electric No. 3, Schedule 21 - NU.

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

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

Legislative Matters

Federal Energy Legislation: On August 8, 2005, President Bush signed into law comprehensive energy legislation. Among provisions potentially affecting CL&P are the repeal of PUHCA, FERC backstop siting authority for transmission, transmission pricing and rate reform, renewable production tax credits, and accelerated depreciation for certain new electric and gas facilities. The accelerated depreciation provision, assuming timely rate recovery, is expected to increase CL&P cash flows by more than $4.5 million annually. As part of this legislation, some but not all of the SEC's responsibilities under PUHCA were transferred to the FERC.

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

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

Regulatory Issues and Rate Matters

Transmission - Wholesale Rates: Wholesale transmission revenues are based on rates and formulas that are approved by the FERC. Most of CL&P’s wholesale transmission revenues are collected through a combination of the RNS tariff and CL&P’s LNS tariff. CL&P’s LNS rate is reset on January 1and June 1of each year. CL&P's RNS rate is reset on June 1 of each year. On January 1, 2006, CL&P's LNS rates increased CL&P's wholesale revenues by approximately $10.4 million on an annualized basis. The LNS and RNS rates to be effective on June 1, 2006 have not yet been determined. Additionally, CL&P's LNS tariff provides for a true-up to actual costs, which ensures that CL&P's transmission business recovers its total transmission revenue requirements, including the allowed ROE. At December 31, 2005, this true-up resulted in the recognition of a $1.3 million regulatory liability.

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

Transmission - Retail Rates: A significant portion of transmission business revenue comes from ISO-NE charges to the distribution businesses of CL&P. The distribution business recovers these costs through the retail rates that are charged to their retail customers. In July of 2005, CL&P began tracking its retail transmission revenues and expenses. CL&P filed for a transmission adjustment clause on August 1, 2005 with the rate tracking mechanism effective on July 1, 2005. The DPUC approved the mechanism on December 20, 2005. On January 1, 2006, consistent with that approval, CL&P raised its retail transmission rate to collect $21 million of additional revenues over the first six months of 2006. CL&P adjusts its retail transmission rates on a regular basis, thereby recovering all of its retail transmission expenses on a timely basis. This new tracking mechanism resulted from the enactment of the new legislation passed by the Connecticut legislature in 2005.

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

After opposition from state regulators, utilities and various Congressional delegations, the FERC ordered settlement negotiations before an ALJ to determine whether there was an acceptable alternative to LICAP. On March 6, 2006, ISO-NE and a broad cross-section of critical stakeholders from around the region, including CL&P, filed a comprehensive settlement agreement at the FERC implementing a FCM in place of LICAP. The settlement agreement provides for a fixed level of compensation to generators from December 1, 2006 through May 31,

2010 without regard to location in New England, and annual forward capacity auctions, beginning in 2008, for the 1-year period ending on May 31, 2011, and annually thereafter. The settlement agreement must be approved by the FERC, and the parties have asked for a decision by June 30, 2006. According to preliminary estimates, FCM would require CL&P to pay approximately $470 million during the 3½-year transition period. CL&P would be able to recover these costs from its customers through the FMCC mechanism.

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

Procurement Fee Rate Proceedings: CL&P is currently allowed to collect a fixed procurement fee of 0.50 mills per kilowatt-hour (kWh) from customers who purchase TSO service through 2006. One mill is equal to one-tenth of a cent. That fee can increase to 0.75 mills per kWh if CL&P outperforms certain regional benchmarks. The fixed portion of the procurement fee amounted to approximately $12 million (approximately $7 million after-tax) for 2004. CL&P submitted to the DPUC its proposed methodology to calculate the variable portion (incentive portion) of the procurement fee. CL&P requested approval of $5.8 million for its 2004 incentive payment. On December 8, 2005, a draft decision was issued in this docket, which accepted the methodology proposed by CL&P and authorized payment of the $5.8 million incentive fee. The DPUC has not set a date for issuing a final decision.

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

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

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

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

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

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

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

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

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

Deferred Contractual Obligations

FERC Proceedings: In 2003, the Connecticut Yankee Atomic Power Company (CYAPC) increased the estimated decommissioning and plant closure costs for the period 2000 through 2023 by approximately $395 million over the April 2000 estimate of $436 million approved by the FERC in a 2000 rate case settlement. The revised estimate reflects the increases in the projected costs of spent fuel storage, increased security and liability and property insurance costs, and the fact that CYAPC is now self performing all work to complete the decommissioning of the plant due to the termination of the decommissioning contract with Bechtel Power Corporation (Bechtel) in July of 2003. CL&P's share of CYAPC's increase in decommissioning and plant closure costs is approximately $136 million. On July 1, 2004, CYAPC filed with the FERC for recovery seeking to increase its annual decommissioning collections from $16.7 million to $93 million for a six-year period beginning on January 1, 2005. On August 30, 2004, the FERC issued an order accepting the rates, with collection beginning on February 1, 2005, subject to refund.

Both the DPUC and Bechtel filed testimony in the FERC proceeding claiming that CYAPC was imprudent in its management of the decommissioning project. In its testimony, the DPUC recommended a disallowance of $225 million to $234 million out of CYAPC's requested rate increase of approximately $395 million. CL&P's share of the DPUC's recommended disallowance would be between $78 million to $81 million. The FERC staff also filed testimony that recommended a $38 million decrease in the requested rate increase claiming that CYAPC should have used a different gross domestic product (GDP) escalator. CL&P's share of this recommended decrease is $13.1 million.

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

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

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

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

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

Spent Nuclear Fuel Litigation: CYAPC, Yankee Atomic Energy Company (YAEC) and Maine Yankee Atomic Power Company (MYAPC) (Yankee Companies) also commenced litigation in 1998 charging that the federal government breached contracts it entered into with each company in 1983 under the Act. Under the Act, the United States Department of Energy (DOE) was to begin removing spent nuclear fuel from the nuclear plants of the Yankee Companies no later than January 31, 1998 in return for payments by each company into the nuclear waste fund. No fuel has been collected by the DOE, and spent nuclear fuel is stored on the sites of the Yankee Companies' plants. The Yankee Companies collected the funds for payments into the nuclear waste fund from wholesale utility customers under FERC-approved contract rates. The wholesale utility customers in turn collect these payments from their retail electric customers. The Yankee Companies'

individual damage claims attributed to the government's breach ranging between $523 million and $543 million are specific to each plant and include incremental storage, security, construction and other costs through 2010. The CYAPC damage claim ranges from $186 million to $198 million, the YAEC damage claim ranges from $177 million to $185 million and the MYAPC damage claim is $160 million. The DOE trial ended on August 31, 2004 and a verdict has not been reached. Post-trial findings of facts and final briefs were filed by the parties in January of 2005. The Yankee Companies' current rates do not include an amount for recovery of damages in this matter. Management can predict neither the outcome of this matter nor its ultimate impact on CL&P.

YAEC: In November of 2005, YAEC established an updated estimate of the cost of completing the decommissioning of its plant resulting in an increase of approximately $85 million. CL&P's share of the increase in estimated costs is $20.8 million. This estimate reflects the cost of completing site closure activities from October of 2005 forward and storing spent nuclear fuel and other high level waste on site until 2020, when it is assumed to be removed by the DOE. This estimate projects a total cost of $192.1 million for the completion of decommissioning and long-term fuel storage. To fund these costs, on November 23, 2005, YAEC submitted an application to the FERC to increase YAEC’s wholesale decommissioning charges. The DPUC and the Massachusetts attorney general protested these increases. On January 31, 2006, the FERC issued an order accepting the rate increase, effective February 1, 2006, subject to refund after hearings and settlement judge proceedings. The hearings have been suspended pending settlement discussions between YAEC, the FERC and other intervenors in the case. CL&P has a 24.5 percent ownership interest in YAEC and can predict neither the outcome of this matter nor its ultimate impact on CL&P.

Off-Balance Sheet Arrangements

The CL&P Receivables Corporation (CRC) was incorporated on September 5, 1997 and is a wholly owned subsidiary of CL&P. CRC has an agreement with CL&P to purchase and has an arrangement with a highly-rated financial institution under which CRC can sell up to $100 million of an undivided interest in accounts receivable and unbilled revenues. At December 31, 2005 and 2004, CRC had sold an undivided interest in its accounts receivable and unbilled revenues of $80 million and $90 million, respectively, to that financial institution with limited recourse.

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

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

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

Critical Accounting Policies and Estimates

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

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

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

CL&P utilizes regulatory commission approved tracking mechanisms to track the recovery of certain incurred costs. The tracking mechanisms allow for rates to be changed periodically, with overcollections refunded to customers or undercollections collected from customers in future periods.

Wholesale transmission revenues are based on rates and formulas that are approved by the FERC. Most of CL&P’s wholesale transmission revenues are collected through a combination of the RNS tariff and CL&P's LNS tariff. The RNS tariff, which is administered by ISO-NE, recovers the revenue requirements associated with transmission facilities that are deemed by the FERC to be Pool Transmission Facilities. The LNS tariff, which was accepted by the FERC, provides for the recovery of CL&P's total transmission revenue requirements, net of revenue credits received from various rate components, including revenues received under the RNS rates. At December 31, 2005, this true-up has resulted in the recognition of a $1.3 million regulatory liability.

A significant portion of the CL&P transmission business revenue comes from ISO-NE charges to CL&P's electric distribution business. CL&P recovers these costs through the retail rates that are charged to its retail customers. In July of 2005, CL&P began tracking its retail transmission revenues and expenses and will adjust its retail transmission rates on a regular basis, thereby recovering all of its retail transmission expenses on a timely basis. This new tracking mechanism resulted from the enactment of the new legislation passed by the Connecticut legislature in 2005.

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

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

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

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

Derivative Accounting: The application of derivative accounting rules is complex and requires management judgment in the following respects: election and designation of the normal purchases and sales exception, identification of derivatives and embedded derivatives, and determining the fair value of derivatives.

Certain of CL&P's contracts for the purchase or sale of energy or energy-related products are derivatives. Those contracts that do not qualify for the normal purchases and sales exception are recorded at fair value as derivative assets and liabilities. At December 31, 2005 and 2004, CL&P recorded the fair value of two existing power purchase contracts as derivatives, one as a derivative asset, and one as a derivative liability. An offsetting regulatory liability and an offsetting regulatory asset have been recorded as management believes that these costs will continue to be recovered or refunded in rates.

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

The application of SFAS No. 71 results in recording regulatory assets and liabilities. Regulatory assets represent the deferral of incurred costs that are probable of future recovery in customer rates. In some cases, CL&P records regulatory assets before approval for recovery has been received from the DPUC. Management must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery. Management bases its conclusion on certain factors, including changes in the regulatory environment, recent rate orders issued by the DPUC 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.

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

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

CL&P has less than 50 percent ownership interests in CYAPC, YAEC and MYAPC. CL&P does not control these companies and does not consolidate them in its financial statements. CL&P accounts for the investments in these companies using the equity method. Under the equity method, CL&P records its ownership share of the earnings or losses at these companies. Determining whether or not CL&P should apply the equity method of accounting for an investment requires management judgment.

In December of 2003, the FASB issued a revised version of FASB Interpretation No. (FIN) 46 (FIN 46R). FIN 46R has resulted in fewer CL&P investments meeting the definition of a VIE. FIN 46R was effective for CL&P for the first quarter of 2004 and did not have an impact on CL&P's consolidated financial statements.

Pension and Postretirement Benefits Other Than Pensions (PBOP): CL&P participates in a uniform noncontributory defined benefit retirement plan (Pension Plan) covering substantially all regular CL&P employees. CL&P also participates in a postretirement benefit plan (PBOP Plan) to provide certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired

employees. For each of these plans, the development of the benefit obligation, fair value of plan assets, funded status and net periodic benefit credit or cost is based on several significant assumptions. If these assumptions were changed, the resulting change in benefit obligations, fair values of plan assets, funded status and net periodic benefit credits or costs could have a material impact on CL&P's consolidated financial statements.

Pre-tax periodic pension income for the Pension Plan totaled $0.6 million, $14.3 million and $29.1 million for the years ended December 31, 2005, 2004 and 2003, respectively. The pension income amounts exclude one-time items recorded under SFAS No. 88, "Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits."

Not included in the pension expense/(income) amount are pension amounts related to intercompany allocations totaling $8.8 million, $2.5 million and $(1) million for the years ended December 31, 2005, 2004 and 2003, respectively, including pension curtailment and termination benefits expense of $2.4 million and $0.5 million for the years ended December 31, 2005 and 2004, respectively. These amounts are included in other operating expenses on the accompanying consolidated financial statements.

The pre-tax net PBOP Plan cost, excluding curtailments and termination benefits, totaled $21.5 million, $18.6 million and $16.6 million for the years ended December 31, 2005, 2004 and 2003, respectively.

As a result of NU's decision to pursue a fundamentally different business strategy, and align the structure of the company to support this business strategy, CL&P recorded a $1 million pre-tax curtailment expense in 2005 for the Pension Plan. CL&P also accrued certain related termination benefits and recorded a $1.3 million pre-tax charge in 2005 for the Pension Plan.

On December 15, 2005, the NU Board of Trustees approved a benefit for new non-union employees hired on and after January 1, 2006 to receive retirement benefits under a new 401(k) benefit rather than under the Pension Plan. Non-union employees actively employed on December 31, 2005 will be given the choice in 2006 either to elect to continue participation in the Pension Plan or instead receive a new employer contribution under the 401(k) Savings Plan effective January 1, 2007. If the new benefit is elected, their accrued pension liability in the Pension Plan will be frozen as of December 31, 2006. Non-union employees will make this election in the second half of 2006. This decision resulted in the recording of an estimated pre-tax curtailment expense of $1.3 million in 2005, as a certain number of employees are expected to elect the new 401(k) benefit, resulting in a reduction in aggregate estimated future years of service under the Pension Plan. Management estimated the amount of the curtailment expense associated with this change based upon actuarial calculations and certain assumptions, including the expected level of transfers to the new 401(k) benefit. Any adjustments to this estimate resulting from actual employee elections will be recorded in 2006.

In April of 2004, as a result of litigation with nineteen former employees, CL&P was ordered by the court to modify its Pension Plan to include special retirement benefits for fifteen of these former employees retroactive to the dates of their retirement and provide increased future monthly benefit payments. CL&P recorded $1.1 million in termination benefits related to this litigation in 2004 and made a lump sum payment totaling $0.8 million to these former employees.

For the PBOP Plan, CL&P recorded an estimated $2.5 million pre-tax curtailment expense at December 31, 2005 relating to NU's change in business strategy. CL&P also accrued a $0.2 million pre-tax termination benefit at December 31, 2005 relating to certain benefits provided under the terms of the PBOP Plan. Additional termination benefits may be recorded in 2006.

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

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


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

The actual asset allocations at December 31, 2005 and 2004 approximated these target asset allocations. CL&P 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 4, "Pension Benefits and Postretirement Benefits Other Than Pensions," to the consolidated financial statements.

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

At December 31, 2005, the Pension Plan had cumulative unrecognized investment gains of $36.2 million, which will decrease pension expense over the next four years. At December 31, 2005, the Pension Plan also had cumulative unrecognized actuarial losses of $203.6 million, which will increase pension expense over the expected future working lifetime of active Pension Plan participants, or approximately 13 years. The combined total of unrecognized investment gains and actuarial losses at December 31, 2005 is a net unrecognized loss of $167.4 million. These gains and losses impact the determination of pension expense and the actuarially determined prepaid pension amount recorded on the consolidated balance sheets but have no impact on expected Pension Plan funding.

At December 31, 2005, the PBOP Plan had cumulative unrecognized investment gains of $17.1 million, which will decrease PBOP Plan expense over the next four years. At December 31, 2005, the PBOP Plan also had cumulative unrecognized actuarial losses of $87.8 million, which will increase PBOP Plan expense over the expected future working lifetime of active PBOP Plan participants, or approximately 13 years. The combined total of unrecognized investment gains and actuarial losses at December 31, 2005 is a net unrecognized loss of $70.7 million. These gains and losses impact the determination of PBOP Plan cost and the actuarially determined accrued PBOP Plan cost recorded on the consolidated balance sheets.

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

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


	Pension Plan		Postretirement Plan
Year	Expected Contributions	Forecasted Expense/ (Income)	Expected Contributions	Forecasted Expense
2006	$0.0	$ 3.1	$ 21.0	$ 21.0
2007	$0.0	$(6.3)	$ 18.1	$ 18.1
2008	$0.0	$(9.8)	$ 17.2	$ 17.2

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

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


	At December 31,
	Pension Plan		Postretirement Plan
Assumption Change	2005	2004	2005	2004
Lower long-term rate of return	$ 4.5	$ 4.7	$0.3	$0.3
Lower discount rate	$ 5.6	$ 5.1	$0.4	$0.4
Lower compensation increase	$(2.8)	$(2.0)	N/A	N/A

Plan Assets: The market-related value of the Pension Plan assets has increased by $25.3 million to $990.7 million at December 31, 2005. The projected benefit obligation (PBO) for the Pension Plan has also increased by $59.3 million to $859.3 million at December 31, 2005. These changes have decreased the funded status of the Pension Plan on a PBO basis from an overfunded position of $165.4 million at December 31, 2004 to an overfunded position of $131.4 million at December 31, 2005. The PBO includes expectations of future employee compensation increases. The accumulated benefit obligation (ABO) of the Pension Plan was approximately $221 million less than Pension Plan assets at December 31, 2005 and approximately $269 million less than Pension Plan assets at December 31, 2004. The ABO is the obligation for employee service and compensation provided through December 31, 2005. Under current accounting rules, if the ABO exceeds Pension Plan assets at a future plan measurement date, CL&P will record an additional minimum liability. CL&P has not made employer contributions since 1991.

The value of PBOP Plan assets has increased from $74.9 million at December 31, 2004 to $85.1 million at December 31, 2005. The benefit obligation for the PBOP Plan has increased from $192.4 million at December 31, 2004 to $200.7 million at December 31, 2005. These changes have decreased the underfunded status of the PBOP Plan on an accumulated projected benefit obligation basis from $117.5 million at December 31, 2004 to $115.6 million at December 31, 2005. CL&P has made a contribution each year equal to the PBOP Plan’s postretirement benefit cost, excluding curtailments, settlements and special termination benefits.

Health Care Cost: The health care cost trend assumption used to project increases in medical costs was 7 percent for 2005 and 8 percent for 2004, decreasing one percentage point per year to an ultimate rate of 5 percent in 2007. For December 31, 2005 disclosure purposes, the health care cost trend assumption was reset for 2006 at 10 percent, decreasing one percentage point per year to an ultimate rate of 5 percent in 2011. The effect of increasing the health care cost trend by one percentage point would have increased service and interest cost components of the PBOP Plan cost by $0.4 million in 2005 and $0.4 million in 2004.

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

CL&P accounts for deferred taxes under SFAS No. 109, "Accounting for Income Taxes." For temporary differences recorded as deferred tax liabilities that will be recovered in rates in the future, CL&P has established a regulatory asset. The regulatory asset amounted to $227.6 million and $207.5 million at December 31, 2005 and 2004, respectively. Regulatory agencies in certain jurisdictions in which CL&P operates require the tax effect of specific temporary differences to be "flowed through" to utility customers. Flow through treatment means that deferred tax expense is not recorded in the consolidated statements of income. Instead, the tax effect of the temporary difference impacts both amounts for income tax expense currently included in customers’ rates and the company’s net income. Flow through treatment can result in effective income tax rates that are significantly different than expected income tax rates. Recording deferred taxes on flow through items is required by SFAS No. 109, and the offset to the deferred tax amounts is the regulatory asset referred to above.

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

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

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

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

full site remediation and long-term monitoring. The probabilistic model approach estimates the liabilities associated with each possible action plan based on findings through various phases of site assessments.

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

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.

Asset Retirement Obligations: On March 30, 2005, the FASB issued FIN 47, "Accounting for Conditional Asset Retirement Obligations - an Interpretation of FASB Statement No. 143." FIN 47 requires an entity to recognize a liability for the fair value of an asset retirement obligation (ARO) that is conditional on a future event if the liability’s fair value can be reasonably estimated. CL&P adopted FIN 47 on December 31, 2005. Upon adoption, management identified several conditional removal obligations that have been accounted for as AROs. For further information regarding the adoption of FIN 47, see Note 1M, "Summary of Significant Accounting Policies - Asset Retirement Obligations," to the consolidated financial statements.

Under SFAS No. 71, regulated utilities, including CL&P, currently recover amounts in rates for future costs of removal of plant assets. At December 31, 2005 and 2004, these amounts totaling $139.4 million and $144.3 million, respectively, are classified as regulatory liabilities on the accompanying consolidated balance sheets.

Special Purpose Entities: In addition to the special purpose entity that is described in the "Off-Balance Sheet Arrangements" section of this Management's Discussion and Analysis, during 2001, to facilitate the issuance of rate reduction certificates intended to finance certain stranded costs, CL&P established CL&P Funding LLC. CL&P Funding LLC was created as part of a state-sponsored securitization program. CL&P Funding LLC is restricted from engaging in non-related activities and is required to operate in a manner intended to reduce the likelihood that it would be included in CL&P’s bankruptcy estate if it ever became involved in a bankruptcy proceeding. CL&P Funding LLC and the securitization amounts are consolidated in the accompanying consolidated financial statements.

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

Other Matters

Commitments and Contingencies: For further information regarding other commitments and contingencies, see Note 5, "Commitments and Contingencies," to the consolidated financial statements.

Accounting Standards Issued But Not Yet Adopted:

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

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


(Millions of Dollars)	2006	2007	2008	2009	2010	Thereafter
Long-term debt ^{(a) (b)}	$ -	$ -	$ -	$ -	$ -	$1,043.7
Estimated interest payments on existing long-term debt	59.6	59.6	59.6	59.6	59.6	923.7
Capital leases ^{(c) (d)}	2.4	2.4	2.1	2.0	1.5	16.6
Operating leases ^{(d) (e)}	19.5	18.4	15.5	11.0	9.2	26.5
Required funding of other post- retirement benefit obligations ^(e)	21.0	18.1	17.2	16.3	15.6	N/A
Long-term contractual arrangements^{(d) (e)}	479.8	299.8	281.0	250.2	220.1	891.6
Totals	$582.3	$398.3	$375.4	$339.1	$306.0	$2,902.1

^(a) Included in CL&P's 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 in the absence of receipt by the company of a waiver or amendment. Such acceleration would change the obligations outlined in the table of contractual obligations and commercial commitments.

^(b) Long-term debt disclosed above excludes fees and interest due for spent nuclear fuel disposal costs of $216.9 million and unamortized discounts of $1.7 million.

^(c) The capital lease obligations include imputed interest of $13.5 million.

^(d) CL&P has no provisions in its capital or operating lease agreements or agreements related to its long-term contractual arrangements that could trigger a change in terms and conditions, such as acceleration of payment obligations.

^(e) Amounts are not included on CL&P's consolidated balance sheets.

Rate reduction bond amounts are non-recourse to CL&P, have no required payments over the next five years and are not included in this table. CL&P's standard offer service contracts and default service contracts also are not included in this table. For further information regarding CL&P’s contractual obligations and commercial commitments, see Note 2, "Short-Term Debt," 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 CL&P's expectations, plans, objectives, future financial performance and other statements that are not historical facts. These statements are "forward looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. In some cases the reader can identify these forward looking statements by words such as "estimate," "expect," "anticipate," "intend," "plan," "believe," "forecast," "should," "could," and similar expressions. Forward looking statements involve risks and uncertainties that may cause actual results or outcomes to differ materially from those included in the forward looking statements. Factors that may cause actual results to differ materially from those included in the forward looking statements include, but are not limited to, actions by state and federal regulatory bodies, competition and industry restructuring, changes in economic conditions, changes in weather patterns, changes in laws, regulations or regulatory policy, expiration or initiation of significant energy supply contracts, changes in levels of capital expenditures, developments in legal or public policy doctrines, technological developments, volatility in electric and natural gas commodity markets, effectiveness of our risk management policies and procedures, changes in accounting standards and financial reporting regulations, fluctuations in the value of electricity positions, actions of rating agencies, terrorist attacks on domestic energy facilities and other presently unknown or unforeseen factors. Other risk factors are detailed from time to time in our reports to the SEC. Management undertakes no obligation to update the information contained in any forward looking statements to reflect developments or circumstances occurring after the statement is made.

Web Site: Additional financial information is available through CL&P's web site at www.cl-p.com.

RESULTS OF OPERATIONS

The following table provides the variances in income statement line items for the consolidated statements of income included in this annual report for the past two years.


Income Statement Variances	2005 over/(under) 2004			2004 over/(under) 2003
(Millions of Dollars)	Amount	Percent		Amount	Percent
Operating Revenues	$634	22	%	$128	5	%

Operating Expenses:
Fuel, purchased and net interchange power	447	26		96	6
Other operation	113	26		53	14
Maintenance	14	17		8	11
Depreciation	14	12		15	14
Amortization of regulatory asset, net	35	(a)		(82)	(77)
Amortization of rate reduction bonds	8	7		7	7
Taxes other than income taxes	12	8		1	-
Total operating expenses	643	25		98	4
Operating Income	(9)	(4)		30	16
Interest expense, net	10	9		-	-
Other income, net	13	52		16	(a)
Income before income tax expense	(6)	(5)		46	53
Income tax expense	(13)	(29)		27	(a)
Net income	$ 7	8	%	$ 19	30	%

(a) Percent greater than 100.

Comparison of the Year 2005 to the Year 2004

Operating Revenues

Operating revenues increased $634 million in 2005, compared to 2004, due to higher distribution revenues ($615 million) and higher transmission revenues ($19 million).

The distribution revenue increase of $615 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 ($570 million). The tracking mechanisms allow for rates to be changed periodically with over collections refunded to customers or under collections collected from customers in future periods. The distribution component of rates which impact earnings increased $45 million, primarily due to the retail rate increase effective January 1, 2005 and increased sales volumes, partially offset by the additional reserve recorded to reflect the final decision on the streetlight docket ($2 million). Retail sales in 2005 were 3.0 percent higher than in 2004.

The distribution revenue tracking components increased $570 million primarily due to higher TSO related revenues ($299 million), an increase in revenues associated with the recovery of FMCC charges ($235 million), and higher wholesale revenues ($51 million) primarily due to higher market prices for the sales of IPP contract related power, partially offset by lower revenues as a result of lower retail rates for the recovery of conservation and load management and system benefit costs ($9 million).

Transmission revenues increased $19 million primarily due to higher rate base and operating expenses which are recovered under the NU schedule 21 tariff and revenues resulting from the additional recovery of 2004 expenses.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expense increased $447 million in 2005, primarily due to higher TSO supply costs as a result of the higher retail sales and a higher cost per kWh in 2005.

Other Operation

Other operation expenses increased $113 million in 2005 primarily due to higher RMR costs ($73 million) which are tracked and recovered through the FMCC, and higher administrative expenses ($36 million) mainly as a result of higher pension and other benefit costs ($18 million) and employee termination and benefit plan curtailment charges ($16 million).

Maintenance

Maintenance expense increased $14 million in 2005 primarily due to higher expenses related to distribution lines maintenance ($11 million) in part due to heat related and storm activity, higher expenses for substation maintenance ($1 million) and higher transmission system maintenance expenses ($1 million).

Depreciation

Depreciation expense increased $14 million in 2005 due to higher utility plant balances resulting from plant additions.

Amortization of Regulatory Assets, Net

Amortization of regulatory assets, net increased $35 million in 2005 primarily due to higher amortization related to the recovery of transition charges as a result of higher wholesale revenues.

Amortization of Rate Reduction Bonds

Amortization of rate reduction bonds increased $8 million in 2005 due to the repayment of additional principal.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $12 million in 2005 primarily due to higher Connecticut GET (gross earnings tax) resulting from higher revenue ($13 million) and higher property taxes ($4 million), partially offset by lower taxes paid in 2005 to the town of Waterford for lost property tax revenue as a result of the sale of Millstone ($3 million).

Interest Expense, Net

Interest expense, net increased $10 million in 2005 primarily due to higher interest on long-term debt ($16 million) mainly as a result of $280 million of new debt issued in September 2004 ($11 million) and $200 million of new debt issued in April 2005 ($7 million), and higher other interest related to the final decision on the streetlight docket ($3 million), partially offset by lower rate reduction bond interest resulting from lower principal balances outstanding ($8 million).

Other Income, Net

Other income, net increased $13 million in 2005 primarily due to a higher TSO procurement fee ($6 million) and a higher AFUDC ($6 million), as a result of increased eligible CWIP for transmission and lower short term debt resulting in a greater component of CWIP being subject to the higher equity rate.

Income Taxes

Income tax expense decreased $13 million in 2005 primarily due to lower pre-tax income, greater favorable flow through adjustments for plant related items and lower state tax due to lower rates and higher credits. For further information regarding income tax expense, see Note 1H, "Summary of Significant Accounting Policies - Income Taxes," to the consolidated financial statements.

Comparison of the Year 2004 to the Year 2003

Operating Revenues

Operating revenues increased $128 million in 2004, compared with the same period in 2003, due to higher distribution revenues ($112 million) and higher transmission revenues ($16 million).

The distribution revenue increase of $112 million is primarily due to non-earnings components of retail rates ($89 million). The distribution and retail transmission components of CL&P’s rates which flows through to earnings increased $31 million, primarily due to the retail transmission rate increase effective in January of 2004. The non-earnings components increase of $89 million is primarily due to the pass through of energy supply costs ($168 million) and FMCC ($151 million), partially offset by the resolution of Standard Market Design (SMD) cost recovery which was being collected from CL&P customers in 2003 and early 2004 and also partially refunded in late 2004 ($71 million), lower wholesale revenues due in part to the expiration of long-term contracts ($46 million), lower CL&P EAC revenue as a result of the end of EAC billings in 2003 ($44 million), lower system benefit cost recoveries ($31 million), lower transition cost recoveries ($21 million), and lower revenue to fund Conservation and Load Management (C&LM) initiatives ($16 million). Retail sales in 2004 were 0.1 percent higher than 2003.

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

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expense increased $96 million in 2004, primarily due to an increase in the standard offer service supply costs ($152 million), partially offset by lower deferrals of fuel expense as a result of the lower levels of fuel and congestion costs ($53 million).

Other Operation

Other operation expenses increased $53 million in 2004, primarily due to higher RMR costs ($60 million) and other power pool related expenses recovered through the FMCC charge ($11 million), partially offset by lower C&LM expense ($22 million).

Maintenance

Maintenance expenses increased $8 million in 2004 primarily due to the 2003 positive resolution of the CL&P Millstone use of proceeds docket ($4 million) and higher distribution maintenance expenses ($4 million).

Depreciation

Depreciation expense increased $15 million in 2004, primarily due to higher utility plant balances in 2004 resulting from plant additions and higher depreciation rates resulting from the distribution rate case decision effective in January of 2004.

Amortization of Regulatory Assets, Net

Amortization expense decreased $82 million in 2004 primarily due to the lower amortization related to the recovery of system benefit and transition charges ($54 million), primarily due to the lower recovery of stranded costs resulting from the decrease in the system benefit and transition charge component of retail rates, and a decrease in amortization expense resulting from the amortization of GSC over-recoveries allowed in the distribution rate case decision effective in January of 2004 ($29 million).

Amortization of Rate Reduction Bonds

Amortization of rate reduction bonds increased $7 million in 2004, due to the repayment of a higher principal amount.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $1 million in 2004, primarily due to higher property taxes.

Other Income/(Loss), Net

Other income, net increased $16 million in 2004, primarily due to the recognition beginning in 2004 of a procurement fee approved in the TSO docket ($12 million), higher interest and dividend income ($3 million) and higher C&LM incentive income ($2 million).

Income Taxes

Income tax expense increased $27 million in 2004 due to higher income before tax expense, higher reversals of flow through depreciation and adjustments to tax expense as a result of the actual 2003 tax return amounts compared to the 2003 year end tax provision estimates.

Company Report on Internal Controls

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 and other sections of this annual report. These financial statements, which were audited by Deloitte & Touche LLP, have been prepared in conformity with accounting principles generally accepted in the United States of America using estimates and judgments, where required, and giving consideration to materiality.

The company has endeavored to establish a control environment that encourages the maintenance of high standards of conduct in all of its business activities. Management is responsible for maintaining a system of internal controls over financial reporting, that is designed to provide reasonable assurance, at an appropriate cost-benefit relationship, to the company’s management and Board of Trustees of Northeast Utilities regarding the preparation of reliable, published financial statements. The system is supported by an organization of trained management personnel, policies and procedures, and a comprehensive program of internal audits. Through established programs, the company regularly communicates to its management employees their internal control responsibilities and obtains information regarding compliance with policies prohibiting conflicts of interest and policies segregating information between regulated and unregulated subsidiary companies. The company has standards of business conduct for all employees, as well as a code of ethics for senior financial officers.

The Audit Committee of the Board of Trustees of Northeast Utilities is composed entirely of independent trustees and includes two members that the Board of Trustees considers "audit committee financial experts." The Audit Committee meets regularly with management, the internal auditors, and the independent auditors to review the activities of each and to discuss audit matters, financial reporting matters, and the system of internal controls over financial reporting. The Audit Committee also meets periodically with the internal auditors and the independent auditors without management present.

Because of inherent limitations in any system of internal controls, errors or irregularities may occur and not be detected. The company believes, however, that its system of internal controls over financial reporting and control environment provide reasonable assurance that its assets are safeguarded from loss or unauthorized use and that its financial records, which are the basis for the preparation of all financial statements, are reliable. Additionally, management believes that its disclosure controls and procedures are in place and operating effectively. Disclosure controls and procedures are designed to ensure that information included in reports such as this annual report is recorded, processed, summarized, and reported within the time periods required and that the information disclosed is accumulated and reviewed by management for discussion and approval.

March 7, 2006

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, 2005 and 2004, and the related consolidated statements of income, comprehensive income, common stockholder’s equity and cash flows for each of the three years in the period ended December 31, 2005. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. 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, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Deloitte & Touche LLP

Hartford, Connecticut

March 7, 2006


THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


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

Current Assets:
Cash	$ 2,301	$ 5,608
Investments in securitizable assets	252,801	139,391
Receivables, less provision for uncollectible
accounts of $1,982 in 2005 and $2,010 in 2004	80,883	69,892
Accounts receivable from affiliated companies	17,214	66,386
Unbilled revenues	7,888	8,189
Taxes receivable	-	766
Materials and supplies	32,929	33,213
Derivative assets - current	82,578	24,243
Prepayments and other	18,003	16,187
	494,597	363,875

Property, Plant and Equipment:
Electric utility	3,997,652	3,671,767
Less: Accumulated depreciation	1,175,164	1,089,872
	2,822,488	2,581,895
Construction work in progress	344,204	242,982
	3,166,692	2,824,877

Deferred Debits and Other Assets:
Regulatory assets	1,357,985	1,526,359
Prepaid pension	315,532	318,559
Derivative assets - long-term	308,648	167,122
Other	121,618	106,121
	2,103,783	2,118,161














Total Assets	$ 5,765,072	$ 5,306,913



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,	2005	2004
	(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION

Current Liabilities:
Notes payable to banks	$ -	$ 15,000
Notes payable to affiliated companies	26,825	90,025
Accounts payable	253,974	166,520
Accounts payable to affiliated companies	39,755	89,242
Accrued taxes	60,531	-
Accrued interest	16,947	14,203
Derivative liabilities – current	477	4,408
Other	70,025	56,606
	468,534	436,004

Rate Reduction Bonds	856,479	995,233

Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	774,190	761,036
Accumulated deferred investment tax credits	85,970	88,540
Deferred contractual obligations	243,279	281,633
Regulatory liabilities	742,993	614,770
Derivative liabilities - long-term	31,774	42,809
Other	131,253	95,505
	2,009,459	1,884,293

Capitalization:
Long-Term Debt	1,258,883	1,052,891

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 2005 and 2004	60,352	60,352
Capital surplus, paid in	612,815	415,140
Retained earnings	382,628	347,176
Accumulated other comprehensive loss	(278)	(376)
Common Stockholder's Equity	1,055,517	822,292
Total Capitalization	2,430,600	1,991,383



Commitments and Contingencies (Note 5)

Total Liabilities and Capitalization	$ 5,765,072	$ 5,306,913



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,	2005	2004		2003
	(Thousands of Dollars)


Operating Revenues	$ 3,466,420	$ 2,832,924	$ 2,704,524

Operating Expenses:
Operation -
Fuel, purchased and net interchange power	2,145,834	1,698,335	1,602,240
Other	550,100	437,502	384,443
Maintenance	95,076	81,064	73,066
Depreciation	133,120	119,295	104,513
Amortization of regulatory assets, net	59,632	24,294	105,956
Amortization of rate reduction bonds	118,488	110,625	103,285
Taxes other than income taxes	154,619	142,919	142,339
Total operating expenses	3,256,869	2,614,034	2,515,842
Operating Income	209,551	218,890	188,682

Interest Expense:
Interest on long-term debt	59,019	43,308	39,815
Interest on rate reduction bonds	55,796	63,667	70,284
Other interest	5,220	3,072	508
Interest expense, net	120,035	110,047	110,607
Other Income, Net	37,503	24,712	8,968
Income Before Income Tax Expense	127,019	133,555	87,043
Income Tax Expense	32,174	45,539	18,135
Net Income	$ 94,845	$ 88,016	$ 68,908

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Net Income	$ 94,845	$ 88,016	$ 68,908
Other comprehensive income/(loss), net of tax:
Unrealized (losses)/gains on securities	(22)	37	152
Minimum supplemental executive retirement
pension liability adjustments	120	(66)	(136)
Other comprehensive income/(loss), net of tax	98	(29)	16
Comprehensive Income	$ 94,943	$ 87,987	$ 68,924




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,	Retained	Accumulated Other Comprehensive
	Shares	Amount	Paid In	Earnings	(Loss)/Income	Total
	(Thousands of Dollars, except share information)
Balance at January 1, 2003	6,035,205	$ 60,352	$ 327,299	$ 308,554	$ (363)	$ 695,842

Net income for 2003				68,908		68,908
Cash dividends on preferred stock				(5,559)		(5,559)
Cash dividends on common stock				(60,110)		(60,110)
Capital stock expenses, net			186			186
Allocation of benefits - ESOP			(856)			(856)
Other comprehensive income					16	16
Balance at December 31, 2003	6,035,205	60,352	326,629	311,793	(347)	698,427

Net income for 2004				88,016		88,016
Cash dividends on preferred stock				(5,559)		(5,559)
Cash dividends on common stock				(47,074)		(47,074)
Capital contribution from NU parent			88,000			88,000
Tax deduction for stock options exercised and Employee Stock
Purchase Plan disqualifying dispositions			823			823
Capital stock expenses, net			186			186
Allocation of benefits – ESOP			(498)			(498)
Other comprehensive loss					(29)	(29)
Balance at December 31, 2004	6,035,205	60,352	415,140	347,176	(376)	822,292

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

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,	2005	2004	2003
	(Thousands of Dollars)

Operating Activities:
Net income	$ 94,845	$ 88,016	$ 68,908
Adjustments to reconcile to net cash flows
provided by operating activities:
Bad debt expense	12,834	1,440	5,164
Depreciation	133,120	119,295	104,513
Deferred income taxes	(16,585)	102,394	(125,711)
Amortization of regulatory assets, net	59,632	24,294	105,956
Amortization of rate reduction bonds	118,488	110,625	103,285
Amortization/(deferral) of recoverable energy costs	36,090	(13,242)	19,191
Pension expense/(income)	1,491	(6,763)	(14,047)
Regulatory (refunds)/overrecoveries	(73,442)	(137,537)	267,729
Deferred contractual obligations	(60,444)	(35,764)	(34,554)
Other non-cash adjustments	(8,730)	(19,556)	(60,857)
Other sources of cash	717	18,499	2,283
Other uses of cash	(14,192)	(18,594)	(14,691)
Changes in current assets and liabilities:
Receivables and unbilled revenues, net	25,648	(4,201)	(2,008)
Materials and supplies	284	(1,630)	796
Investments in securitizable assets	(113,410)	27,074	12,443
Other current assets	(1,779)	(3,249)	6,886
Accounts payable	25,312	(40,893)	17,692
Accrued taxes	61,297	(65,587)	31,237
Other current liabilities	16,097	9,327	11,564
Net cash flows provided by operating activities	297,273	153,948	505,779

Investing Activities:
Investments in plant	(444,384)	(389,266)	(318,497)
Restricted cash - LMP costs	-	93,630	(93,630)
Net proceeds from sale of property	21,993	-	-
Proceeds from sales of investment securities	1,883	1,773	1,176
Purchases of investment securities	(1,993)	(2,316)	(2,184)
Other investing activities	1,078	2,090	7,224
Net cash flows used in investing activities	(421,423)	(294,089)	(405,911)

Financing Activities:
Issuance of long-term debt	200,000	280,000	-
Reacquisitions and retirements of long-term debt	-	(59,000)	-
Retirement of rate reduction bonds	(138,754)	(129,546)	(120,949)
Capital contribution from Northeast Utilities	197,794	88,000	-
(Decrease)/increase in short-term debt	(15,000)	15,000	-
NU Money Pool (lending)/borrowing	(63,200)	(1,100)	93,025
Cash dividends on preferred stock	(5,559)	(5,559)	(5,559)
Cash dividends on common stock	(53,834)	(47,074)	(60,110)
Other financing activities	(604)	(786)	(620)
Net cash flows provided by/(used in) financing activities	120,843	139,935	(94,213)
Net (decrease)/increase in cash	(3,307)	(206)	5,655
Cash - beginning of year	5,608	5,814	159
Cash - end of year	$ 2,301	$ 5,608	$ 5,814


Supplemental Cash Flow Information:
Cash paid/(received) during the year for:
Interest, net of amounts capitalized	$ 125,249	$ 109,890	$ 112,258
Income taxes	$ (12,761)	$ 24,915	$ 105,167

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

Notes To Consolidated Financial Statements

1. 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. 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 Federal Energy Regulatory Commission (FERC) and/or the SEC. 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.

Included in the consolidated balance sheet at December 31, 2005, are accounts receivable from affiliated companies and accounts payable to affiliated companies totaling $17.2 million and $39.8 million, respectively, relating to transactions between CL&P and other subsidiaries that are wholly owned by NU. At December 31, 2004, these amounts totaled $66.4 million and $89.2 million, respectively.

Total CL&P purchases from affiliate Select Energy, Inc. (Select Energy), another NU subsidiary, for CL&P's standard offer load and for other transactions with Select Energy represented approximately $53 million, $611 million and $688 million for the years ended December 31, 2005, 2004 and 2003, respectively.

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 years' presentation.

In the company's consolidated balance sheet at December 31, 2004, the company changed the classification of certain deposit amounts totaling $9.3 million related to its rate reduction bonds. The company previously presented these amounts on a gross basis in deferred debits and other assets - other with an equal and offsetting amount in other current liabilities. For the current year presentation, these amounts are presented on a net basis in the company's accompanying consolidated balance sheet.

In the company’s consolidated statements of income for the years ended December 31, 2004 and 2003, the company changed the classification of certain costs that were not recoverable from regulated customers totaling $3.2 million and $4.4 million, respectively. The company previously presented these amounts in other income, net. For the current year presentation, these amounts are presented in other operation expenses in the consolidated statements of income for the years ended December 31, 2004 and 2003.

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

The consolidated statements of cash flows for the years ended December 31, 2004 and 2003 have also been reclassified to exclude from cash flows from operations the change in accounts payable related to capital projects as well as excluding these amounts from investments in plant in investing activities. These amounts totaled sources of cash of $18.4 million and uses of cash of $4.6 million for the years ended December 31, 2004 and 2003, respectively.

Accounting Standards Issued But Not Yet Adopted

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

Guarantees

NU provides credit assurances on behalf of subsidiaries in the form of guarantees and letters of credit (LOCs) in the normal course of business. At December 31, 2005, the maximum level of exposure in accordance with FASB Interpretation No. (FIN) 45, "Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others," under guarantees by NU, on behalf of CL&P, totaled $1.2 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 $40 million of LOCs issued on behalf of CL&P at December 31, 2005. CL&P has no guarantees of the performance of third parties.

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

Until the repeal of PUHCA on February 8, 2006, NU was authorized by the SEC to provide up to $50 million of guarantees to the Utility Group, including CL&P, through June 30, 2007. The amount of guarantees on behalf of CL&P outstanding for compliance with this limit at December 31, 2005 is $0.1 million. These amounts are calculated using different, more probabilistic and fair-value based criteria than the maximum level of exposure required to be disclosed under FIN 45. FIN 45 includes all exposures even though they are not reasonably likely to result in exposure to NU on behalf of CL&P.

With the repeal of PUHCA, there are no regulatory limits on NU's ability to guarantee the obligation of its subsidiaries, including CL&P.

Revenues

CL&P retail revenues are based on rates approved by the DPUC. These regulated rates are applied to customers' use of energy to calculate a bill. In general, rates can only be changed through formal proceedings with the DPUC. However, CL&P utilizes a regulatory commission-approved tracking mechanism to track the recovery of certain incurred costs. The tracking mechanism allows 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 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.

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

Transmission Revenues - Wholesale Rates: Wholesale transmission revenues are based on rates and formulas that are approved by the FERC. Most of CL&P’s wholesale transmission revenues are collected through a combination of the New England Regional Network Service (RNS) tariff and CL&P’s Local Network Service (LNS) tariff. The RNS tariff, which is administered by the New England Independent System Operator (ISO-NE), recovers the revenue requirements associated with transmission facilities that are deemed by the FERC to be regional facilities. This regional rate is reset on June 1of each year. The LNS tariff provides for the recovery of CL&P's total transmission revenue requirements, net of revenues received from other sources, including those revenues received under RNS rates. CL&P's LNS tariff is reset on January 1 and June 1 of each year. Additionally, CL&P’s LNS tariff provides for a true-up to actual costs, which ensures that CL&P recovers its total transmission revenue requirements, including an allowed return on equity (ROE). At December 31, 2005, this true-up has resulted in the recognition of a $1.3 million regulatory liability.

Transmission Revenues - Retail Rates: A significant portion of CL&P’s transmission business revenue comes from ISO-NE charges to CL&P’s distribution business. CL&P recovers these costs through the retail rates that are charged to its retail customers. Any difference between the revenues received from retail customers and the retail transmission expenses charged to the distribution business has historically impacted the distribution business earnings. In July of 2005, CL&P began a process of tracking its retail transmission revenues and expenses and adjusting its retail transmission rates on a regular basis, thereby recovering all of its retail transmission expenses on a timely basis. This ratemaking change resulted from the enactment of the legislation passed by the Connecticut legislature in 2005.

Derivative Instruments

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 under accrual accounting.

Certain CL&P contracts for the purchase or sale of energy or energy-related products are derivatives. Derivative contracts that are elected as and meet the requirements of a normal purchase or sale are recognized in revenues or expenses, as applicable, as when the quantity of the contract is delivered. Election of the normal purchases and sales exception (and resulting accrual accounting) for derivatives requires the conclusions that it is probable at the inception of the contract and throughout its term that it will result in physical delivery and that the quantities will be used or sold by the business over a reasonable period in the normal course of business.

Certain CL&P contracts that do not meet the normal purchases and sales criteria are recorded at fair value as derivative assets and liabilities with offsetting amounts recorded as regulatory liabilities, and assets because the contracts are part of providing regulated electric service and because management believes that these amounts will be recovered or refunded in rates.

For further information regarding these 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 businesses of CL&P continue to be cost-of-service rate regulated and management believes that the application of SFAS No. 71 to those businesses continues to be appropriate. Management also believes it is probable that CL&P will recover its investments in long-lived assets, including regulatory assets. In addition, all material net regulatory assets are earning an equity return, except for securitized regulatory assets, which are not supported by equity and substantial portions of the unrecovered contractual obligations regulatory assets.

Regulatory Assets: The components of CL&P's regulatory assets are as follows:


	At December 31,
(Millions of Dollars)	2005	2004
Securitized assets	$ 855.6	$ 994.3
Income taxes, net	227.6	207.5
Unrecovered contractual obligations	197.7	213.4
Recoverable energy costs	7.3	43.4
Other	69.8	67.8
Totals	$1,358.0	$1,526.4

Included in other regulatory assets above of $69.8 million at December 31, 2005 are the regulatory assets recorded associated with the implementation of FIN 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143," totaling $25.1 million. These regulatory assets have not been approved for deferred accounting treatment. At this time, management believes that the regulatory assets related to FIN 47 are probable of recovery.

Additionally, CL&P had $10.7 million and $11.4 million of regulatory costs at December 31, 2005 and 2004, respectively, that are included in deferred debits and other assets - other on the accompanying consolidated balance sheets. These amounts represent regulatory costs that have not yet been approved by the DPUC. Management believes these costs are recoverable in future 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 is $731.4 million and $850 million at December 31, 2005 and 2004, respectively. CL&P used the remaining proceeds from the issuance of the rate reduction certificates to securitize a portion of its SFAS No. 109, "Accounting for Income Taxes," regulatory asset. The securitized SFAS No. 109 regulatory asset had an unamortized balance of $124.2 million and $144.3 million at December 31, 2005 and 2004, respectively.

Securitized assets are being recovered over the amortization period of their associated rate reduction certificates. All outstanding rate reduction certificates of CL&P 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) is accounted for in accordance with the rate-making treatment of the applicable regulatory commissions and SFAS No. 109. Differences in income taxes between SFAS No. 109 and the

rate-making treatment of the applicable regulatory commissions are recorded as regulatory assets which totaled $227.6 million and $207.5 million at December 31, 2005 and 2004, respectively. For further information regarding income taxes, see Note 1H, "Summary of Significant Accounting Policies - Income Taxes" to the consolidated financial statements.

Unrecovered Contractual Obligations: CL&P, under the terms of contracts with Connecticut Yankee Atomic Power Company (CYAPC), Yankee Atomic Energy Company (YAEC) and Maine Yankee Atomic Power Company (MYAPC) (Yankee Companies), is responsible for its proportionate share of the remaining costs of the units, including decommissioning. These amounts which totaled $197.7 million and $213.4 million at December 31, 2005 and 2004, respectively, are recorded as unrecovered contractual obligations. A portion of these obligations for CL&P was securitized in 2001 and is included in securitized regulatory assets. As discussed in Note 5E, "Commitments and Contingencies - Deferred Contractual Obligations," substantial portions of the unrecovered contractual obligations regulatory assets have not yet been approved for recovery. At this time management believes that these regulatory assets are probable of recovery.

Recoverable Energy Costs: Under the Energy Policy Act of 1992 (Energy Act), CL&P was assessed for its proportionate share of the costs of decontaminating and decommissioning uranium enrichment plants owned by the United States Department of Energy (DOE) (D&D Assessment). The Energy Act requires that regulators treat D&D Assessments as a reasonable and necessary current cost of fuel, to be fully recovered in rates like any other fuel cost. CL&P no longer owns nuclear generation assets but continues to recover these costs through rates. At December 31, 2005 and 2004, CL&P’s total D&D Assessment deferrals were $7.3 million and $10.9 million, respectively, and have been recorded as recoverable energy costs. Also included in recoverable energy costs at December 31, 2004 is $32.5 million related to Federally Mandated Congestion Costs (FMCC).

The majority of the recoverable energy costs are currently recovered in rates from CL&P's customers.

Regulatory Liabilities: CL&P had $743 million and $614.8 million of regulatory liabilities at December 31, 2005 and 2004, respectively, including revenues subject to refund. These amounts are comprised of the following:


	At December 31,
(Millions of Dollars)	2005	2004
Cost of removal	$139.4	$144.3
CTA, GSC, and SBC overcollections	154.0	200.0
Regulatory liabilities offsetting derivative assets	391.2	191.4
Other regulatory liabilities	58.4	79.1
Totals	$743.0	$614.8

Cost of Removal: Under SFAS No. 71, CL&P currently recovers amounts in rates for future costs of removal of plant assets. These amounts which totaled $139.4 million and $144.3 million at December 31, 2005 and 2004, respectively, are classified as regulatory liabilities on the accompanying consolidated balance sheets.

CTA, GSC and SBC Overcollections: The Competitive Transition Assessment (CTA) allows CL&P to recover stranded costs, such as securitization costs associated with the rate reduction bonds, amortization of regulatory assets, and IPP over market costs. The Generation Service Charge (GSC) allows CL&P to recover the costs of the procurement of energy for standard offer service. The System Benefits Charge (SBC) allows CL&P to recover certain regulatory and energy public policy costs, such as public education outreach costs, hardship protection costs, transition period property taxes, and displaced workers protection costs. CL&P CTA, GSC and SBC overcollections totaled $154 million and $200 million at December 31, 2005 and 2004, respectively.

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

Income Taxes

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

Details of income tax expense are as follows:


	For the Years Ended December 31,
	2005	2004	2003
	(Millions of Dollars)
The components of the federal and state income tax provisions are:

Current income taxes:
Federal	$44.7	$(50.6)	$ 115.0
State	4.1	(6.2)	28.8
Total current	48.8	(56.8)	143.8
Deferred income taxes, net:
Federal	(1.8)	99.6	(88.7)
State	(12.2)	5.3	(34.5)
Total deferred	(14.0)	104.9	(123.2)
Investment tax credits, net	(2.6)	(2.6)	(2.5)
Total income tax expense	$32.2	$ 45.5	$ 18.1

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


	For the Years Ended December 31,
	2005	2004	2003
	(Millions of Dollars)
Expected federal income tax expense	$44.5	$46.7	$30.5
Tax effect of differences:
Depreciation	(3.9)	2.0	(0.3)
Investment tax credit amortization	(2.6)	(2.6)	(2.5)
State income taxes, net of federal benefit	(5.3)	(0.2)	(3.7)
Tax asset valuation reserve adjustment	-	-	(5.5)
Medicare subsidy	(2.4)	(0.5)	-
Property taxes	(1.9)	(1.0)	(0.3)
Allowance for doubtful accounts	1.7	(1.0)	1.7
Other, net	2.1	2.1	(1.8)
Total income tax expense	$32.2	$45.5	$18.1

NU and its subsidiaries, including CL&P, file a consolidated federal income tax return. NU and its subsidiaries, including CL&P, are parties to a tax allocation agreement under which taxable subsidiaries pay no more taxes than they would have otherwise paid had they filed a stand-alone tax return. Subsidiaries generating tax losses are similarly paid for their losses when utilized.

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


	At December 31,
(Millions of Dollars)	2005	2004
Deferred tax liabilities – current:
Property tax accruals	$ 23.8	$ 20.0
Total deferred tax liabilities – current	23.8	20.0
Deferred tax assets – current:
Allowance for uncollectible accounts	8.0	3.7
Total deferred tax assets – current	8.0	3.7
Net deferred tax liabilities – current	15.8	16.3
Deferred tax liabilities – long-term:
Accelerated depreciation and other plant related differences	633.6	621.4
Securitized costs	44.5	51.8
Income tax gross-up	168.6	166.2
Employee benefits	139.0	126.2
Other	20.4	17.3
Total deferred tax liabilities - long-term	1,006.1	982.9
Deferred tax assets – long-term:
Regulatory deferrals	158.0	174.3
Employee benefits	15.6	10.8
Income tax gross-up	28.2	25.9
Other	30.1	10.9
Total deferred tax assets – long-term	231.9	221.9
Net deferred tax liabilities – long-term	774.2	761.0
Net deferred tax liabilities	$790.0	$777.3

At December 31, 2005, CL&P had state tax credit carry forwards of $14.9 million that expire between 2009 and 2010. At December 31, 2004, CL&P had state tax credit carry forwards of $6.8 million that expire on December 31, 2009.

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

Depreciation

The provision for depreciation on utility assets is calculated using the straight-line method based on the estimated remaining useful lives of depreciable plant-in-service, which range primarily from 3 years to 50 years, adjusted for salvage value and removal costs, as approved by the appropriate regulatory agency where applicable. Depreciation rates are applied to plant-in-service from the time it is placed in service. When plant is retired from service, the original cost of the plant, including costs of removal less salvage, is charged to the accumulated provision for depreciation. Cost of removal is classified as a regulatory liability. The depreciation rates for the several classes of electric utility plant-in-service are equivalent to a composite rate of 3.5 percent in 2005, 3.4 percent in 2004 and 3.3 percent in 2003.

Jointly Owned Electric Utility Plant

At December 31, 2005, CL&P owns common stock in the Yankee Companies. Each of the Yankee Companies owns a single nuclear generating plant which is being decommissioned. CL&P’s ownership interests in the Yankee Companies at December 31, 2005, which are accounted for on the equity method are 34.5 percent of CYAPC, 24.5 percent of YAEC and 12 percent of MYAPC. The total carrying value of CYAPC, MYAPC and YAEC, which is included in deferred debits and other assets - other on the accompanying consolidated balance sheets and the electric distribution reportable segment, totaled $19.5 million and $19.4 million at December 31, 2005 and 2004, 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 1Q, "Summary of Significant Accounting Policies - Other Income, Net," to the consolidated financial statements.

CYAPC filed with the FERC to recover the increased estimate of decommissioning and plant closure costs. The FERC proceeding is ongoing. Management believes that the FERC proceeding has not impaired the value of its investment in CYAPC totaling $16 million at December 31, 2005 but will continue to evaluate the impacts that the FERC proceeding has on CL&P's investment. For further information, see Note 5E, "Commitments and Contingencies - Deferred Contractual Obligations," to the consolidated financial statements.

Allowance for Funds Used During Construction

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


	For the Years Ended December 31,
(Millions of Dollars, except percentages)	2005		2004		2003
Borrowed funds	$ 6.7		$3.1		$3.0
Equity funds	9.8		3.4		5.8
Totals	$16.5		$6.5		$8.8
Average AFUDC rate	7.0	%	4.1	%	7.9	%

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

Sale of Customer Receivables

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

At December 31, 2005 and 2004, amounts sold to CRC by CL&P but not sold to the financial institution totaling $252.8 million and $139.4 million, respectively, are included as investments in securitizable assets on the accompanying consolidated balance sheets. These amounts

would be excluded from CL&P’s assets in the event of CL&P’s bankruptcy. On July 6, 2005, CRC renewed its Receivables Purchase and Sale Agreement with CL&P and the financial institution through July 5, 2006. CL&P’s continuing involvement with the receivables that are sold to CRC and the financial institution is limited to the servicing of those receivables.

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

Asset Retirement Obligations

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

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

CL&P utilized regulatory accounting in accordance with SFAS No. 71 and the impact of this implementation is included in other regulatory assets at December 31, 2005. The fair value of the AROs is included in property, plant and equipment and related accretion is recorded as a regulatory asset, with corresponding credits reflecting the ARO liabilities in deferred credits and other liabilities - other, on the accompanying consolidated balance sheet at December 31, 2005. Depreciation of the ARO asset is also included as a regulatory asset with an offsetting amount in accumulated depreciation. The following table presents the fair value of the ARO, the related accumulated depreciation, the regulatory asset, and the ARO liabilities:


	At December 31, 2005
(Millions of Dollars)	Fair Value of ARO Asset	Accumulated Depreciation of ARO Asset	Regulatory Asset	ARO Liabilities
Asbestos	$ 2.2	$(1.2)	$10.9	$(11.9)
Hazardous contamination	5.4	(1.2)	9.5	(13.7)
Other AROs	9.2	(3.6)	4.7	(10.3)
Total AROs	$16.8	$(6.0)	$25.1	$(35.9)

The ARO liabilities as of December 31, 2005, 2004 and January 1, 2004, as if FIN 47 had been applied for all periods affected, were $35.9 million, $29.5 million and $29.1 million, respectively.

Materials and Supplies

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

Restricted Cash – LMP Costs

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

Excise Taxes

Certain excise taxes levied by state or local governments are collected by 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, 2005, 2004 and 2003, gross receipts taxes, franchise taxes and other excise taxes of $88.2 million, $75.8 million and $76.3 million, respectively, are included in operating revenues and taxes other than income taxes 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)	2005	2004	2003
Other Income:
Investment income	$10.8	$ 7.7	$ 3.0
Equity in earnings of regional nuclear generating companies	1.2	0.6	1.8
CL&P procurement fee	17.8	11.7	-
AFUDC - equity funds	9.8	3.4	5.8
Conservation load management incentive	4.4	4.0	1.5
Return on regulatory deferrals	1.4	1.8	5.8
Other	4.3	3.6	1.8
Total Other Income	49.7	32.8	19.7
Other Loss:
Charitable donations	(3.5)	(3.4)	(5.2)
Advertising	(1.4)	(0.5)	(0.6)
Loss on investments in securitizable assets	(1.8)	(0.7)	(0.6)
Rate reduction bond administrative fees	(1.6)	(1.6)	(1.6)
Lobbying costs	(1.5)	(1.2)	(1.2)
Other	(2.4)	(0.7)	(1.5)
Total Other Loss	(12.2)	(8.1)	(10.7)
Total Other Income, Net	$37.5	$24.7	$ 9.0

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

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 receivables aging category, historical collection and write-off experience and management's assessment of collectibility from individual customers. Management reviews at least quarterly the collectibility of the receivables, and if circumstances change, collectibility estimates are adjusted accordingly. Receivable balances are written-off against the provision for uncollectible accounts when these balances are deemed to be uncollectible.

Severance Benefits

As a result of NU’s decision to pursue a fundamentally different business strategy, and align the structure of the company to support this business strategy, CL&P recorded a $10.1 million severance benefits charge in other operating expenses on the accompanying consolidated statement of income for the year ended December 31, 2005.

2. 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 SEC, the FERC, or by the DPUC. On October 28, 2005, the SEC amended its June 30, 2004 order, granting authorization to allow CL&P to incur total short-term borrowings up to a maximum of $450 million through June 30, 2007. The SEC also granted authorization for borrowing through the NU Money Pool (Pool) until June 30, 2007. Although PUHCA was repealed on February 8, 2006, under FERC's transition rules, all of the existing orders under PUHCA relevant to FERC authority will continue to be in effect until December 31, 2007, except for those related to NU, which will have no borrowing limitations after February 8, 2006. CL&P will be subject to FERC jurisdiction as to issuing short-term debt after February 8, 2006 and must renew any short-term authority after the PUHCA order expires on December 31, 2007.

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

Credit Agreement: On December 9, 2005, CL&P amended its 5-year unsecured revolving credit facility by extending the expiration date by one year to November 6, 2010. The company can borrow up to $200 million on a short-term basis, or subject to regulatory approvals, on a long-term basis. At December 31, 2005, CL&P had no borrowings outstanding under this facility. At December 31, 2004, there were $15 million in borrowings under this credit facility. The weighted-average interest rate on CL&P’s notes payable to banks outstanding on December 31, 2004 was 5.25 percent.

Under this credit agreement, CL&P may borrow at variable rates plus an applicable margin based upon certain debt ratings, as rated by the higher of Standard and Poor’s (S&P) or Moody’s Investors Service (Moody's).

Under this credit agreement, CL&P must comply with certain financial and non-financial covenants, including but not limited to, a consolidated debt to capitalization ratio. CL&P currently is and expects to remain in compliance with these covenants.

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

Pool: CL&P is a member of the 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 parent. NU parent 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 parent, however, bear interest at NU parent’s cost and must be repaid based upon the terms of NU parent’s original borrowing. At December 31, 2005 and 2004, CL&P had borrowings of $26.8 million and $90 million from the Pool, respectively. The interest rate on borrowings from the Pool at December 31, 2005 and 2004 was 4.09 percent and 2.24 percent, respectively.

3. Derivative Instruments

CL&P has two IPP contracts to purchase power that contain pricing provisions that are not clearly and closely related to the price of power and therefore do not qualify for the normal purchases and sales exception. The fair values of these IPP non-trading derivatives at December 31, 2005 include derivative assets with a fair value of $391.2 million, of which $82.6 million and $308.6 million are classified as current and long-term derivative assets on the accompanying consolidated balance sheets, respectively, and derivative liabilities with a fair value of $32.3 million, of which $0.5 million and $31.8 million are classified as current and long-term derivative liabilities on the accompanying consolidated balance sheets, respectively. An offsetting regulatory liability and an offsetting regulatory asset were recorded as management believes that these costs will continue to be recovered or refunded in rates. At December 31, 2004, the fair values of these IPP non-trading derivatives included derivative assets with a fair value of $191.3 million, of which $24.2 million and $167.1 million are classified as current and long-term derivative assets on the accompanying consolidated balance sheets, respectively, and derivative liabilities with a fair value of $47.2 million, of which $4.4 million and $42.8 million are classified as current and long-term derivative liabilities on the accompanying consolidated balance sheets, respectively.

4. Pension Benefits and Postretirement Benefits Other Than Pensions

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


	For the Years Ended December 31,
(Millions of Dollars)	2005	2004	2003
Total pension expense/(income)	$3.0	$(13.2)	$(29.1)
Amount capitalized as utility plant	(1.5)	6.4	15.1
Total pension expense/(income), net of amounts capitalized	$ 1.5	$(6.8)	$(14.0)

Amounts above include pension curtailments and termination benefits expenses of $3.6 million in 2005 and $1.1 million in 2004.

Not included in the pension expense/(income) amount above are pension related intercompany allocations totaling $8.8 million, $2.5 million and $(1) million for the years ended December 31, 2005, 2004 and 2003, respectively, including pension curtailment and termination benefits expense of $2.4 million and $0.5 million for the years ended December 31, 2005 and 2004. These amounts are included in other operating expenses on the accompanying consolidated financial statements.

Pension Curtailments and Termination Benefits: As a result of the decision to pursue a fundamentally different business strategy, and align the structure of the company to support this business strategy, CL&P recorded a $1 million pre-tax curtailment expense in 2005. CL&P also accrued certain related termination benefits and recorded a $1.3 million pre-tax charge in 2005.

On December 15, 2005, the NU Board of Trustees approved a benefit for new non-union employees hired on and after January 1, 2006 to receive retirement benefits under a new 401(k) benefit rather than under the Pension Plan. Non-union employees actively employed on December 31, 2005 will be given the choice in 2006 to elect to continue participation in the Pension Plan or instead receive a new employer contribution under the 401(k) Savings Plan effective January 1, 2007. If the new benefit is elected, their accrued pension liability in the Pension Plan will be frozen as of December 31, 2006. Non-union employees will make this election in the second half of 2006. This decision resulted in CL&P recording an estimated pre-tax curtailment expense of $1.3 million in 2005, as a certain number of employees are expected to elect the new 401(k) benefit, resulting in a reduction in aggregate estimated future years of service under the Pension Plan. Management estimated the amount of the curtailment expense associated with this change based upon actuarial calculations and certain assumptions, including the expected level of transfers to the new 401(k) benefit.

In April of 2004, as a result of litigation with nineteen former employees, NU was ordered by the court to modify its Pension Plan to include special retirement benefits for fifteen of these former employees retroactive to the dates of their retirement and provide increased future monthly benefit payments. CL&P recorded $1.1 million in termination benefits related to this litigation in 2004 and made a lump sum benefit payment totaling $0.8 million to these former employees.

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

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. Since the market-related valuation calculation recognizes gains or losses over a four-year period, the future value of the market-related assets will be impacted as previously deferred gains or losses are recognized.

Postretirement Benefits Other Than Pensions: CL&P also provides certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired employees (PBOP Plan). These benefits are available for employees retiring from 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 which also are tax deductible. Currently, there are no pending regulatory actions regarding postretirement benefit costs and there are no postretirement benefit costs that are deferred as regulatory assets.

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

Based on the current PBOP Plan provisions, CL&P qualifies for this federal subsidy because the actuarial value of CL&P’s PBOP Plan exceeds the threshold required for the subsidy. The Medicare changes decreased the PBOP benefit obligation by $13 million. The total $13 million decrease is currently being amortized as a reduction to PBOP expense over approximately 13 years. For the years ended December 31, 2005 and 2004, this reduction in PBOP expense totaled approximately $1.7 million, including amortization of the actuarial gain of $0.9 million and a reduction in interest cost and service cost based on a lower PBOP benefit obligation of $0.8 million.

PBOP Curtailments and Termination Benefits: CL&P recorded an estimated $2.5 million pre-tax curtailment expense at December 31, 2005 relating to NU's change in business strategy. CL&P also accrued a $0.2 million pre-tax termination benefit at December 31, 2005 relating to certain benefits provided under the terms of the PBOP Plan.

There were no curtailments or termination benefits in 2004 or 2003.

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


	At December 31,
	Pension Benefits		Postretirement Benefits
(Millions of Dollars)	2005	2004	2005	2004
Change in benefit obligation
Benefit obligation at beginning of year	$(800.0)	$(731.3)	$(192.4)	$(169.3)
Service cost	(17.2)	(14.7)	(2.8)	(2.1)
Interest cost	(46.8)	(44.8)	(10.2)	(10.5)
Transfers	0.2	(2.0)	-	(0.8)
Actuarial loss	(53.3)	(52.0)	(11.3)	(24.8)
Benefits paid - excluding lump sum payments	47.3	45.1	15.9	15.1
Benefits paid - lump sum payments	-	0.8	-	-
Curtailment/impact of plan changes	11.8	-	0.3	-
Termination benefits	(1.3)	(1.1)	(0.2)	-
Benefit obligation at end of year	$(859.3)	$(800.0)	$(200.7)	$(192.4)
Change in plan assets
Fair value of plan assets at beginning of year	$965.4	$ 899.3	$ 74.9	$ 64.3
Actual return on plan assets	72.8	110.0	4.6	6.3
Employer contribution	-	-	21.5	18.6
Transfers	(0.2)	2.0	-	0.8
Benefits paid - excluding lump sum payments	(47.3)	(45.1)	(15.9)	(15.1)
Benefits paid - lump sum payments	-	(0.8)	-	-
Fair value of plan assets at end of year	$ 990.7	$ 965.4	$ 85.1	$ 74.9
Funded status at December 31^st	$ 131.4	$ 165.4	$(115.6)	$(117.5)
Unrecognized transition obligation	-	-	41.4	50.3
Unrecognized prior service cost	16.7	23.2	-	-
Unrecognized net loss	167.4	130.0	$ 70.7	66.5
Prepaid/(accrued) benefit cost	$ 315.5	$ 318.6	$ (3.5)	$ (0.7)

The $11.8 million reduction in the plan's obligation that is included in the curtailment/impact of plan changes relates to the reduction in the future years of service expected to be rendered by plan participants. This reduction is the result of the transition of employees into the new 401(k) benefit and the company's decision to pursue a fundamentally different business strategy, and align the structure of the company to support this business strategy. This overall reduction in plan obligation serves to reduce the previously unrecognized actuarial losses.

The company amortizes its unrecognized transition obligation over the remaining service lives of its employees as calculated for CL&P on an individual operating company basis. The company amortizes the unrecognized prior service cost and unrecognized net loss over the remaining service lives of its employees as calculated on a NU consolidated basis.

The accumulated benefit obligation for the Pension Plan was $769.6 million and $696.8 million at December 31, 2005 and 2004, respectively.

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


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

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


	For the Years Ended December 31,
	Pension Benefits			Postretirement Benefits
(Millions of Dollars)	2005	2004	2003	2005	2004	2003
Service cost	$17.1	$ 14.7	$ 12.8	$ 2.8	$ 2.1	$ 2.0
Interest cost	46.8	44.8	44.4	10.2	10.5	11.3
Expected return on plan assets	(80.1)	(81.3)	(84.1)	(4.9)	(4.6)	(5.1)
Amortization of unrecognized net transition (asset)/obligation	-	(0.9)	(0.9)	6.3	6.3	6.3
Amortization of prior service cost	3.0	3.0	3.0	-	-	-
Amortization of actuarial loss/(gain)	12.6	5.4	(4.3)	-	-	-
Other amortization, net	-	-	-	7.1	4.3	2.1
Net periodic (income)/expense – before curtailments and termination benefits	(0.6)	(14.3)	(29.1)	21.5	18.6	16.6
Curtailment expense	2.3	-	-	2.5	-	-
Termination benefits expense	1.3	1.1	-	0.2	-	-
Total curtailments and termination benefits	3.6	1.1	-	2.7	-	-
Total - net periodic expense/(income)	$ 3.0	$(13.2)	$(29.1)	$24.2	$18.6	$16.6

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


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

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


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

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

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


(Millions of Dollars)	One Percentage Point Increase	One Percentage Point Decrease
Effect on total service and interest cost components	$0.4	$(0.3)
Effect on postretirement benefit obligation	$7.3	$(6.4)

CL&P'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. CL&P'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, CL&P also evaluated input from actuaries and consultants as well as long-term inflation assumptions and CL&P's historical 20-year compounded return of approximately 11 percent. The Pension Plan's and PBOP Plan's target asset allocation assumptions and expected long-term rate of return assumptions by asset category are as follows:


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

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


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

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


(Millions of Dollars)
Year	Pension Benefits	Postretirement Benefits	Government Subsidy
2006	$ 48.9	$18.8	$ 2.0
2007	50.2	19.1	2.1
2008	51.2	18.9	2.2
2009	52.2	18.8	2.3
2010	53.2	18.6	2.4
2011-2015	280.6	89.1	13.8

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

Contributions: CL&P does not expect to make any contributions to the Pension Plan in 2006 and expects to make $21 million in contributions to the PBOP Plan in 2006.

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

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

5. Commitments and Contingencies

Regulatory Developments and Rate Matters

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

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

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

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

The amounts recorded as environmental liabilities on the consolidated balance sheets represent management’s best estimate of the liability for environmental costs and takes into consideration site assessment and remediation costs. Based on currently available information for estimated site assessment and remediation costs at December 31, 2005 and 2004, CL&P had $2.7 million and $7.8 million, respectively, recorded as environmental reserves. A reconciliation of the activity in these reserves at December 31, 2005 and 2004 is as follows:


	For the Years Ended December 31,
(Millions of Dollars)	2005	2004
Balance at beginning of year	$7.8	$7.9
Additions and adjustments	(5.0)	0.2
Payments	(0.1)	(0.3)
Balance at end of year	$2.7	$7.8

CL&P currently has 11 sites included in the environmental reserve. Of those 11 sites, 4 sites are in the remediation or long-term monitoring phase, 6 sites have had some level of site assessment completed and the remaining site is in the preliminary stage of site assessment.

For 3 sites that are included in the company's liability for environmental costs, the information known and nature of the remediation options at those sites allows for an estimate of the range of losses to be made. These sites primarily relate to manufactured gas plant (MGP) sites. At December 31, 2005, $1.8 million has been accrued as a liability for these sites, which represents management's best estimate of the liability for environmental costs. This amount differs from an estimated range of loss from $1.6 million to $6 million as management utilizes the probabilistic model approach to make its estimate of the liability for environmental costs.

For the 8 remaining sites for which an estimate is based on the probabilistic model approach, determining a range of estimated losses is not possible. These liabilities are estimated on an undiscounted basis and do not assume that any amounts are recoverable from insurance companies or other third parties. The environmental reserve includes sites at different stages of discovery and remediation and does not include any unasserted claims.

At December 31, 2005, there are 6 sites for which there are unasserted claims, however, any related 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.

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.

MGP Sites: 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 December 31, 2005 and 2004, $1.5 million and $6.5 million, respectively, represents amounts for the site assessment and remediation of MGPs. CL&P currently has 4 MGP sites included in its environmental liability. Of the 4 MGP sites, 3 sites are currently in the site assessment stage and one site is in the preliminary stage of site assessment.

On January 19, 2005, the DPUC issued a final decision approving the sale proceeding of a former MGP site that was held for sale at December 31, 2004. The final decision approved the price of $24 million for the sale of the land and also approved the deferral of the gain in the amount of $14.0 million ($8.4 million net of tax). At December 31, 2004, CL&P had $7.9 million related to remediation efforts at the property and other sale costs recorded in other deferred debits and other assets – other on the accompanying consolidated balance sheets. During 2005, the former MGP site was sold to an independent third party.

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

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

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 DOE for the disposal of spent nuclear fuel and high-level radioactive waste. The DOE is responsible for the selection and development of repositories for, and the disposal of, spent nuclear fuel and high-level radioactive waste. For nuclear fuel used to generate electricity prior to April 7, 1983 (Prior Period Fuel), an accrual has been recorded for the full liability, and payment must be made prior to the first delivery of spent fuel to the DOE. Until such payment is made, the outstanding balance will continue to accrue interest at the 3-month treasury bill yield rate. At December 31, 2005 and 2004, fees due to the DOE for the disposal of Prior Period Fuel were $216.9 million and $210.4 million, respectively, including interest costs of $150.4 million and $143.9 million, respectively.

Long-Term Contractual Arrangements

Vermont Yankee Nuclear Power Corporation (VYNPC): Previously under the terms of its agreement, CL&P paid its ownership (or entitlement) share of costs, which included depreciation, O&M expenses, taxes, the estimated cost of decommissioning, and a return on invested capital to VYNPC and recorded these costs as purchased-power expenses. On July 31, 2002, VYNPC consummated the sale of its nuclear generating unit to a subsidiary of Entergy Corporation for approximately $180 million. CL&P has commitments to buy approximately 9.5 percent of the plant's output through March of 2012 at a range of fixed prices. The total cost of purchases under contracts with VYNPC amounted to $15.3 million in 2005, $15.9 million in 2004 and $17.8 million in 2003.

Electricity Procurement Contracts: CL&P has entered into various arrangements for the purchase of electricity. The total cost of purchases under these arrangements amounted to $148 million in 2005, $200 million in 2004 and $157.8 million in 2003. These amounts relate to IPP contracts and do not include contractual commitments related to CL&P's TSO or standard offer.

Hydro-Quebec: Along with other New England utilities, CL&P has entered into an agreement to support transmission and terminal facilities 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 $12 million in 2005, $13.5 million in 2004 and $14.4 million in 2003.

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

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

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


(Millions of Dollars)	2006	2007	2008	2009	2010	Thereafter
VYNPC	$ 17.0	$ 16.3	$ 16.5	$ 18.0	$ 17.3	$ 22.0
Electricity procurement contracts	211.5	212.5	200.5	170.6	148.9	745.5
Hydro-Quebec	13.3	12.8	12.7	12.5	12.5	124.1
Transmission business project commitments	173.8	7.0	7.0	7.0	-	-
Yankee Companies FERC-approved billings, subject to refund	64.2	51.2	44.3	42.1	41.4	-
Totals	$479.8	$299.8	$281.0	$250.2	$220.1	$891.6

Deferred Contractual Obligations

FERC Proceedings: In 2003, CYAPC increased the estimated decommissioning and plant closure costs for the period 2000 through 2023 by approximately $395 million over the April 2000 estimate of $436 million approved by the FERC in a 2000 rate case settlement. The revised estimate reflects the increases in the projected costs of spent fuel storage, increased security and liability and property insurance costs, and the fact that CYAPC is now self performing all work to complete the decommissioning of the plant due to the termination of the decommissioning contract with Bechtel Power Corporation (Bechtel) in July of 2003. CL&P's share of CYAPC's increase in decommissioning and plant closure costs is approximately $136 million. On July 1, 2004, CYAPC filed with the FERC for recovery seeking to increase its annual decommissioning collections from $16.7 million to $93 million for a six-year period beginning on January 1, 2005. On August 30, 2004, the FERC issued an order accepting the rates, with collection beginning on February 1, 2005, subject to refund.

Spent Nuclear Fuel Litigation: CYAPC, YAEC and MYAPC (Yankee Companies) also commenced litigation in 1998 charging that the federal government breached contracts it entered into with each company in 1983 under the Act. Under the Act, the DOE was to begin removing spent nuclear fuel from the nuclear plants of the Yankee Companies no later than January 31, 1998 in return for payments by each company into the nuclear waste fund. No fuel has been collected by the DOE, and spent nuclear fuel is stored on the sites of the Yankee Companies' plants. The Yankee Companies collected the funds for payments into the nuclear waste fund from wholesale utility customers under FERC-approved contract rates. The wholesale utility customers in turn collect these payments from their retail electric customers. The Yankee Companies' individual damage claims attributed to the government's breach ranging between $523 million and $543 million are specific to each plant and include incremental storage, security, construction and other costs through 2010. The CYAPC damage claim

ranges from $186 million to $198 million, the YAEC damage claim ranges from $177 million to $185 million and the MYAPC damage claim is $160 million. The DOE trial ended on August 31, 2004 and a verdict has not been reached. Post-trial findings of facts and final briefs were filed by the parties in January of 2005. The Yankee Companies' current rates do not include an amount for recovery of damages in this matter. Management can predict neither the outcome of this matter nor its ultimate impact on CL&P.

YAEC: In November of 2005, YAEC established an updated estimate of the cost of completing the decommissioning of its plant resulting in an increase of approximately $85 million. CL&P's share of the increase in estimated costs is $20.8 million. This estimate reflects the cost of completing site closure activities from October of 2005 forward and storing spent nuclear fuel and other high level waste on site until 2020, when it is assumed to be removed by the DOE. This estimate projects a cost of $192.1 million for the completion of decommissioning and long-term fuel storage. To fund these costs, on November 23, 2005, YAEC submitted an application to the FERC to increase YAEC’s wholesale decommissioning charges. The DPUC and the Massachusetts attorney general protested these increases. On January 31, 2006, the FERC issued an order accepting the rate increase, effective February 1, 2006, subject to refund after hearings and settlement judge proceedings. The hearings have been suspended pending settlement discussions between YAEC, the FERC and other intervenors in the case. CL&P has a 24.5 percent ownership interest in YAEC and can predict neither the outcome of this matter nor its ultimate impact on CL&P.

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 of its subsidiaries 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 recovery of congestion charges incurred by NRG prior to the implementation of standard market design (SMD) on March 1, 2003, which is still pending before the court, 2) the recovery of CL&P's station service billings from NRG, which is currently subject of an arbitration, and 3) the recovery of CL&P’s expenditures that were incurred related to an NRG subsidiary’s generating plant construction project has ceased. While it is unable to determine the ultimate outcome of these issues, management does not expect their resolution will have a material adverse effect on CL&P's consolidated financial condition or results of operations.

6. 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 price for those issues or similar issues. Adjustable rate securities are assumed to have a fair value equal to their carrying value. The carrying amounts of CL&P’s financial instruments and the estimated fair values are as follows:


	At December 31, 2005
(Millions of Dollars)	Carrying Amount	Fair Value
Preferred stock not subject to mandatory redemption	$116.2	$ 98.5
Long-term debt -
First mortgage bonds	619.8	649.2
Other long-term debt	640.8	655.7
Rate reduction bonds	856.5	912.9


	At December 31, 2004
(Millions of Dollars)	Carrying Amount	Fair Value
Preferred stock not subject to mandatory redemption	$116.2	$ 101.4
Long-term debt -
First mortgage bonds	419.8	470.1
Other long-term debt	634.3	652.6
Rate reduction bonds	995.2	1,074.9

Other long-term debt includes $216.9 million and $210.4 million of fees and interest due for spent nuclear fuel disposal costs at December 31, 2005 and 2004, respectively.

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

7. 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. The provisions of these lease agreements generally provide for renewal options. Certain lease agreements contain contingent lease payments. The contingent lease payments are based on various factors, such as, the commercial paper rate plus a credit spread or the consumer price index.

Capital lease rental payments were $3 million in both 2005 and 2004 and $3.1 million in 2003. Interest included in capital lease rental payments was $1.8 million in both 2005 and 2004 and $2 million in 2003. Capital lease asset amortization was $1.2 million in both 2005 and 2004 and $1.1 million in 2003.

Operating lease rental payments charged to expense were $20 million in 2005, $14.7 million in 2004 and $11.9 million in 2003. The capitalized portion of operating lease payments was approximately $6.2 million, $4.2 million, and $3.7 million for the years ended December 31, 2005, 2004, and 2003, respectively.

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


	Capital Leases	Operating Leases
2006	$ 2.4	$ 19.5
2007	2.4	18.4
2008	2.1	15.5
2009	2.0	11.0
2010	1.5	9.2
Thereafter	16.6	26.5
Future minimum lease payments	27.0	$100.1
Less amount representing interest	13.5
Present value of future minimum lease payments	$13.5

8. Dividend Restrictions

The Federal Power Act and certain state statutes limit the payment of dividends by CL&P to its retained earnings balance. At December 31, 2005, retained earnings available for payment of dividends is restricted to $382.6 million.

9. Accumulated Other Comprehensive Income/(Loss)

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


(Millions of Dollars)	December 31, 2004	Current Period Change	December 31, 2005
Unrealized gains on securities	$ 0.1	$ -	$ 0.1
Minimum supplemental executive retirement pension liability adjustments	(0.5)	0.1	(0.4)
Accumulated other comprehensive (loss)/income	$(0.4)	$0.1	$(0.3)


(Millions of Dollars)	December 31, 2003	Current Period Change	December 31, 2004
Unrealized gains on securities	$ 0.1	$ -	$ 0.1
Minimum supplemental executive retirement pension liability adjustments	(0.4)	(0.1)	(0.5)
Accumulated other comprehensive loss	$(0.3)	$(0.1)	$(0.4)

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


(Millions of Dollars)	2005	2004	2003
Unrealized gains on securities	$ -	$ -	$(0.1)
Minimum supplemental executive retirement pension liability adjustments	(0.1)	0.1	0.3
Accumulated other comprehensive (loss)/income	$(0.1)	$ 0.1	$ 0.2

The unrealized gains on securities above relate to $2 million and $1.9 million of Supplemental Executive Retirement Plan (SERP) securities at December 31, 2005 and 2004, respectively, that are included in prepayments and other on the accompanying consolidated balance sheets.

10. Preferred Stock Not Subject to Mandatory Redemption

Details of preferred stock not subject to mandatory redemption are as follows (in millions except in redemption price and shares):


Description	December 31, 2005 Redemption Price	Shares Outstanding at December 31, 2005 and 2004	December 31,
Description	December 31, 2005 Redemption Price	Shares Outstanding at December 31, 2005 and 2004	2005	2004
$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

11. Long-Term Debt

Details of long-term debt outstanding are as follows:


At December 31,	2005	2004
	(Millions of Dollars)
First Mortgage Bonds:
7.875% Series D due 2024	$ 139.8	$ 139.8
4.800% Series A due 2014	150.0	150.0
5.750% Series B due 2034	130.0	130.0
5.000% Series A due 2015	100.0	-
5.625% Series B due 2035	100.0	-
Total First Mortgage Bonds	619.8	419.8
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	1,043.7	843.7
Fees and interest due for spent nuclear fuel disposal costs	216.9	210.4
Less amounts due within one year	-	-
Unamortized premium and discount, net	(1.7)	(1.2)
Long-term debt	$1,258.9	$1,052.9

There are no cash sinking fund requirements or debt maturities for the years 2006 through 2010.

Essentially, all utility plant of CL&P is subject to the liens of the company'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 their first mortgage bond indentures.

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

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. CL&P currently is and expects to remain in compliance with these covenants.

On April 7, 2005, CL&P issued $100 million of First Mortgage Bonds (the Series A Bonds) with a fixed coupon of 5.00 percent and a maturity of April 1, 2015. The company also issued $100 million of First Mortgage Bonds (the Series B Bonds) with a fixed coupon of 5.625 percent and a maturity of April 1, 2035. The proceeds of both issuances were used to refinance the company's short-term borrowings, which were previously incurred to fund transmission and distribution capital expenditures.

12. Segment Information

Segment information related to the distribution and transmission businesses for CL&P for the years ended December 31, 2005, 2004, and 2003 is as follows (in millions of dollars):


	For the Year Ended December 31, 2005
	Distribution	Transmission	Totals
Operating revenues	$3,353.7	$112.7	$3,466.4
Depreciation and amortization	(293.5)	(17.7)	(311.2)
Other operating expenses	(2,899.9)	(45.7)	(2,945.6)
Operating income	160.3	49.3	209.6
Interest expense, net of AFUDC	(108.5)	(11.5)	(120.0)
Interest income	2.9	0.4	3.3
Other income/(loss), net	35.6	(1.5)	34.1
Income tax expense	(26.2)	(6.0)	(32.2)
Net income	64.1	30.7	94.8
Total assets (1)	$5,765.1	$ -	$5,765.1
Cash flows for total investments in plant	$ 236.6	$207.8	$ 444.4


	For the Year Ended December 31, 2004
	Distribution	Transmission	Totals
Operating revenues	$2,738.8	$ 94.1	$2,832.9
Depreciation and amortization	(238.8)	(15.4)	(254.2)
Other operating expenses	(2,314.7)	(45.1)	(2,359.8)
Operating income	185.3	33.6	218.9
Interest expense, net of AFUDC	(101.1)	(8.9)	(110.0)
Interest income	3.9	0.2	4.1
Other income/(loss), net	21.1	(0.6)	20.5
Income tax expense	(41.0)	(4.5)	(45.5)
Net income	$ 68.2	$ 19.8	$ 88.0
Total assets (1)	$ 5,306.9	$ -	$5,306.9
Cash flows for total investments in plant	$ 254.7	$ 134.6	$ 389.3


	For the Year Ended December 31, 2003
	Distribution	Transmission	Totals
Operating revenues	$2,627.0	$77.5	$2,704.5
Depreciation and amortization	(299.8)	(13.9)	(313.7)
Other operating expenses	(2,166.8)	(35.3)	(2,202.1)
Operating income	160.4	28.3	188.7
Interest expense, net of AFUDC	(108.1)	(2.5)	(110.6)
Interest income	1.9	0.1	2.0
Other income/(loss), net	7.6	(0.7)	6.9
Income tax expense	(10.0)	(8.1)	(18.1)
Net income	$ 51.8	$17.1	$ 68.9
Total assets (1)	$5,206.9	$ -	$5,206.9
Cash flows for total investments in plant	$ 255.9	$62.6	$ 318.5

(1) Information for segmenting total assets between distribution and transmission is not available at December 31, 2005 or 2004. These distribution and transmission assets are disclosed in the distribution columns above.


Consolidated Quarterly Financial Data (Unaudited)
	Quarter Ended (a) (b)
(Thousands of Dollars)	March 31,	June 30,	September 30,	December 31,
2005
Operating Revenues	$838,901	$797,568	$952,444	$877,507
Operating Income	$ 62,280	$ 45,057	$ 60,195	$ 42,019
Net Income	$ 25,143	$ 11,053	$ 26,073	$ 32,576

2004
Operating Revenues	$748,690	$679,080	$725,532	$679,622
Operating Income	$ 63,584	$ 48,279	$ 63,747	$ 43,280
Net Income	$ 26,223	$ 17,255	$ 21,684	$ 22,854


Selected Consolidated Financial Data (Unaudited)
(Thousands of Dollars)	2005	2004	2003	2002	2001
Operating Revenues	$3,466,420	$2,832,924	$2,704,524	$2,507,036	$2,646,123
Net Income	94,845	88,016	68,908	85,612	109,803
Cash Dividends on Common Stock	53,834	47,074	60,110	60,145	60,072
Property, Plant and Equipment, net (c)	3,166,692	2,824,877	2,561,898	2,332,693	2,029,173
Total Assets (d)	5,765,072	5,306,913	5,206,894	4,786,083	4,727,727
Rate Reduction Bonds	856,479	995,233	1,124,779	1,245,728	1,358,653
Long-Term Debt (e)	1,258,883	1,052,891	830,149	827,866	824,349
Preferred Stock Not Subject to Mandatory Redemption	116,200	116,200	116,200	116,200	116,200
Obligations Under Capital Leases (e)	13,488	14,093	14,879	15,499	16,040

(a)

Certain reclassifications of prior years' data have been made to conform with the current year's presentation.

(b)

Quarterly operating income amounts differ from those previously reported as a result of the change in classification of certain costs that were not recoverable from regulated customers. These amounts, previously presented in other income, net, have been reclassified to other operation expenses and are summarized as follows (thousands of dollars):


Quarter Ended	2005	2004
March 31,	$157	$697
June 30,	873	887
September 30,	851	1,191

(c)

Amount includes construction work in progress.

(d)

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

(e)

Includes portions due within one year.


Consolidated Statistics (Unaudited)
	2005	2004	2003	2002	2001
Revenues: (Thousands)
Residential	$1,440,142	$1,155,492	$1,151,707	$1,028,425	$ 991,946
Commercial	1,170,038	939,579	960,678	874,713	855,348
Industrial	327,598	275,730	290,526	274,228	285,479
Other Utilities	344,650	295,833	322,955	271,484	420,664
Streetlighting and Railroads	37,054	31,897	35,358	33,788	33,356
Miscellaneous	146,938	134,393	(56,700)	24,398	59,330
Total	$3,466,420	$2,832,924	$2,704,524	$2,507,036	$2,646,123
Sales: (kWh - Millions)
Residential	10,760	10,305	10,359	9,699	9,340
Commercial	10,307	9,922	9,829	9,644	9,460
Industrial	3,501	3,623	3,630	3,707	3,850
Other Utilities	4,179	5,375	5,885	6,281	9,709
Streetlighting and Railroads	298	298	298	292	286
Total	29,045	29,523	30,001	29,623	32,645
Customers: (Average)
Residential	1,078,723	1,071,249	1,058,247	1,048,096	1,050,633
Commercial	108,558	108,865	104,750	103,408	95,782
Industrial	3,976	4,078	3,989	4,035	4,028
Other	2,630	2,694	2,643	2,768	2,791
Total	1,193,887	1,186,886	1,169,629	1,158,307	1,153,234
Average Annual Use Per Residential Customer (kWh)	9,974	9,620	9,790	9,244	8,884
Average Annual Bill Per Residential Customer	$1,335.02	$1,078.40	$1,089.63	$979.86	$943.48
Average Revenue Per kWh:
Residential	13.38¢	11.21¢	11.13¢	10.60¢	10.62¢
Commercial	11.35	9.47	9.77	9.07	9.04
Industrial	9.36	7.61	8.00	7.40	7.42