CL&P 2006 Annual Report

Exhibit 13.1

2006 Annual Report
The Connecticut Light and Power Company

Management’s Discussion and Analysis

Financial Condition and Business Analysis

Executive Summary

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

Results:

In 2006, The Connecticut Light and Power Company (CL&P or the company) reported earnings of $200 million in 2006 compared to $94.8 million in 2005 and $88 million in 2004. Included in earnings were transmission earnings of $48.1 million, $30.7 million and $19.8 million in 2006, 2005 and 2004, respectively, and distribution earnings of $151.9 million, $64.1 million and $68.2 million in 2006, 2005 and 2004, respectively. These earnings are stated before $5.5 million of preferred dividends in each year, including $4.3 million for distribution and $1.2 million for transmission.

In 2006, CL&P recorded a reduction in income tax expense of $74 million, pursuant to a private letter ruling (PLR) received from the Internal Revenue Service (IRS). Excluding the PLR, earnings at the distribution business totaled $77.9 million in 2006, compared with earnings of $64.1 million in 2005.

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

Legislative, Legal and Regulatory Items:

As a result of a regulatory decision in late 2003, CL&P distribution rates rose by $11.9 million annually on January 1, 2006 and an incremental $7 million annually on January 1, 2007. As a result of CL&P's transmission cost tracking mechanism, CL&P's retail transmission revenues rose by $21 million in the first half of 2006 and by an incremental $6 million annually on July 1, 2006.

On October 31, 2006, the Federal Energy Regulatory Commission (FERC) issued its decision on the return on equity (ROE) and incentives for the New England transmission owners. On a going forward basis, CL&P's transmission capital program will be largely comprised of regional infrastructure that is included within the regional planning process. Over 90 percent of the company's projected $2 billion capital program for 2007 through 2011 is expected to be in this category and is expected to earn the 12.4 percent ROE for regional infrastructure projects as opposed to the 10.9 percent base ROE.

In 1998, the Connecticut Yankee Atomic Power Company (CYAPC), the Yankee Atomic Electric Company (YAEC) and the Maine Yankee Atomic Power Company (MYAPC) (collectively, the Yankee Companies) filed separate complaints against the United States Department of Energy (DOE) in the United States Court of Federal Claims (Court of Federal Claims) seeking monetary damages resulting from the DOE's failure to begin accepting spent nuclear fuel. In a ruling released on October 4, 2006, the Court of Federal Claims held that the DOE was liable for damages to CYAPC for $34.2 million through 2001, YAEC for $32.9 million through 2001 and MYAPC for $75.8 million through 2002. CL&P owns 34.5 percent of CYAPC, 24.5 percent of YAEC and 12 percent of MYAPC. In December of 2006 the DOE appealed the ruling. The refund to CL&P of any damages that may be recovered from the DOE is established in the Yankee Companies' FERC-approved rate settlement agreements, although implementation will be subject to the final determination of the FERC. CL&P expects to pass any recovery onto its customers. As such, no earnings are expected to result from the court decision.

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

Liquidity:

On June 7, 2006, CL&P issued $250 million of 30-year first mortgage bonds with a coupon rate of 6.35 percent.

CL&P’s cash capital expenditures totaled $567.2 million in 2006, compared with $444.4 million in 2005.

CL&P projects capital expenditures of approximately $3.4 billion from 2007 through 2011, including $860 million in 2007, $270 million for distribution and $590 million for transmission. Over the five-year period, approximately $1.3 billion is projected to be spent on distribution and approximately $2 billion on transmission.

Cash flows from operations decreased by $45.9 million from $297.3 million in 2005 to $251.4 million in 2006. Items impacting cash flows were payments to Yankee companies for estimated decommissioning and closure costs, regulatory refund payments, repayment of amounts under the CL&P receivables facility and income tax payments.

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).

In 2006, CL&P earned $200 million, compared to $94.8 million in 2005 and $88 million in 2004. These results include transmission earnings of $48.1 million, $30.7 million and $19.8 million in 2006, 2005 and 2004, respectively, and distribution earnings of $151.9 million, $64.1 million and $68.2 million in 2006, 2005 and 2004, respectively. These earnings are stated before $5.5 million of preferred dividends in each year, including $4.3 million for distribution and $1.2 million for transmission. The increase in 2006 CL&P distribution earnings is due primarily to a PLR that reduced CL&P’s 2006 income tax expense by $74 million. CL&P’s 2006 distribution earnings also include the recognition of an after-tax deferred gain of $7.7 million related to generation assets CL&P previously sold to its affiliate, Northeast Generation Company (NGC). This deferred gain was being recognized on a CL&P stand-alone basis over the life of the generation assets. The remainder was recognized in 2006 as a result of the sale of NU’s competitive generation business to a third party.

Excluding the impact of these items, CL&P’s distribution business earned $70.2 million in 2006, or an increase of $6.1 million when compared to 2005. This increase was due to an $11.9 million distribution rate increase that took effect on January 1, 2006, the settlement of a tax appeal with the State of Connecticut, and the absence of employee termination and benefit curtailment charges that were recorded in 2005. These factors were partially offset by a 4.9 percent decline in sales, increased storm-related expenses, and higher interest expense. CL&P’s regulatory return on equity (Regulatory ROE) for 2006 was approximately 7.5 percent compared to its allowed ROE of 9.85 percent. In 2007, CL&P expects its ROE to be between 6 percent and 6.5 percent as a result of higher operating expenses being only partially offset by a $7 million distribution rate increase that took effect on January 1, 2007.

The increase in CL&P's transmission earnings in 2006 is due to higher levels of investment in the transmission system, partially offset by the October 31, 2006 FERC ROE decision.

A summary of changes in CL&P electric kilowatt-hour (KWH) sales for 2006 as compared to 2005 on an actual and weather normalized basis is as follows:


	Percentage Decrease	Weather Normalized Percentage Decrease
Residential	(6.6)%	(2.1)%
Commercial	(3.0)%	(1.5)%
Industrial	(5.6)%	(4.8)%
Other	(4.7)%	(4.7)%
Total	(4.9)%	(2.3)%

Electric sales in 2006 declined due to lower use per customer as a result of a combination of milder summer and winter weather in 2006, compared with 2005, and customer reaction to higher energy prices. CL&P forecasts retail sales growth for the period 2007 through 2011 to be 1.1 percent.

Liquidity

Cash flows from operations decreased by $45.9 million from $297.3 million in 2005 to $251.4 million in 2006. Several items impacting operating cash flows in 2006 are as follows:

Payments totaling $61.3 million were made to CYAPC, MYAPC and YAEC for decommissioning and closure costs. These payments are expected to decline in future years and are expected to total $29.4 million in 2007.

Net regulatory refunds paid in the amount of $80.9 million related to amounts refunded to CL&P’s ratepayers. No such significant CL&P refunds are expected for 2007 at this time.

$80 million of outstanding sales under CL&P’s sale of receivables facility were repaid in 2006 and included as an operating cash outflow. In addition, CL&P's accounts payable increased due to higher prices. This had an approximately $31 million positive impact on operating cash flows.

A federal income tax payment of approximately $20 million related to CL&P’s 2005 tax return which was made in the first quarter of 2006.

CL&P is party to a $400 million credit line which expires on 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, 2006 and 2005, CL&P had no borrowings outstanding under this facility.

In addition to its revolving credit facility, CL&P has an arrangement with a financial institution under which CL&P can sell up to $100 million of accounts receivable and unbilled revenues. There were no amounts outstanding under that facility at December 31, 2006. For more information regarding the sale of receivables, see Note 1K, "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- with a stable outlook, by Moody’s Investors Service, Standard & Poor’s and Fitch Ratings, respectively.

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

CL&P’s cash position is expected to change in 2007. In the first quarter of 2007, the company will pay approximately $170 million in federal and state taxes due primarily to the tax gain on the sale of the competitive generation business.

The Federal Power Act limits the payment of dividends by CL&P to its retained earnings balance. In addition, certain state statues may impose additional limitations on CL&P. CL&P also has a revolving credit agreement that imposes a leverage restriction.

Cash capital expenditures included on the accompanying consolidated statements of cash flows and described in the liquidity section of this management's discussion and analysis do not include cost of removal, the allowance for funds used during construction (AFUDC) related to equity funds, and the capitalized portion of pension expense or income. CL&P's cash capital expenditures totaled $567.2 million in 2006, compared with $444.4 million in 2005 and $389.3 million in 2004. The increase in CL&P’s cash capital expenditures was primarily the result of higher transmission capital expenditures. For information regarding 2007 through 2011 projected capital expenditures, see "Business Development and Capital Expenditures," included in this Management's Discussion and Analysis.

CL&P is forecasting 2007 capital expenditures of approximately $862 million, compared with forecasted net cash flows from operations of between $100 million and $150 million. As a result, the company expects that it will need to borrow on its credit facility in 2007 and expects to issue approximately $500 million of new debt in 2007. CL&P expects to fund approximately 60 percent 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

CL&P’s capital expenditures including cost of removal, AFUDC, and the capitalized portion of pension expense or income, totaled $625.9 million in 2006, compared with $469.9 million in 2005, and $387.5 million in 2004.

Transmission: Transmission capital expenditures were $415.6 million, $215.3 million, and $132.7 million for the years ended December 31, 2006, 2005, and 2004, respectively. Most of the increase in transmission capital expenditures in 2006 when compared to 2005 and 2004 was due to construction of transmission projects in southwest Connecticut.

Under CL&P’s FERC-approved tariffs, transmission projects enter rate base once they enter commercial operation. Additionally, 50 percent of CL&P’s capital expenditures on its four major transmission projects in southwest Connecticut enter rate base during the construction period with the remainder entering rate base once the projects are complete. At the end of 2006, CL&P’s approximate transmission rate base was approximately $840 million. A summary of projected year end transmission rate base is as follows (millions of dollars):


	Year
		2007		2008		2009		2010	2011
Transmission Rate Base	$	1,173	$	1,512	$	2,117	$	2,218	$	2,461

The increase in transmission rate base is driven by the need to improve the capacity and reliability of NU's regulated transmission system.

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

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

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

A 69-mile, 115 KV/345 KV transmission project from Middletown to Norwalk, Connecticut on which CL&P has commenced site work. CL&P has received the Connecticut Department of Environmental Protection's (DEP) and the United States Army Corps of

Engineers’ permits for the project but still requires CSC review of certain detailed construction plans. Although this project is currently expected to be completed by the end of 2009, opportunities to optimize schedule performance may result in an earlier completion date. This project is currently 16 percent complete and CL&P's portion of this project is estimated to cost approximately $1.05 billion. At December 31, 2006, CL&P has capitalized $186.4 million associated with this project;

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

The replacement of the existing 138 KV undersea cable between Connecticut and Long Island, for which design and engineering work for the project is complete, and cable manufacturing commenced in mid-January of 2007. On October 1, 2004, CL&P and the Long Island Power Authority (LIPA) jointly filed plans with the DEP to replace an 11-mile 138 KV undersea electric transmission line between Norwalk and Northport - Long Island, New York, consistent with a comprehensive settlement agreement reached on June 24, 2004. CL&P and LIPA each own approximately 50 percent of the line. CL&P's portion of the project is estimated to cost $72 million. Final permits are expected by mid-2007 with marine construction activities commencing in October of 2007. The project in-service date is expected to be in 2008. At December 31, 2006, CL&P has capitalized $16.9 million associated with this project.

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

As part of a larger regional system plan, NU, ISO-NE and National Grid have begun planning upgrades to the transmission system connecting Massachusetts, Rhode Island and Connecticut in a comprehensive study called the Southern New England Transmission Reinforcement (SNETR) Project. That study has led to the identification of three interdependent NU projects that work together to address the region's transmission needs: the Greater Springfield Reliability Project, the Central Connecticut Reliability Project, and the Interstate Reliability Project. Together, these three projects, along with National Grid’s Rhode Island Reliability Project, are referred to as the New England East-West Solution (NEEWS). NU and National Grid have not yet completed a detailed estimate of the total cost for these upgrades, but NU estimates that its share of these projects may range from $1.1 billion to $1.4 billion of which approximately $550 million is included in CL&P’s $2 billion 2007 through 2011 capital budget. NU and National Grid have entered into a formal agreement to plan and permit these projects.

Distribution: In December of 2003, the DPUC approved in rates $900 million of distribution capital expenditures for CL&P from 2004 through 2007. Those expenditures are intended to improve the reliability of the distribution system and to meet growth requirements on the distribution system. In 2006, CL&P’s distribution capital expenditures were $210.3 million, compared with $254.6 million in 2005 and $254.8 million in 2004. In 2007, CL&P projects an increase in distribution capital expenditures to $270 million.

A summary of projected year end distribution rate base is as follows (millions of dollars):


	Year
		2007		2008		2009		2010	2011
Distribution Rate Base	$	1,964	$	2,083	$	2,220	$	2,359	$	2,466

Several factors may impact CL&P’s distribution rate base amounts above, including the level and timing of capital expenditures and plant placed in service, regulatory approval of rate increases and other factors.

CL&P projects a total of approximately $3.4 billion of capital expenditures from 2007 through 2011. A summary of these estimated capital expenditures for CL&P’s transmission and distribution businesses for 2007 through 2011 is as follows (millions of dollars):


	Year
		2007		2008		2009		2010	2011		Totals
Transmission	$	590	$	517	$	343	$	231	$	333	$	2,014
Distribution		270		261		266		270		279		1,346
	$	860	$	778	$	609	$	501	$	612	$	3,360

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

Transmission Access and FERC Regulatory Changes

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

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

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

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


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

On a going forward basis, CL&P's transmission capital program will be largely comprised of regional infrastructure that is included within the regional planning process. Over 90 percent of the company's projected $2 billion capital program for 2007 through 2011 is expected to be in this category and is expected to earn the 12.4 percent ROE for regional infrastructure projects as opposed to the 10.9 percent base ROE.

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

In calculating the refunds owed to customers as a result of this FERC ROE decision, the New England Transmission Owners (NETOs) applied the "last clean rate" doctrine. The doctrine provides that FERC may not order refunds down to the rate level determined in the rate proceeding but can only order refunds down to the "last clean rate" authorized by FERC. This creates a refund floor for the locked-in period from February 1, 2005 to October 31, 2006. During this locked-in period, the refund floor is the higher of the ROE level established by FERC’s October 31, 2006 decision or the previously effective ROE level for CL&P. In CL&P’s case, the "last clean rate" was 11 percent and as such, refunds for the locked-in period will be refunded to this 11 percent floor. Since prior to this ROE decision the transmission business assumed an ROE of 11.5 percent for the purpose of revenue recognition, the cumulative impact from February 1, 2005 to CL&P's transmission 2006 earnings was approximately $2.3 million, net of tax. As of December 31, 2006, a total regulatory liability for refunds of $17.9 million has been accumulated and recorded, including interest. As a result, transmission business earnings as of November 1, 2006 include the ROEs in the FERC's October 31, 2006 order. The FERC issued an order accepting the NETO's compliance filing detailing the ROEs applicable to refunds, but several state regulators and municipal utilities claimed that the New England utilities used incorrect ROEs for the refund calculations. The impact of these claims is not expected to be material.

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

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

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

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

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

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

Legislative Matters

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

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

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

Regulatory Issues and Rate Matters

Transmission - Retail Rates: A significant portion of CL&P's transmission business revenue comes from ISO-NE charges to the distribution business of CL&P. CL&P's distribution business recovers these costs through retail rates that are charged to its retail customers. In 2005, CL&P began tracking its retail transmission revenues and expenses for recovery.

Forward Capacity Market: 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 proposing a forward capacity market (FCM) in place of the previously proposed locational installed capacity (LICAP), an administratively determined electric generation capacity pricing mechanism. The settlement agreement provided for a fixed level of compensation to generators from December 1, 2006 through May 31, 2010 without regard to location in New England, and annual forward capacity auctions, beginning in 2008, for the 1-year period

ending on May 31, 2011, and annually thereafter. According to preliminary estimates, FCM would require CL&P to pay approximately $470 million from December 1, 2006 through December 31, 2009. CL&P expects to recover these costs from its ratepayers. On June 16, 2006, the FERC approved the settlement agreement. Rehearing of this issue was sought by several parties, which was denied by the FERC on October 31, 2006. Several parties also challenged the FERC's approval of the settlement agreement and that challenge is now pending in the Court of Appeals. In addition, ISO-NE has received approval from FERC on many of the rules that implement the terms of the settlement agreement. On December 1, 2006, the settlement agreement was implemented and the payment of fixed compensation to generators began.

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

Procurement Fee Rate Proceedings: CL&P was allowed to collect a fixed procurement fee of 0.50 mills per KWH from customers who purchase Transitional Standard Offer (TSO) service through 2006. One mill is equal to one-tenth of one cent. That fee can increase to 0.75 mills per KWH if CL&P outperforms certain regional benchmarks. CL&P submitted to the DPUC its proposed methodology to calculate the variable portion (incentive portion) of the procurement fee and requested approval of $5.8 million for its 2004 incentive payment. On December 8, 2005, a draft decision was issued in this docket, which accepted the methodology as proposed by CL&P and authorized payment of the $5.8 million incentive fee. A final decision, which had been scheduled for December 28, 2005, was delayed by the DPUC, and the DPUC re-opened the docket to allow the Office of Consumer Counsel (OCC) to submit additional testimony.

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

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

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

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

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

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

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

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

Standard Service Procurement and Rates: On June 21, 2006, the DPUC approved a proposal by CL&P to issue RFPs periodically for

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

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

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

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

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

In CL&P's 2001 CTA and SBC reconciliation, and subsequently in a September 10, 2002 petition to reopen related proceedings, CL&P requested that a deferred intercompany tax liability associated with the intercompany sale of generation assets be excluded from the calculation of CTA cost of service. This liability was included as a reduction in the calculation of CTA cost of service. On September 10, 2003, the DPUC issued a final decision denying CL&P’s request and on October 24, 2003, CL&P appealed the DPUC’s final decision to the Connecticut Superior Court. On June 20, 2006, the Connecticut Superior Court denied CL&P's appeal. On November 1, 2006, the aforementioned generation assets were sold by NGC. As a result of this sale, the intercompany liability and its related decrease to revenue requirements will no longer be reflected as a component of the CTA effective with the November 1, 2006 sale date.

Transmission Tracking Mechanism: On July 6, 2005, Connecticut adopted legislation creating a mechanism to allow the DPUC to true-up, at least annually, the retail transmission charge in local electric distribution company rates based on changes in FERC-approved charges. This mechanism allows CL&P to include short-term forward-looking transmission charges in its retail transmission rate and promptly recover its transmission expenditures. On December 20, 2005, the DPUC approved CL&P’s August 1, 2005 proposal to implement the mechanism effective on July 1, 2005, which includes two adjustments annually, on January 1^st and July 1^st. On January 1, 2006, consistent with that approval, CL&P raised its retail transmission rate to collect $21 million of additional revenues over the first six months of 2006. On July 1, 2006, CL&P raised its transmission rates by an incremental $6.1 million on an annual basis. Rates effective on January 1, 2007 reflected no increase to the overall average retail transmission rate.

Deferred Contractual Obligations

CL&P has significant decommissioning and plant closure cost obligations to the Yankee Companies. The Yankee Companies collect decommissioning and closure costs through wholesale, FERC-approved rates charged under power purchase agreements with several New England utilities, including CL&P. CL&P owns 34.5 percent of CYAPC, 24.5 percent of YAEC, and 12 percent of MYAPC.

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

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

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

storage of spent fuel, a gross domestic product escalator of 2.5 percent for costs incurred after 2006, a 10 percent contingency factor for all decommissioning costs and extension of the collection period by five years. Annual collections began in January of 2007, and are reduced from the $93 million originally requested for years 2007 through 2010 to lower levels ranging from $37 million in 2007 rising to $49 million in 2015.

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

The settlement agreement also required CYAPC to forego collection of a $10 million regulatory asset that was written-off in 2006. CL&P included in 2006 earnings its 34.5 percent share of CYAPC's after-tax write-off.

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

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

MYAPC: MYAPC is collecting amounts in rates that are adequate to recover the remaining cost of decommissioning its plant, and CL&P expects to recover its respective share of such costs from its customers.

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

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

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

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

CL&P’s aggregate share of these damages would be $29 million. CL&P cannot at this time determine the timing or amount of any ultimate recovery or the credit to future storage costs that may be realized in connection with this matter.

Uranium Enrichment Litigation: In 2001, NU asserted claims against the DOE in the Court of Federal Claims for overcharges for purchases of uranium enrichment separative work units (SWUs) for CYAPC's unit and the Millstone units between 1986 and 1993 (D&D Claims). The NU case was stayed by the Court of Federal Claims while other D&D Claims cases were being litigated. Beginning in 2005, NU joined a number of other utilities in a consortium in an attempt to negotiate a settlement agreement with the DOE. In late-2006, a settlement was reached between the consortium and the DOE. The distribution of proceeds under the settlement agreement totals approximately $0.8 million for CYAPC and approximately $1.4 million for Millstone and was received on January 30, 2007. This distribution is based on the total number of SWUs purchased for CYAPC's unit and the Millstone units during the applicable period covered by the litigation. The company believes it is likely that the net proceeds from the settlement agreement will be credited to ratepayers. Prior to March 31, 2001, CL&P owned 81 percent of Millstone 1 and 2 and 52.93 percent of Millstone 3.

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 accounts receivable and unbilled revenues and has an arrangement with a highly-rated financial institution under which CRC can sell up to $100 million of an undivided interest in accounts receivable and unbilled revenues. At December 31, 2005, CRC had sold an undivided interest in its accounts receivable and unbilled revenues of $80 million to that financial institution with limited recourse. At December 31, 2006, CL&P had made no such sales.

CRC was established for the sole purpose of acquiring and selling CL&P’s accounts receivable and unbilled revenues and is included in CL&P's and NU's consolidated financial statements. On July 5, 2006, CRC renewed the bank commitment for the Receivables Purchase and Sale Agreement with CL&P and the financial institution through July 3, 2007, unless otherwise extended. CL&P’s continuing involvement with the receivables that are sold to CRC and the financial institution is limited to the servicing of those receivables.

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

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

Enterprise Risk Management

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

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates, assumptions and at times difficult, subjective or complex judgments. Changes in these estimates, assumptions and judgments, in and of themselves, could materially impact the financial statements of 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 rates are applied to customers’ use of energy to calculate their bills. In general, rates can only be changed through formal proceedings before the state regulatory commissions.

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

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 NU's wholesale transmission revenues are collected through a combination of ISO-NE FERC Electric Tariff No. 3, Open Access Transmission Tariff (RNS), and Schedule 21 - NU (LNS) to that tariff. The RNS tariff is administered by ISO-NE and is billed to all New England transmission users. RNS recovers the revenue requirements associated with facilities that are deemed to provide a regional benefit, or PTF. The RNS rate is reset on June 1^st of each year. NU's LNS rate is reset on January 1^st and June 1^st of each year and provides for a true-up to actual costs, which ensures that CL&P's transmission business recovers its total transmission revenue requirements, including the allowed ROE.

A significant portion of CL&P’s transmission business revenue comes from ISO-NE charges to the distribution business of CL&P. The distribution business recovers these costs through the retail rates that are charged to its retail customers. In 2005, CL&P began tracking its retail transmission revenues and expenses for recovery.

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 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. Such estimates are subject to adjustment when actual meter readings become available, when changes in estimating methodology occur and under other circumstances.

CL&P estimates unbilled revenues monthly using the daily load cycle (DLC) method. The DLC method allocates billed sales to the

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

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.

Derivative Accounting: The application of derivative accounting rules is complex and requires management judgment in the following respects: identification of derivatives and embedded derivatives, designation of the normal purchases and sales exception and estimating the fair value of derivatives. All of these judgments, depending upon their timing and effect, can have a significant impact on earnings.

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, 2006 and 2005, 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. At December 31, 2006, CL&P also recorded the fair value of financial transmission rights (FTR) contracts as derivative assets and liabilities. Offsetting regulatory liabilities and offsetting regulatory assets to these derivatives 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 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. Management believes 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. All material net regulatory assets are earning an equity return, except for securitized regulatory assets, which are not supported by equity. Amortization and deferrals of regulatory assets are included on a net basis in amortization expense on the accompanying consolidated statements of income. The regulatory assets not earning an equity return will be recovered over approximately 4 years.

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

The October 31, 2006 FERC decision regarding the RTO ROE and incentives for the New England transmission owners, which required the company's transmission business to adjust the 11.5 percent ROE being utilized for the purpose of revenue recognition. This adjustment resulted in a negative impact to CL&P's transmission business’ 2006 earnings of approximately $2.3 million, net of tax. Previously, management recognized revenues utilizing its best estimate of the RTO ROE since the RTO was activated on February 1, 2005.

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

A settlement agreement filed by CYAPC, the DPUC, the OCC and Maine state regulators which was approved by the FERC on November 16, 2006 and disposed of pending litigation at the FERC and the Court of Appeals, among other issues. The settlement agreement required CYAPC to forego collection of a $10 million regulatory asset that was written-off in 2006. CL&P included in 2006 earnings its 34.5 percent share of CYAPC's after-tax write-off.

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

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

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

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

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 because CL&P has the ability to influence the operating or financial decisions of the companies. 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 to an investment requires management judgment.

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

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. In addition to the Pension Plan, CL&P also participates in a PBOP Plan to provide certain health care benefits, primarily medical and dental, and life insurance benefits to retired employees. For each of these plans, the development of the benefit obligation, fair value of plan assets, funded status and net periodic benefit credit or cost is based on several significant assumptions. If these assumptions were changed, the resulting changes in benefit obligations, fair values of plan assets, funded status and net periodic expense could have a material impact on CL&P’s consolidated financial statements.

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

SFAS No. 158 requires the additional liability to be recorded with an offset to accumulated other comprehensive income in stockholders’ equity. However, because CL&P is a cost-of-service rate regulated entity under SFAS No. 71, regulatory assets were recorded in the amount of $155.8 million, as these amounts in pension expense have been and continue to be recoverable in cost-of-service, regulated rates. Regulatory accounting was also applied to the portions of the Northeast Utilities Service Company costs that support CL&P, as these amounts are also recoverable.

Pre-tax periodic pension expense for the Pension Plan totaled $2.4 million for the year ended December 31, 2006 and income of $0.6 million and $14.3 million for the years ended December 31, 2005 and 2004, respectively. The pension expense amounts exclude one-time items such as Pension Plan curtailments and termination benefits.

The pre-tax net PBOP Plan cost, excluding curtailments and termination benefits, totaled $21.6 million, $21.5 million and $18.6 million for the years ended December 31, 2006, 2005 and 2004, respectively.

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

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

Based on the current PBOP Plan provisions, 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 total PBOP benefit obligation by $13 million as of December 31, 2006 and 2005. 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, 2006, 2005 and 2004, this reduction in PBOP expense totaled approximately $1.7 million, including amortization of actuarial gains of $0.9 million and a reduction in interest cost and service cost

based on a lower PBOP benefit obligation of $0.8 million. At December 31, 2006, CL&P had a receivable for the federal subsidy in the amount of $1.3 million related to benefit payments made in 2006. The amount is expected to be funded into the PBOP Plan when received in 2007.

Based upon guidance from the federal government released in 2005, CL&P also qualifies for the federal subsidy relating to employees whose PBOP Plan obligation is "capped" under CL&P's PBOP Plan. These subsidy amounts do not reduce CL&P's PBOP Plan benefit obligation as they will be used to offset retiree contributions. CL&P realizes a tax benefit because the federal subsidy is tax exempt when it is collected and tax deductible as the amounts are contributed to the PBOP Plan. These additional subsidy benefits are also being amortized over approximately 13 years beginning in 2005. For the years ended December 31, 2006 and 2005, the additional subsidy amounts were approximately $4.6 million. For the years ended December 31, 2006, 2005 and 2004, the subsidy amounts reduced expected tax expense by $2.2 million, $2.4 million and $0.5 million, respectively.

Pension and PBOP Plan Curtailments and Termination Benefits: In December of 2005, a new program was approved providing a benefit for certain employees hired on and after January 1, 2006 providing for these employees to receive retirement benefits under a new 401(k) benefit (K-Vantage Plan) rather than under the Pension Plan. The approval of the new plan resulted in the recording of an estimated pre-capitalization, pre-tax curtailment expense of $1.3 million in 2005 for CL&P, as a certain number of employees hired before that date were expected to elect the new 401(k) benefits, resulting in a reduction in aggregate estimated future years of service under the Pension Plan. Management estimated the amount of the curtailment expense associated with this change based upon actuarial calculations and certain assumptions, including the expected level of transfers to the new 401(k) benefit. Because the predicted level of elections of the new benefit did not occur, CL&P recorded a pre-capitalization, pre-tax reduction in the curtailment expense of $0.8 million and a pre-capitalization, pre-tax increase in pension expense of $1.3 million in 2006. The increase in pension expense reflects interest on the increased PBO and amortization of increased actuarial gains and losses resulting from the inclusion of additional employees in Pension Plan calculations.

In addition, as a result of its corporate reorganization, CL&P estimated and recorded a combined pre-capitalization, pre-tax curtailment expense and related termination benefits for the Pension Plan totaling $2.3 million in 2005. Refinements to this estimate resulted in a combined pre-capitalization, pre-tax reduction in the curtailment expense and termination benefits expense of $1.3 million in 2006.

In 2004, as a result of litigation with nineteen former employees, NU was ordered by the court to modify its Pension Plan to include special retirement benefits for fifteen of these former employees retroactive to the dates of their retirement and provide increased future monthly benefit payments. CL&P recorded $1.1 million in termination benefits expense related to this litigation in 2004 and made a lump sum benefit 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 its corporate reorganization. CL&P also accrued a $0.2 million pre-tax termination benefit expense at December 31, 2005 relating to certain benefits provided under the terms of the PBOP Plan. Based on refinements to its estimates, CL&P recorded an adjustment to the curtailment and related termination benefits in 2006. This adjustment resulted in a combined pre-capitalization, pre-tax reduction in the curtailment expense and termination benefits expense of $1.5 million in 2006. There were no curtailments or termination benefits in 2004.

Long-Term Rate of Return Assumptions: In developing the expected long-term rate of return assumptions, 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 are based on certain target asset allocation assumptions and expected long-term rates of return. CL&P believes that 8.75 percent is an appropriate aggregate long-term rate of return on Pension Plan and PBOP Plan assets (life assets and non-taxable health assets) and 6.85 percent for PBOP health assets, net of tax for 2006. 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
	2006 and 2005		2006 and 2005
Asset Category	Target Asset Allocation	Assumed Rate of Return	Target Asset Allocation	Assumed Rate of Return
Equity Securities:
United States	45%	9.25%	55%	9.25%
Non-United States	14%	9.25%	11%	9.25%
Emerging markets	3%	10.25%	2%	10.25%
Private	8%	14.25%	-	-
Debt Securities:
Fixed income	20%	5.50%	27%	5.50%
High yield fixed income	5%	7.50%	5%	7.50%
Real Estate	5%	7.50%	-	-

The actual asset allocations at December 31, 2006 and 2005 approximated these target asset allocations. 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 4A, "Employee Benefits - 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.

Discount Rate: The discount rate that is utilized in determining future pension and PBOP obligations is based on a yield-curve approach where each cash flow related to the Pension Plan, SERP or PBOP Plan liability stream is discounted at an interest rate specifically applicable to the timing of the cash flow. The yield curve is developed from the top quartile of AA rated Moody's and S&P's bonds without callable features outstanding at December 31, 2006. This process calculates the present values of these cash flows and calculates the equivalent single discount rate that produces the same present value for future cash flows. The discount rates determined on this basis are 5.90 percent for the Pension Plan, SERP and 5.80 percent for the PBOP Plan at December 31, 2006. Discount rates used at December 31, 2005 were 5.80 percent for the Pension Plan and 5.65 percent for the PBOP Plan.

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


	Pension Plan				SERP				Postretirement Plan
Year	Expected Contributions		Forecasted Income		Expected Contributions		Forecasted Expense		Expected Contributions		Forecasted Expense
2007	$	-	$	(11.1)		N/A	$	0.3	$	16.8	$	16.8
2008	$	-	$	(15.9)		N/A	$	0.3	$	15.5	$	15.5
2009	$	-	$	(22.4)		N/A	$	0.3	$	14.3	$	14.3

Future actual pension and postretirement expense will depend on future investment performance, changes in future discount rates and various other factors related to the populations participating in the plans and amounts capitalized. Beginning in 2007, CL&P will make an additional contribution to the PBOP Plan for the amounts received from the federal Medicare subsidy. This amount is estimated at $1.3 million for 2007.

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


	At December 31,
	Pension Plan Cost				SERP Cost				Postretirement Plan Cost
Assumption Change		2006		2005	2006		2005		2006		2005
Lower long-term rate of return	$	4.8	$	4.5		N/A		N/A	$	0.5	$	0.3
Lower discount rate	$	4.7	$	5.6	$	0.03	$	0.03	$	0.3	$	0.4
Lower compensation increase	$	(2.5)	$	(2.8)	$	(0.01)	$	(0.01)		N/A		N/A

Plan Assets: The market-related value of the Pension Plan assets has increased by $112.9 million to $1,103.6 million at December 31, 2006. The PBO for the Pension Plan has also increased by $1.2 million to $860.5 million at December 31, 2006. These changes have changed the funded status of the Pension Plan on a PBO basis from an overfunded position of $131.4 million at December 31, 2005 to an overfunded position of $243.1 million at December 31, 2006. The PBO includes expectations of future employee compensation increases. The PBO includes expectations of future employee compensation increases. SFAS No. 158 requires CL&P to record the funded status of the Pension Plan based on the PBO on the consolidated balance sheet at December 31, 2006. CL&P has not made an employer contribution to the Pension Plan since 1991.

The accumulated benefit obligation (ABO) of the Pension Plan was approximately $333 million less than Pension Plan assets at December 31, 2006 and approximately $221 million less than Pension Plan assets at December 31, 2005. The ABO is the obligation for employee service and compensation provided through December 31^st.

The value of PBOP Plan assets has increased from $85.1 million at December 31, 2005 to $101.3 million at December 31, 2006. The benefit obligation for the PBOP Plan has increased from $200.7 million at December 31, 2005 to $187.1 million at December 31, 2006. These changes have changed the underfunded status of the PBOP Plan on an accumulated projected benefit obligation basis from $115.6 million at December 31, 2005 to $85.8 million at December 31, 2006. 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. At December 31, 2005, the health care cost trend assumption was reset for 2006 at 10 percent, decreasing one percentage point per year to an ultimate rate of 5 percent in 2011. The effect of increasing the health care cost trend by one percentage point would have increased service and interest cost components of the PBOP Plan cost by $0.5 million in 2006 and $0.4 million in 2005.

Income Taxes: Income tax expense is calculated in each reporting period in each of the jurisdictions in which CL&P operates. This process involves estimating actual current tax expense or benefit as well as the income tax impact of temporary differences resulting from differing treatment of items, such as timing of the deduction and expenses for tax and book accounting purposes. These differences result in deferred tax assets and liabilities that are recorded on the consolidated balance sheets. The income tax estimation process impacts all of CL&P’s segments. Adjustments made to income tax estimates can 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 $266.6 million and $227.6 million at December 31, 2006 and 2005, respectively. Regulatory agencies in certain jurisdictions in which CL&P operates require the tax effect of specific temporary differences to be "flowed through" to customers. Flow through treatment means that deferred tax expense is not recorded on the consolidated statements of income. Instead, the tax effect of the temporary difference impacts both amounts for income tax expense currently included in customers’ rates and the company’s net income. Flow through treatment can result in effective income tax rates that are significantly different than expected income tax rates. Recording deferred taxes on flow through items is required by SFAS No. 109, and the offset to the deferred tax amounts is the regulatory asset referred to above.

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

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

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

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

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

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.

For further information, see Note 5B, "Commitments and Contingencies - Environmental Matters," to the consolidated financial statements.

Asset Retirement Obligations: In March of 2005, the FASB issued FIN 47, "Accounting for Conditional Asset Retirement Obligations - an Interpretation of FASB Statement No. 143." FIN 47 requires an entity to recognize a liability for the fair value of an ARO that is conditional on a future event if the liability’s fair value can be reasonably estimated. CL&P adopted FIN 47 on December 31, 2005.

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

CL&P currently recovers amounts in rates for future costs of removal of plant assets. At December 31, 2006 and 2005, these amounts totaling $134.4 million and $139.4 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 4A, "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 for Servicing of Financial Assets: In March of 2006, the FASB issued SFAS No. 156, "Accounting for Servicing of Financial Assets - An Amendment of FASB Statement No. 140." SFAS No. 156 requires an entity to recognize a servicing asset or liability at fair value each time it undertakes an obligation to service a financial asset by entering into a servicing contract in a transfer of the servicer's financial assets that meets the requirements for sale accounting and in other circumstances. Servicing assets and liabilities may be subsequently measured through either amortization or recognition of fair value changes in earnings. SFAS No. 156 is required to be applied prospectively to transactions beginning in the first quarter of 2007. Implementation of SFAS No. 156 will not have an effect on the CL&P’s consolidated financial statements.

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

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

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

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


(Millions of Dollars)	2007		2008		2009		2010		2011		Thereafter		Totals
Long-term debt ^{(a) (b)}	$	-	$	-	$	-	$	-	$	-	$	1,293.7	$	1,293.7
Estimated interest payments on existing long-term debt^(c)		75.5		75.5		75.5		75.5		75.5		1,253.0		1,630.5
Capital leases ^{(d) (e)}		2.5		3.1		3.5		1.7		1.7		18.7		31.2
Operating leases ^{(e) (f)}		21.0		19.4		15.4		13.2		10.0		48.8		127.8
Required funding of other post- retirement benefit obligations ^(f)		16.8		15.5		14.3		13.2		12.2		-		72.0
Long-term contractual arrangements^{(e) (f)}		740.8		530.9		262.3		200.8		196.2		777.5		2,708.5
Other purchase commitments ^{(f) (g)}		667.2		-		-		-		-		-		667.2
Totals	$	1,523.8	$	644.4	$	371.0	$	304.4	$	295.6	$	3,391.7	$	6,530.9

^(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 $227.5 million and unamortized discounts of $1.8 million.

^(c)

Estimated interest payments on fixed-rate debt are calculated by multiplying the coupon rate on the debt by its scheduled notional amount outstanding for the period of measurement. Estimated interest payments on floating-rate debt are calculated by multiplying the most recent floating-rate reset on the debt by its scheduled notional amount outstanding for the period of measurement. This same rate is then assumed for the remaining life of the debt. Interest payments on debt that have an interest rate swap in place are estimated using the effective cost of debt resulting from the swap rather than the underlying interest cost on the debt, subject to the fixed and floating methodologies.

^(d)

The capital lease obligations include imputed interest of $16.9 million as of December 31, 2006.

^(e)

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.

^(f)

Amounts are not included on CL&P's consolidated balance sheets.

^(g)

Amount represents open purchase orders, excluding those obligations that are included in the long-term contractual arrangements. These payments are subject to change as certain purchase orders include estimates based on projected quantities of material and/or services that are provided on demand, the timing of which cannot be determined.

Rate reduction bond amounts are non-recourse to CL&P, have no required payments over the next five years and are not included in this table. The CL&P’s standard service contracts and default service contracts also are not included in this table. The estimated payments under interest rate swap agreements are not included in this table as the estimated payment amounts are not determinable. In addition, there are no Pension Plan contributions expected and therefore have been excluded from this table. For further information regarding 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, changes in levels or timing of capital expenditures, developments in legal or public policy doctrines, technological developments, effectiveness of risk management policies and procedures, changes in accounting standards and financial reporting regulations, fluctuations in the value of remaining electricity positions, actions of rating agencies, terrorist attacks or other intentional disruptance on domestic energy facilities and other presently unknown or unforeseen factors. Other risk factors are detailed from time to time in reports to the Securities and Exchange Commission. Management undertakes no obligation to update the information contained in any forward looking statements to reflect developments or circumstances occurring after the statement is made.

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

RESULTS OF OPERATIONS

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


Income Statement Variances	2006 over/(under) 2005				2005 over/(under) 2004
(Millions of Dollars)	Amount		Percent		Amount		Percent
Operating Revenues	$	513	15	%	$	634	22	%

Operating Expenses:
Fuel, purchased and net interchange power		458	21			447	26
Other operation		57	10			117	27
Maintenance		6	7			14	17
Depreciation		14	11			14	12
Amortization of regulatory asset, net		(71)	(a)			35	(a)
Amortization of rate reduction bonds		9	7			8	7
Taxes other than income taxes		6	4			12	8
Total operating expenses		479	15			647	25
Operating Income		34	17			(13)	(6)
Interest expense, net		(2)	(2)			10	9
Other income, net		(7)	(16)			17	61
Income before income tax expense		29	23			(6)	(5)
Income tax expense		(76)	(a)			(13)	(29)
Net income	$	105	(a)	%	$	7	8	%

(a) Percent greater than 100.

Comparison of the Year 2006 to the Year 2005

Operating Revenues

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

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

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

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

Fuel, Purchased and Net Interchange Power

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

Other Operation

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

Maintenance

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

Depreciation

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

Amortization of Regulatory (Liabilities)/Assets, Net

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

Amortization of Rate Reduction Bonds

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

Taxes Other Than Income Taxes

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

Interest Expense, Net

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

Other Income, Net

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

Income Tax Benefit

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

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 business revenues ($615 million) and higher transmission business revenues ($19 million).

The distribution business 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 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). The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections collected from customers in future periods.

The distribution component of 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.

Transmission business 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 $117 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 gross earnings tax (GET) 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 ($15 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 interest on the Millstone prior spent nuclear fuel disposal liability ($4 million), partially offset by lower rate reduction bond interest resulting from lower principal balances outstanding ($8 million).

Other Income, Net

Other income, net increased $17 million in 2005 primarily due to a higher TSO procurement fee ($6 million), a higher equity 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, and higher interest income related to the Millstone prior spent nuclear fuel disposal asset ($4 million).

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 1G, "Summary of Significant Accounting Policies – Income Taxes", to the consolidated financial statements.

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, 2006 and 2005, 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, 2006. 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, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 1G, the Company realized a $74 million reduction to income tax expense in 2006 due to a ruling that certain income tax credits and excess deferred income taxes could not be used to reduce customers’ rates following the sale of the generation business, and as discussed in Note 4, the Company adopted Statement of Financial Accounting Standard No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.


/s/	Deloitte & Touche LLP
	Deloitte & Touche LLP

Hartford, Connecticut

February 26, 2007


THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


At December 31,	2006	2005
	(Thousands of Dollars)
ASSETS

Current Assets:
Cash	$ 3,310	$ 2,301
Investments in securitizable assets	375,656	252,801
Receivables, less provision for uncollectible
accounts of $1,679 in 2006 and $1,982 in 2005	73,052	80,883
Accounts receivable from affiliated companies	1,965	17,214
Unbilled revenues	8,044	7,888
Materials and supplies	39,447	32,929
Derivative assets - current	45,031	82,578
Prepayments and other	15,945	18,003
	562,450	494,597

Property, Plant and Equipment:
Electric utility	4,557,231	3,997,652
Less: Accumulated depreciation	1,260,526	1,175,164
	3,296,705	2,822,488
Construction work in progress	337,665	344,204
	3,634,370	3,166,692

Deferred Debits and Other Assets:
Regulatory assets	1,477,375	1,357,985
Prepaid pension	243,139	315,532
Derivative assets - long-term	249,423	308,648
Other	154,537	121,618
	2,124,474	2,103,783














Total Assets	$ 6,321,294	$ 5,765,072



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,	2006	2005
	(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION

Current Liabilities:
Notes payable to affiliated companies	$ 258,925	$ 26,825
Accounts payable	326,163	253,974
Accounts payable to affiliated companies	47,906	39,755
Accrued taxes	186,647	60,531
Accrued interest	29,587	16,947
Derivative liabilities - current	4,101	477
Other	80,543	70,025
	933,872	468,534

Rate Reduction Bonds	743,899	856,479

Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	719,470	774,190
Accumulated deferred investment tax credits	24,019	85,970
Deferred contractual obligations	185,195	243,279
Regulatory liabilities	582,841	742,993
Derivative liabilities - long-term	31,923	31,774
Accrued postretirement benefits	85,768	3,411
Other	127,638	127,842
	1,756,854	2,009,459

Capitalization:
Long-Term Debt	1,519,440	1,258,883

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 2006 and 2005	60,352	60,352
Capital surplus, paid in	672,693	612,815
Retained earnings	513,344	382,628
Accumulated other comprehensive income/(loss)	4,640	(278)
Common Stockholder's Equity	1,251,029	1,055,517
Total Capitalization	2,886,669	2,430,600

Commitments and Contingencies (Note 5)

Total Liabilities and Capitalization	$ 6,321,294	$ 5,765,072



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,	2006	2005	2004
	(Thousands of Dollars)


Operating Revenues	$ 3,979,811	$ 3,466,420	$ 2,832,924

Operating Expenses:
Operation -
Fuel, purchased and net interchange power	2,603,882	2,145,834	1,698,335
Other	614,372	557,587	440,753
Maintenance	101,443	95,076	81,064
Depreciation	147,460	133,135	119,310
Amortization of regulatory (liabilities)/assets, net	(11,251)	59,632	24,294
Amortization of rate reduction bonds	126,909	118,488	110,625
Taxes other than income taxes	160,926	154,619	142,919
Total operating expenses	3,743,741	3,264,371	2,617,300
Operating Income	236,070	202,049	215,624

Interest Expense:
Interest on long-term debt	64,873	59,019	43,308
Interest on rate reduction bonds	46,692	55,796	63,667
Other interest	6,281	5,220	3,072
Interest expense, net	117,846	120,035	110,047
Other Income, Net	37,822	45,005	27,978
Income Before Income Tax (Benefit)/Expense	156,046	127,019	133,555
Income Tax (Benefit)/Expense	(43,961)	32,174	45,539
Net Income	$ 200,007	$ 94,845	$ 88,016

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Net Income	$ 200,007	$ 94,845	$ 88,016
Other comprehensive income/(loss), net of tax:
Qualified cash flow hedging instruments	4,537	-	-
Unrealized gains/(losses) on securities	17	(22)	37
Minimum SERP liability	364	120	(66)
Other comprehensive income/(loss), net of tax	4,918	98	(29)
Comprehensive Income	$ 204,925	$ 94,943	$ 87,987



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


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

Balance at January 1, 2004	6,035,205	$60,352	$326,629	$311,793	$ (347)	$ 698,427

Net income for 2004				88,016		88,016
Dividends on preferred stock				(5,559)		(5,559)
Dividends on common stock				(47,074)		(47,074)
Allocation of benefits - ESOP			(498)			(498)
Tax deduction for stock options exercised and Employee
Stock Purchase Plan disqualifying dispositions			823			823
Capital stock expenses, net			186			186
Capital contribution from NU parent			88,000			88,000
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
Dividends on preferred stock				(5,559)		(5,559)
Dividends on common stock				(53,834)		(53,834)
Allocation of benefits - ESOP			(476)			(476)
Tax deduction for stock options exercised and Employee
Stock Purchase Plan disqualifying dispositions			171			171
Capital stock expenses, net			186			186
Capital contribution from NU parent			197,794			197,794
Other comprehensive income					98	98
Balance at December 31, 2005	6,035,205	60,352	612,815	382,628	(278)	1,055,517

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



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,	2006	2005	2004
	(Thousands of Dollars)

Operating Activities:
Net income	$ 200,007	$ 94,845	$ 88,016
Adjustments to reconcile to net cash flows
provided by operating activities:
Bad debt expense	13,582	12,834	1,440
Depreciation	147,460	133,135	119,310
Deferred income taxes	(154,260)	(16,585)	102,394
Amortization of regulatory (liabilities)/assets, net	(11,251)	59,632	24,294
Amortization of rate reduction bonds	126,909	118,488	110,625
Amortization/(deferral) of recoverable energy costs	3,839	36,090	(13,242)
Pension expense/(income)	438	1,491	(6,763)
Regulatory refunds	(80,888)	(73,442)	(137,537)
Deferred contractual obligations	(61,273)	(60,444)	(35,764)
Other non-cash adjustments	(7,223)	(8,730)	(19,556)
Other sources of cash	15,728	702	18,484
Other uses of cash	(804)	(14,192)	(18,594)
Changes in current assets and liabilities:
Receivables and unbilled revenues, net	22,924	25,648	(4,201)
Materials and supplies	(6,518)	284	(1,630)
Investments in securitizable assets	(158,254)	(113,410)	27,074
Other current assets	6,786	(1,779)	(3,249)
Accounts payable	56,628	25,312	(40,893)
Accrued taxes/(taxes receivable)	126,116	61,297	(65,587)
Other current liabilities	11,421	16,097	9,327
Net cash flows provided by operating activities	251,367	297,273	153,948

Investing Activities:
Investments in plant	(567,151)	(444,384)	(389,266)
Restricted cash - LMP costs	-	-	93,630
Net proceeds from sale of property	-	21,993	-
Proceeds from sales of investment securities	2,210	1,883	1,773
Purchases of investment securities	(2,369)	(1,993)	(2,316)
Rate reduction bond escrow	(46,852)	4,651	(145)
Other investing activities	6,899	(3,573)	2,235
Net cash flows used in investing activities	(607,263)	(421,423)	(294,089)

Financing Activities:
Issuance of long-term debt	250,000	200,000	280,000
Reacquisitions and retirements of long-term debt	-	-	(59,000)
Retirement of rate reduction bonds	(112,580)	(138,754)	(129,546)
(Decrease)/increase in short-term debt	-	(15,000)	15,000
Increase/(decrease) in NU Money Pool borrowing	232,100	(63,200)	(1,100)
Capital contributions from Northeast Utilities Parent	60,756	197,794	88,000
Cash dividends on preferred stock	(5,559)	(5,559)	(5,559)
Cash dividends on common stock	(63,732)	(53,834)	(47,074)
Other financing activities	(4,080)	(604)	(786)
Net cash flows provided by financing activities	356,905	120,843	139,935
Net increase/(decrease) in cash	1,009	(3,307)	(206)
Cash - beginning of year	2,301	5,608	5,814
Cash - end of year	$ 3,310	$ 2,301	$ 5,608

Supplemental Cash Flow Information:
Cash paid/(received) during the year for:
Interest, net of amounts capitalized	$ 117,856	$ 125,249	$ 109,890
Income taxes	$ (16,364)	$ (12,761)	$ 24,915

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

Notes To Consolidated Financial Statements

Summary of Significant Accounting Policies

About The Connecticut Light and Power Company

The Connecticut Light and Power Company (CL&P or the company) is a wholly owned subsidiary of Northeast Utilities (NU). CL&P is a reporting company under the Securities Exchange Act of 1934. Until February 8, 2006, NU was registered with the Securities and Exchange Commission (SEC) as a holding company under the Public Utility Holding Company Act of 1935 (PUHCA). On February 8, 2006, PUHCA was repealed. CL&P is now registered with the Federal Energy Regulatory Commission (FERC) as a public utility holding company under PUHCA 2005. Arrangements among CL&P, other NU companies, outside agencies, and other utilities covering interconnections, interchange of electric power and sales of utility property, are subject to regulation by the FERC 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. Three other subsidiaries construct, acquire or lease some of the property and facilities used by CL&P.

At December 31, 2006 and 2005, CL&P had a long-term receivable from NUSCO in the amount of $25 million that is included in deferred debits and other assets - other on the accompanying consolidated balance sheets related to the funding of investments held by NUSCO. In addition, at December 31, 2005, CL&P had a long-term asset in the amount of $10.5 million from The Rocky River Realty Company (RRR) included in deferred debits and other assets - other on the accompanying consolidated balance sheets. This amount was paid to CL&P in 2006.

Included in the consolidated balance sheet at December 31, 2006, are accounts receivable from affiliated companies and accounts payable to affiliated companies totaling $2 million and $47.9 million, respectively, relating to transactions between CL&P and other subsidiaries that are wholly owned by NU. At December 31, 2005, these amounts totaled $17.2 million and $39.8 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 $6.1 million, $53.4 million and $611.3 million for the years ended December 31, 2006, 2005 and 2004, 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 statements of income for the years ended December 31, 2005 and 2004, the classification of expense amounts relating to costs not recoverable from regulated customers and certain other cost and income items previously included in other income, net was changed to a preferable presentation to no longer reflect these costs as they would appear for rate-making purposes. These amounts, which were reclassified to other operation expense totaled $7.5 million and $3.3 million, respectively, for the years ended December 31, 2005 and 2004. These reclassifications had no impact on the companies' results of operations, financial condition or changes in stockholders' equity.

Accounting Standards Issued But Not Yet Adopted

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

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

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 state regulatory commissions. However, 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.

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 consolidated statement of income and are assets on the consolidated balance sheets that are reclassified to accounts receivable in the following month as customers are billed. Such estimates are subject to adjustment when actual meter readings become available, when changes in estimating methodology occur and under other circumstances.

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

Transmission Revenues - Wholesale Rates: Wholesale transmission revenues are based on rates and formulas that are approved by the FERC. Most of NU's wholesale transmission revenues are collected through a combination of New England Independent System Operator (ISO-NE) FERC Electric Tariff No. 3, Open Access Transmission Tariff (RNS), and Schedule 21 - NU (LNS) to that tariff. The RNS tariff is administered by ISO-NE and is billed to all New England transmission users. RNS recovers the revenue requirements associated with facilities that are deemed to provide a regional benefit, or pool transmission facilities. The RNS rate is reset on June 1^st of each year. NU's LNS rate is reset on January 1^st and June 1^st of each year and provides for a true-up to actual costs, which ensures that CL&P's transmission business recovers its total transmission revenue requirements, including the allowed return on equity (ROE).

Transmission Revenues - Retail Rates: A significant portion of CL&P's transmission business revenues comes from ISO-NE charges to the NU distribution businesses, including CL&P. CL&P recovers these costs through the retail rates that are charged to its retail customers. In 2005, CL&P began tracking its retail transmission revenues and expenses.

Derivative Accounting

The accounting treatment for energy contracts entered into varies and depends on the intended use of the particular contract and on whether or not the contract is a derivative. Non-derivative contracts are recorded at the time of delivery or settlement 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, 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. 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. All material net regulatory assets are earning an equity return, except for securitized regulatory assets, which are not supported by equity. Amortization and deferrals of regulatory assets are included on a net basis in amortization expense on the accompanying consolidated statements of income.

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


	At December 31,
(Millions of Dollars)	2006		2005
Securitized assets	$	707.2	$	855.6
Income taxes, net		266.6		227.6
Unrecovered contractual obligations		163.7		197.7
Recoverable energy costs		3.4		7.3
CTA and SBC		100.5		-
Deferred benefit costs		155.8		-
Other regulatory assets		80.2		69.8
Totals	$	1,477.4	$	1,358.0

Additionally, CL&P had $11.1 million and $10.7 million of regulatory costs at December 31, 2006 and 2005, 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 for recovery by the applicable regulatory agency. 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 $604.5 million and $731.4 million at December 31, 2006 and 2005, respectively. CL&P used the remaining proceeds from the issuance of the rate reduction certificates to securitize a portion of its SFAS No. 109, "Accounting for Income Taxes," regulatory asset. The securitized SFAS No. 109 regulatory asset had an unamortized balance of $102.7 million and $124.2 million at December 31, 2006 and 2005, respectively.

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

Income Taxes, Net: The tax effect of temporary differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of taxable income) 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 $266.6 million and $227.6 million at December 31, 2006 and 2005, respectively. For further information regarding income taxes, see Note 1G, "Summary of Significant Accounting Policies - Income Taxes," to the consolidated financial statements.

Unrecovered Contractual Obligations: Under the terms of contracts with the Connecticut Yankee Atomic Power Company (CYAPC), Yankee Atomic Electric Company (YAEC), and Maine Yankee Atomic Power Company (MYAPC) (Yankee Companies), CL&P is responsible for its proportionate share of the remaining costs of the units, including decommissioning. A portion of these amounts, $163.7 million and $197.7 million at December 31, 2006 and 2005, respectively, are recorded as unrecovered contractual obligations. An additional portion of these obligations for CL&P was securitized in 2001 and is included in securitized regulatory assets.

Recoverable Energy Costs: Under the Energy Policy Act of 1992 (Energy Act), CL&P was assessed 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 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, 2006 and 2005, CL&P’s total D&D Assessment deferrals were $3.4 million and $7.3 million, respectively, and have been recorded as recoverable energy costs.

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

CTA and SBC: The Competitive Transition Assessment (CTA) allows CL&P to recover stranded costs, such as securitization costs associated with the rate reduction bonds, amortization of regulatory assets, and IPP over market costs. The System Benefits Charge (SBC) allows CL&P to recover certain regulatory and energy public policy costs, such as public education outreach costs, hardship protection costs, transition period property taxes, and displaced workers protection costs. At December 31, 2006, CTA undercollections totaled approximately $75.5 million whereas at December 31, 2005 CTA collections exceeded CTA costs by $26 million. The change in

the CTA balance is due primarily to refunds to customers of approximately $100 million as ordered by the DPUC and the absence of overcollections in 2006 that were previously anticipated. At December 31, 2006, SBC undercollections totaled $25 million and at December 31, 2005, SBC undercollections totaled $1.8 million. The increase in the undercollections is primarily due to an acceleration of the recovery of hardship protection costs. At December 31, 2005, the $1.8 million balance was included in the CTA, GSC and SBC regulatory liability.

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

See Note 4A, "Employee Benefits - Pension Benefits and Postretirement Benefits Other Than Pensions," for additional information regarding the implementation of SFAS No. 158.

Other Regulatory Assets: Included in other regulatory assets are the regulatory assets associated with the implementation of FIN 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143," totaling $25.8 million and $25.1 million at December 31, 2006 and 2005, respectively. These regulatory assets have not been approved for future recovery. At this time, management believes that these regulatory assets are probable of recovery.

In addition, at December 31, 2006 and 2005, other regulatory assets included $17.1 million and $18.8 million, respectively, related to losses on reacquired debt, and $36 million and $32.3 million, respectively, which offset the fair value of derivative contracts related to the procurement of energy.

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


	At December 31,
(Millions of Dollars)	2006		2005
Cost of removal	$	134.4	$	139.4
CTA, GSC and SBC		108.2		154.0
Regulatory liabilities offsetting
derivative assets		294.5		391.2
Other regulatory liabilities		45.7		58.4
Totals	$	582.8	$	743.0

Cost of Removal: CL&P currently recovers amounts in rates for future costs of removal of plant assets. These amounts, which totaled $134.4 million and $139.4 million at December 31, 2006 and 2005, respectively, are classified as regulatory liabilities on the accompanying consolidated balance sheets. This liability is included in rate base.

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

Regulatory Liabilities Offsetting Derivative Assets: The regulatory liabilities offsetting derivative assets relate to the fair value of contracts used to purchase power that will benefit ratepayers in the future. These amounts totaled $294.5 million and $391.2 million at December 31, 2006 and 2005, respectively. See Note 3, "Derivative Instruments," for further information. This liability is excluded from rate base.

Other Regulatory Liabilities: At December 31, 2006 and 2005, other regulatory liabilities included $21.6 million and $5.8 million, respectively, related to transmission refunds to be provided to customers, including $17.9 million and $4.5 million, respectively, as a result of the FERC ROE decision, and $12 million and $10.9 million, respectively, related to nuclear cost overcollections.

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 (benefit)/expense are as follows:


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

Current income taxes:
Federal	$	104.9	$	44.7	$	(50.6)
State		3.8		4.1		(6.2)
Total current		108.7		48.8		(56.8)
Deferred income taxes, net:
Federal		(69.2)		(1.8)		99.6
State		(21.5)		(12.2)		5.3
Total deferred		(90.7)		(14.0)		104.9
Investment tax credits, net		(62.0)		(2.6)		(2.6)
Total income tax (benefit)/expense	$	(44.0)	$	32.2	$	45.5

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


	For the Years Ended December 31,
	2006		2005		2004
	(Millions of Dollars)
Expected federal income tax expense	$	54.6	$	44.5	$	46.7
Tax effect of differences:
Depreciation		(1.8)		(3.9)		2.0
Investment tax credit amortization (including $59.3 million related to the PLR)		(62.0)		(2.6)		(2.6)
State income taxes, net of federal benefit		(7.4)		(5.3)		(0.2)
Excess deferred taxes - PLR		(14.7)		-		-
Deferred tax adjustment - sale to affiliate		(4.4)		-		-
Tax asset valuation reserve adjustment		(3.8)		-		-
Medicare subsidy		(2.2)		(2.4)		(0.5)
Other, net		(2.3)		1.9		0.1
Total income tax (benefit)/expense	$	(44.0)	$	32.2	$	45.5

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 separate company tax return. Subsidiaries generating tax losses are similarly paid for their losses when utilized.

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

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


	At December 31,
(Millions of Dollars)	2006		2005

Deferred tax liabilities - current:
Property tax accruals	$	27.1	$	23.8
Derivative asset		17.9		-
Total deferred tax liabilities - current		45.0		23.8
Deferred tax assets - current:
Allowance for uncollectible accounts		15.9		8.0
Other		1.6		-
Total deferred tax assets - current		17.5		8.0
Net deferred tax liabilities - current		27.5		15.8
Deferred tax liabilities - long-term:
Accelerated depreciation and other plant related differences		529.6		633.6
Regulatory deferrals		101.9		13.4
Securitized costs		36.6		44.5
Income tax gross-up		168.4		168.6
Employee benefits		94.5		139.0
Derivative assets		99.5		-
Other		20.2		7.0
Total deferred tax liabilities - long-term		1,050.7		1,006.1
Deferred tax assets - long-term:
Regulatory deferrals		194.9		158.0
Employee benefits		64.7		15.6
Income tax gross-up		21.3		28.2
Derivative liability		12.7		-
Other		37.6		30.1
Total deferred tax assets - long-term		331.2		231.9
Net deferred tax liabilities - long-term		719.5		774.2
Net deferred tax liabilities	$	747.0	$	790.0

At December 31, 2006, CL&P had state tax credit carry forwards of $11.7 million that expire between 2010 and 2011. At December 31, 2005, CL&P had state tax credit carry forwards of $14.9 million that expire between December 31, 2009 and 2010.

Property, Plant and Equipment and Depreciation

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


			At December 31,
	Average Depreciable Life		2006		2005
	(Years)		(Millions of Dollars)
Distribution		27.1	$	3,458.3	$	3,243.9
Transmission		49.4		1,098.9		753.8
Total property, plant and equipment				4,557.2		3,997.7
Less: Accumulated depreciation				(1,260.5)		(1,175.2)
Net property, plant and equipment				3,296.7		2,822.5
Construction work in progress				337.7		344.2
Total property, plant and equipment, net			$	3,634.4	$	3,166.7

The provision for depreciation on utility assets is calculated using the straight-line method based on the estimated remaining useful lives of depreciable plant in-service, adjusted for salvage value and removal costs, as approved by the appropriate regulatory agency, where applicable. Depreciation rates are applied to plant-in-service from the time it is placed in service. When plant is retired from service, the original cost of the plant, including costs of removal less salvage, is charged to the accumulated provision for depreciation. Cost of removal is classified as a regulatory liability. The depreciation rates for the several classes of electric utility plant-in-service are equivalent to a composite rate of 3.5 percent in both 2006 and 2005, and 3.4 percent in 2004.

Jointly Owned Electric Utility Plant

At December 31, 2006, CL&P owns common stock in three regional nuclear companies (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, 2006, 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 CL&P’s ownership interest in CYAPC, MYAPC and YAEC, which is included in deferred debits and other assets - other on the accompanying consolidated balance sheets and the electric distribution reportable segment, totaled $6.6 million and $19.5 million at December 31, 2006 and 2005, respectively. The decrease in the carrying value at

December 31, 2006 is primarily related to the repurchase of CYAPC's stock owned by CL&P in the amount of $9.5 million in the fourth quarter of 2006. Earnings related to these equity investments are included in other income, net on the accompanying consolidated statements of income. For further information, see Note 1O, "Summary of Significant Accounting Policies - Other Income, Net," to the consolidated financial statements.

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

Allowance for Funds Used During Construction

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)	2006			2005			2004
Borrowed funds	$	6.6		$	6.7		$	3.1
Equity funds		7.6			9.8			3.4
Totals	$	14.2		$	16.5		$	6.5
Average AFUDC rate		7.9	%		7.9	%		4.3	%

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

Sale of Customer Receivables

At December 31, 2005, CL&P had sold an undivided interest in its accounts receivable and unbilled revenue of $80 million to a financial institution with limited recourse through CRC. At December 31, 2006, there were no such sales. CRC can sell up to $100 million of an undivided interest in its accounts receivable and unbilled revenues. At December 31, 2005, the reserve requirements calculated in accordance with the Receivables Purchase and Sale Agreement was $21 million. This reserve amount was deducted from the amount of receivables eligible for sale. Concentrations of credit risk to the purchaser under this agreement with respect to the receivables are limited due to CL&P’s diverse customer base.

At December 31, 2006 and 2005, amounts sold to CRC by CL&P but not sold to the financial institution totaling $375.7 million and $252.8 million, respectively, are included as investments in securitizable assets on the accompanying consolidated balance sheets. These amounts would be excluded from CL&P’s assets in the event of CL&P’s bankruptcy. On July 5, 2006, CRC renewed the bank commitment for the Receivables Purchase and Sale Agreement with CL&P and the financial institution through July 3, 2007 to coincide with the date this agreement terminates, unless otherwise extended. CL&P’s continuing involvement with the receivables that are sold to CRC and the financial institution is limited to the servicing of those receivables.

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

See Note 1C, "Summary of Significant Accounting Policies - Accounting Standards Issued But Not Yet Adopted," for further information.

Asset Retirement Obligations

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

Because CL&P is a cost-of-service rate regulated entity, CL&P utilized regulatory accounting in accordance with SFAS No. 71, and the AROs are included in other regulatory assets at December 31, 2006 and 2005. The fair value of the AROs is included in property, plant and equipment and related accretion is recorded as a regulatory asset, with corresponding credits reflecting the ARO liabilities in deferred credits and other liabilities - other, on the accompanying consolidated balance sheets at December 31, 2006 and 2005. Depreciation of the ARO asset is also included as a regulatory asset with an offsetting amount in accumulated depreciation.

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


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


	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)

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


(Millions of Dollars)	2006
Balance at beginning of year	$	(35.9)
Liabilities incurred during the period		(4.7)
Liabilities settled during the period		1.6
Accretion		(0.2)
Change in assumptions		1.7
Revisions in estimated cash flows		1.7
Balance at end of year	$	(35.8)

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.

Other Taxes

Certain excise taxes levied by state or local governments are collected by CL&P from its customers. These excise taxes are accounted for on a gross basis with collections in revenues and payments in expenses. For the years ended December 31, 2006, 2005 and 2004, gross receipts taxes, franchise taxes and other excise taxes of $92.7 million, $88.2 million and $75.8 million, respectively, are included in operating revenues and taxes other than income taxes on the accompanying consolidated statements of income. Certain sales taxes are also collected by CL&P from its customers as agent for state and local governments and are recorded on a net basis with no impact on the accompanying consolidated statements of income.

Other Income, Net

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


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

Other Income:
Investment income	$	9.8	$	10.8	$	7.7
Equity in earnings of regional nuclear generating companies		(0.9)		1.2		0.6
Procurement fee		11.0		17.8		11.7
AFUDC - equity funds		7.6		9.8		3.4
Conservation load management incentive		4.2		4.4		4.0
Energy Independence Act incentives		5.5		-		-
Rental investment revenue		0.7		1.1		0.8
Total Other Income		37.9		45.1		28.2
Other Loss:
Rental investment expenses		(0.1)		(0.1)		(0.2)
Total Other Loss		(0.1)		(0.1)		(0.2)
Total Other Income, Net	$	37.8	$	45.0	$	28.0

The procurement fee represents compensation approved by the DPUC associated with Transitional Standard Offer (TSO) supply procurement. The conservation and load management incentive relates to incentives earned if certain energy and demand savings goals are met. The Energy Independence Act provides incentives to encourage the construction of distributed generation, new large-scale generation and conservation and load management initiatives to reduce FMCC charges.

Based on developments in July of 2006, CYAPC management concluded that $10 million of CYAPC's regulatory assets were no longer probable of recovery and should be written off. CL&P included in 2006 other income, net its 34.5 percent share of CYAPC's after-tax write-off. For further information regarding CYAPC, see Note 5E, "Commitments and Contingencies - Deferred Contractual Obligations."

Provision for Uncollectible Accounts

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

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

Special Deposits

The company had amounts on deposit related to a special purpose entity used to facilitate the issuance of rate reduction certificates. These amounts which totaled $70.1 million and $23.2 million at December 31, 2006 and 2005, respectively, are included in deferred debits and other assets - other on the accompanying consolidated balance sheets.

Short-Term Debt

Limits: The amount of short-term borrowings that may be incurred by CL&P is subject to periodic approval by either the 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 SEC orders under PUHCA relevant to FERC authority will continue to be in effect until 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, 2006, CL&P is permitted to incur $359.2 million of additional unsecured debt.

Credit Agreement: CL&P has a 5-year unsecured revolving credit facility which expires on 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, 2006 and 2005, CL&P had no borrowings outstanding under this facility.

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

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, 2006 and 2005, CL&P had borrowings of $258.9 million and $26.8 million from the Pool, respectively. The weighted average interest rate on borrowings from the Pool at December 31, 2006 and 2005 was 4.97 percent and 2.86 percent, respectively.

Derivative Instruments

CL&P has contracts with two IPPs to purchase power that contain pricing provisions that are not clearly and closely related to the price of power and therefore do not qualify for the normal purchases and sales exception. The fair values of these IPP non-trading derivatives at December 31, 2006 include derivative assets with a fair value of $289.6 million, of which $40.2 million and $249.4 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 $35.7 million, of which $3.8 million and $31.9 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 these contracts are part of the stranded costs, and management believes that these costs will continue to be recovered or refunded in cost of service, regulated rates.

At December 31, 2005, the fair values of these IPP non-trading derivatives included 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.

CL&P has entered into Financial Transmission Rights (FTR) contracts to limit the congestion costs associated with its TSO contracts. An offsetting regulatory asset has been recorded as this contract is part of the stranded costs, and management believes that these costs will be recovered in rates. At December 31, 2006, the fair value of these contracts is recorded as a current derivative asset of $4.8 million and a current derivative liability of $0.3 million on the accompanying consolidated balance sheets. The fair value of CL&P's FTRs at December 31, 2005 was equal to the value when acquired as there were no changes in fair value of the FTRs through December 31, 2005.

Employee Benefits

Pension Benefits and Postretirement Benefits Other Than Pensions

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

SFAS No. 158 requires the additional liability to be recorded with an offset to accumulated other comprehensive income in stockholders’ equity. However, because CL&P is a cost-of-service rate regulated entity under SFAS No. 71, regulatory assets were recorded in the amount of $155.8 million, as these amounts in benefits expense have been and continue to be recoverable in cost-of-service, regulated rates. Regulatory accounting was also applied to the portions of the NUSCO costs that support CL&P, as these amounts are also recoverable.

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


	For the Years Ended December 31,
(Millions of Dollars)	2006		2005		2004
Total pension expense/(income)	$	0.3	$	3.0	$	(13.2)
Amount capitalized as utility plant		0.1		(1.5)		6.4
Total pension expense/(income), net of amounts capitalized	$	0.4	$	1.5	$	(6.8)

Total pension expense above includes pension curtailments and termination benefits benefit of $2.1 million in 2006, and expense of $3.6 million and $1.1 million in 2005 and 2004, respectively.

Pension Curtailments and Termination Benefits: In December of 2005, a new program was approved providing a benefit for certain employees hired on and after January 1, 2006 providing for these employees to receive retirement benefits under a new 401(k) benefit (K-Vantage Plan) rather than under the Pension Plan. The approval of the new plan resulted in the recording of an estimated pre-capitalization, pre-tax curtailment expense of $1.3 million in 2005, as a certain number of employees hired before that date were expected to elect the new 401(k) benefit as permitted, resulting in a reduction in aggregate estimated future years of service under the Pension Plan. Management estimated the amount of the curtailment expense associated with this change based upon actuarial calculations and certain assumptions, including the expected level of transfers to the new 401(k) benefit. Because the predicted level of elections of the new benefit did not occur, CL&P recorded a pre-capitalization, pre-tax reduction in the curtailment expense of $0.8 million in 2006.

In 2004, as a result of litigation with nineteen former employees, NU was ordered by the court to modify its Pension Plan to include special retirement benefits for fifteen of these former employees retroactive to the dates of their retirement and provide increased future monthly benefit payments. 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.

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.

SERP: NU has maintained a SERP since 1987. The SERP provides its eligible participants, some of which are officers of CL&P, with benefits that would have been provided to them under NU's retirement plan if certain Internal Revenue Code and other limitations were not imposed.

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

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

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

Based upon guidance from the federal government released in 2005, CL&P also qualifies for federal subsidy relating to employees whose PBOP Plan obligation is "capped" under CL&P's PBOP Plan. These subsidy amounts do not reduce CL&P's PBOP Plan benefit obligation as they will be used to offset retiree contributions, CL&P realizes a tax benefit because the federal subsidy is tax exempt when it is collected and tax deductible as the amounts are contributed to the PBOP Plan. These additional subsidy benefits are also being amortized over approximately 13 years beginning in 2005. For the years ended December 31, 2006 and 2005, the additional subsidy amounts were approximately $4.6 million. For the years ended December 31, 2006, 2005 and 2004, the subsidy amounts reduced expected tax expense by $2.2 million, $2.4 million and $0.5 million, respectively.

PBOP Curtailments and Termination Benefits: CL&P recorded an estimated $2.5 million pre-tax curtailment expense at December 31, 2005 relating to its corporate reorganization. CL&P also accrued a $0.2 million pre-tax termination benefit expense at December 31, 2005 relating to certain benefits provided under the terms of the PBOP Plan. Based on refinements to its estimates, CL&P recorded an adjustment to the curtailment and related termination benefits in 2006. This adjustment resulted in a combined pre-capitalization, pre-tax reduction in the curtailment expense and termination benefits of $1.5 million in 2006. There were no curtailments or termination benefits in 2004.

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				SERP Benefits				Postretirement Benefits
(Millions of Dollars)	2006		2005		2006		2005		2006		2005
Change in benefit obligation
Benefit obligation at beginning of year	$	(859.3)	$	(800.0)	$	(2.6)	$	(2.0)	$	(200.7)	$	(192.4)
Service cost		(17.0)		(17.2)		(0.1)		-		(2.9)		(2.8)
Interest cost		(47.9)		(46.8)		(0.1)		(0.1)		(11.1)		(10.2)
Transfers		-		0.2		-		-		3.4		-
Actuarial gain/(loss)		21.6		(53.3)		0.1		(0.6)		9.5		(11.3)
Federal subsidy on benefits paid		-		-		-		-		(1.3)		-
Benefits paid - excluding lump sum payments		49.6		47.3		0.1		0.1		16.1		15.9
Curtailment/impact of plan changes		(8.3)		11.8		-		-		(0.1)		0.3
Termination benefits		0.8		(1.3)		-		-		-		(0.2)
Benefit obligation at end of year	$	(860.5)	$	(859.3)	$	(2.6)	$	(2.6)	$	(187.1)	$	(200.7)
Change in plan assets								-
Fair value of plan assets at beginning of year	$	990.7	$	965.4		N/A		N/A	$	85.1	$	74.9
Actual return on plan assets		162.5		72.8		N/A		N/A		12.7		4.6
Employer contribution		-		-		N/A		N/A		21.5		21.5
Transfers		-		(0.2)		N/A		N/A		(1.9)		-
Benefits paid - excluding lump sum payments		(49.6)		(47.3)		N/A		N/A		(16.1)		(15.9)
Benefits paid - lump sum payments		-		-		N/A		N/A	$	-	$	-
Fair value of plan assets at end of year	$	1,103.6	$	990.7	$	N/A	$	N/A	$	101.3	$	85.1
Funded status at December 31^st	$	243.1	$	131.4	$	(2.6)	$	(2.6)	$	(85.8)	$	(115.6)
Unrecognized transition obligation				-				-				41.4
Unrecognized prior service cost				16.7				0.2				-
Unrecognized actuarial net loss				167.4				1.2				70.8
Prepaid/(accrued) benefit cost			$	315.5			$	(1.2)			$	(3.4)

The $11.8 million reduction in 2005 in the Pension Plan's obligation that is included in the curtailment/impact of plan changes related to the reduction in the future years of service expected to be rendered by plan participants. This reduction was the result of the expected transition of employees into the new 401(k) benefit and the company's corporate reorganization. This overall reduction in plan obligation served to reduce the previously unrecognized actuarial losses. In 2006, $8.3 million of this curtailment was reversed because actual levels of elections of the new 401(k) benefit were much lower than expected and is reflected above as an increase to the obligation.

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

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

The accumulated benefit obligation for the Pension Plan was $771.1 million and $769.6 million at December 31, 2006 and 2005, respectively, and $2.4 million and $1.8 million for the SERP at December 31, 2006 and 2005, respectively.

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


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

Receivables	$	-	$	-	$	-	$	-	$	1.3	$	-	$	1.3	$	-
Regulatory assets		72.1		-		1.2		-		82.5		-		155.8		-
Prepaid pension		243.1		315.5		-		-		-		-		243.1		315.5
Total assets		315.2		315.5		1.2		-		83.8		-		400.2		315.5

Other current liabilities (1)		-		-		(0.1)		-		-		-		(0.1)		-
Deferred taxes, net		(94.7)		(126.1)		1.0		0.5		(24.9)		1.7		(118.6)		(123.9)
Accrued postretirement benefits		-		-		-		-		(85.8)		(3.4)		(85.8)		(3.4)
Other deferred credits		-		-		(2.5)		(1.2)		-		-		(2.5)		(1.2)
Total liabilities		(94.7)		(126.1)		(1.6)		(0.7)		(110.7)		(1.7)		(207.0)		(128.5)

Accumulated other comprehensive loss, net of tax	$	-	$	-	$	-	$	(0.4)	$	-	$	-	$	-	$	(0.4)

(1)

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

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


(Millions of Dollars)	Before Adopting SFAS No. 158		Adjustments to Adopt SFAS No. 158		After Adopting SFAS No. 158
Regulatory assets (1)	$	0.5	$	155.3	$	155.8
Prepaid pension		315.2		(72.1)		243.1
Other deferred debits (1)		0.1		(0.1)		-
Total assets		315.8		83.1		398.9

Deferred taxes, net		(140.6)		22.0		(118.6)
Other current liabilities (2)		-		(0.1)		(0.1)
Accrued postretirement benefits		(2.0)		(83.8)		(85.8)
Other deferred credits		(2.4)		(0.1)		(2.5)
Total liabilities	$	(145.0)	$	(62.0)	$	(207.0)

(1)

The regulatory asset amount before adopting SFAS No. 158 represents a portion of an additional minimum pension liability recorded for the SERP. The amount in other deferred debits represents an intangible asset recorded under SFAS No. 87 to account for a portion of the additional minimum pension liability recorded for the SERP. This amount was reversed as part of the adoption of SFAS No. 158.

(2)

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

The following is a summary of amounts recorded as regulatory assets at December 31, 2006 and the portions of those amounts expected to be recognized as portions of net periodic benefit cost in 2007, which is expected to total a benefit of $11.1 million for the Pension Plan, and expense of $0.3 million for the SERP and $16.8 million for the PBOP Plan on a pre-tax basis:


	At December 31, 2006								Estimated Expense in 2007
(Millions of Dollars)	Pension		SERP		OPEB		Total		Pension		SERP		OPEB		Total
Transition obligation	$	-	$	-	$	36.7	$	36.7	$	-	$	-	$	6.1	$	6.1
Prior service cost		16.4		0.2		-		16.6		2.8		-		-		2.8
Net actuarial loss		55.7		1.0		45.8		102.5		10.1		0.1		3.7		13.9
Total	$	72.1	$	1.2	$	82.5	$	155.8	$	12.9	$	0.1	$	9.8	$	22.8

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


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

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


	For the Years Ended December 31,
	Pension Benefits						SERP Benefits						Postretirement Benefits
(Millions of Dollars)	2006		2005		2004		2006		2005		2004		2006		2005			2004
Service cost	$	17.0	$	17.2	$	14.7	$	0.1	$	-	$	0.1	$	2.9	$	2.8	$	2.1
Interest cost		47.9		46.8		44.8		0.1		0.1		0.1		11.1		10.2		10.5
Expected return on plan assets		(81.2)		(80.1)		(81.3)		-		-		-		(5.6)		(4.9)		(4.6)
Net transition (asset)/obligation cost		-		-		(0.9)		-		-		-		6.1		6.3		6.3
Prior service cost		2.8		3.0		3.0		-		-		-		-		-		-
Actuarial loss		15.9		12.5		5.4		0.1		0.1		0.1		7.1		7.1		4.3
Net periodic expense/(income) - before curtailments and termination benefits		2.4		(0.6)		(14.3)		0.3		0.2		0.3		21.6		21.5		18.6
Curtailment (income)/expense		(1.3)		2.3		-		-		-		-		(1.4)		2.5		-
Termination benefits (income)/ expense		(0.8)		1.3		1.1		-		-		-		(0.1)		0.2		-
Total curtailments and termination benefits		(2.1)		3.6		1.1		-		-		-		(1.5)		2.7		-
Total - net periodic expense/(income)	$	0.3	$	3.0	$	(13.2)	$	0.3	$	0.2	$	0.3	$	20.1	$	24.2	$	18.6

Not included in the pension expense/(income) amount above are pension related intercompany allocations totaling $10.3 million, $8.8 million, and $2.5 million for the years ended December 31, 2006, 2005 and 2004, respectively, including curtailment and termination benefits income of $1.5 million, and expense of $2.4 million and $0.5 million for the years ended December 31, 2006, 2005 and 2004. Excluded from postretirement benefits expense are related intercompany allocations of $7.6 million, $7.9 million, and $5.6 million for the years ended December 31, 2006, 2005, and 2004, respectively, including curtailments and termination benefits income of $0.3 million, and expense of $0.7 million, for the years ended December 31, 2006 and 2005, respectively. These amounts are included in other operating expenses on the accompanying consolidated statements of income.

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
	2006		2005		2004		2006		2005		2004
Discount rate	5.80	%	6.00	%	6.25	%	5.65	%	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	%	4.00	%	3.75	%	N/A		N/A		N/A
Expected long-term rate of return -
Health assets, net of tax	N/A		N/A		N/A		6.85	%	6.85	%	6.85	%
Life assets and non-taxable health assets	N/A		N/A		N/A		8.75	%	8.75	%	8.75	%

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


	Year Following December 31,
	2006		2005
Health care cost trend rate assumed for next year	9.00	%	10.00	%
Rate to which health care cost trend rate is assumed to decline (the ultimate trend rate)	5.00	%	5.00	%
Year that the rate reaches the ultimate trend rate	2011		2011

At December 31, 2005, the health care cost trend assumption was reset for 2006 at 10 percent, decreasing one percentage point per year to an ultimate rate of 5 percent in 2011.

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


(Millions of Dollars)	One Percentage Point Increase	One Percentage Point Decrease
Effect on total service and interest cost components	$0.5	$(0.4)
Effect on postretirement benefit obligation	$7.1	$(6.2)

NU's investment strategy for its Pension Plan and PBOP Plan is to maximize the long-term rate of return on those plans' assets within an acceptable level of risk. The investment strategy establishes target allocations, which are routinely reviewed and periodically rebalanced. NU's expected long-term rates of return on Pension Plan assets and PBOP Plan assets are based on these target asset allocation assumptions and related expected long-term rates of return. In developing its expected long-term rate of return assumptions for the Pension Plan and the PBOP Plan, NU also evaluated input from actuaries and consultants as well as long-term inflation assumptions and NU's historical 20-year compounded return of approximately 11 percent. The Pension Plan's and PBOP Plan's target asset allocation assumptions and expected long-term rate of return assumptions by asset category are as follows:


	At December 31,
	Pension Benefits		Postretirement Benefits
	2006 and 2005		2006 and 2005
Asset Category	Target Asset Allocation	Assumed Rate of Return	Target Asset Allocation	Assumed Rate of Return
Equity Securities:
United States	45%	9.25%	55%	9.25%
Non-United States	14%	9.25%	11%	9.25%
Emerging markets	3%	10.25%	2%	10.25%
Private	8%	14.25%	-	-
Debt Securities:
Fixed income	20%	5.50%	27%	5.50%
High yield fixed income	5%	7.50%	5%	7.50%
Real Estate	5%	7.50%	-	-

The actual asset allocations at December 31, 2006 and 2005, approximated these target asset allocations. The plans’ actual weighted-average asset allocations by asset category are as follows:


	At December 31,
	Pension Benefits		Postretirement Benefits
Asset Category	2006	2005	2006	2005
Equity Securities:
United States	46%	46%	54%	54%
Non-United States	16%	16%	14%	14%
Emerging markets	4%	4%	1%	1%
Private	5%	5%	-	-
Debt Securities:
Fixed income	19%	19%	29%	29%
High yield fixed income	5%	5%	2%	2%
Real Estate	5%	5%	-	-
Total	100%	100%	100%	100%

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


(Millions of Dollars)	Pension Benefits		SERP Benefits		Postretirement Benefits		Government Benefits
2007	$	50.7	$	0.1	$	19.1	$	(2.1)
2008		51.8		0.1		19.4		(2.3)
2009		53.0		0.1		19.6		(2.4)
2010		54.2		0.1		19.7		(2.6)
2011		55.5		0.1		19.6		(2.7)
2012-2017		300.3		0.6		94.2		(15.3)

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

Contributions: Currently, CL&P’s policy is to annually fund to the Pension Plan an amount at least equal to that which will satisfy the requirements of the Employee Retirement Income Security Act and Internal Revenue Code. For the PBOP plan, it is currently CL&P's policy to annually fund an amount equal to the PBOP Plan's postretirement benefit cost, excluding curtailments and termination benefits. CL&P does not expect to make any contributions to the Pension Plan in 2007 and expects to make $16.8 million in contributions to the PBOP Plan in 2007. Beginning in 2007, CL&P will make an additional contribution to the PBOP Plan for the amounts received from the federal Medicare subsidy. This amount is estimated at $1.3 million for 2007.

Defined Contribution Plans

NU maintains a 401(k) Savings Plan for substantially all CL&P employees. This savings plan provides for employee contributions up to specified limits. NU matches employee contributions up to a maximum of three percent of eligible compensation with one percent in cash and two percent in NU common shares. The 401(k) matching contributions of cash and NU common shares made by NU to CL&P employees were $3.6 million in 2006, $3.7 million in 2005 and $3.5 million in 2004.

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

Share-Based Payments

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

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

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

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

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

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

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

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


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

At December 31, 2006, the remaining compensation cost to be recognized by NU related to the 65,674 outstanding restricted shares was $0.2 million which will be recorded over the weighted average remaining period of 0.3 years. The per share and total weighted average grant date fair value for restricted shares vested was $14.60 and $1.4 million, respectively, for the year ended December 31, 2005 and $14.84 and $1.9 million, respectively, for the year ended December 31, 2004.

The compensation cost recognized by CL&P for its portion of the restricted shares above was $0.3 million, net of taxes of approximately $0.2 million for the year ended December 31, 2006, $0.3 million, net of taxes of approximately $0.2 million for the year ended December 31, 2005, and $0.4 million, net of taxes of approximately $0.2 million for the year ended December 31, 2004.


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

At December 31, 2006, the remaining compensation cost to be recognized by NU related to the 715,299 outstanding RSUs was $6.5 million which will be recorded over the weighted average remaining period of 1.8 years. The per share and total weighted average grant date fair value for RSUs granted was $18.89 and $5.8 million, respectively, for the year ended December 31, 2005 and $19.07 and $7.3 million, respectively, for the year ended December 31, 2004. The weighted average grant date fair value per share for RSUs issued was $19.06 and $18.65 for the years ended December 31, 2005 and 2004, respectively. The total weighted average fair value of RSUs issued was $1.9 million for the year ended December 31, 2005. The total weighted average fair value of RSUs issued in 2004 was de minimis.

The compensation cost recognized by CL&P for its portion of the RSUs above was $1.6 million, net of taxes of approximately $1 million for the year ended December 31, 2006, $0.8 million, net of taxes of approximately $0.5 million for the year ended December 31, 2005, and $0.6 million, net of taxes of approximately $0.4 million for the year ended December 31, 2004.

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

Severance Benefits

As a result of its corporate reorganization, in 2005 CL&P recorded severance and related expenses totaling $6.7 million relating to expected terminations of CL&P employees. These severance benefits were recorded in other operating expenses. In 2006, CL&P updated its prior estimates based upon actual termination data and updated its estimates of expected personnel reductions. A total reduction in severance and related expenses of $1.5 million was recorded and is included in other operating expenses on the accompanying consolidated statements of income for the year ended December 31, 2006. In addition, a benefit of $0.9 million and expenses of $3.4 million were recorded related to NUSCO intercompany allocations for the years ended December 31, 2006 and 2005, respectively.

Commitments and Contingencies

Regulatory Developments and Rate Matters

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

CTA and SBC Reconciliation: CTA allows CL&P to recover stranded costs, such as securitization costs associated with its rate reduction bonds, amortization of regulatory assets, and IPP over-market costs, while 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.

In CL&P's 2001 CTA and SBC reconciliation, and subsequently in a September 10, 2002 petition to reopen related proceedings, CL&P requested that a deferred intercompany tax liability associated with the intercompany sale of generation assets be excluded from the calculation of CTA cost of service. This liability was included as a reduction in the calculation of CTA cost of service. On September 10, 2003, the DPUC issued a final decision denying CL&P’s request and on October 24, 2003, CL&P appealed the DPUC’s final decision to the Connecticut Superior Court. On June 20, 2006, the Connecticut Superior Court denied CL&P's appeal. On November 1, 2006, the aforementioned generation assets were sold by Northeast Generation Company. As a result of this sale, the intercompany liability and its related decrease to revenue requirements will no longer be reflected as a component of the CTA effective with the November 1, 2006 sale date.

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, 2006 and 2005, CL&P had $2.8 million and $2.7 million, respectively, recorded as environmental reserves. A reconciliation of the activity in these reserves at December 31, 2006 and 2005 is as follows:


	For the Years Ended December 31,
(Millions of Dollars)	2006		2005
Balance at beginning of year	$	2.7	$	7.8
Additions and adjustments		0.2		(5.0)
Payments and adjustments		(0.1)		(0.1)
Balance at end of year	$	2.8	$	2.7

Of the 12 sites CL&P has currently included in the environmental reserve, 4 sites are in the remediation or long-term monitoring phase, six sites have had some level of site assessment completed and two sites are in the preliminary stage of site assessment.

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

At December 31, 2006, in addition to the 12 sites, there are six 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.

Manufactured Gas Plant (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 both December 31, 2006 and 2005, $1.5 million represents the amount for the site assessment and remediation of MGPs. CL&P currently has four MGP sites included in its environmental liability. Of the four MGP sites, three sites are currently in the site assessment stage and one site is in the preliminary stage of site assessment.

Of the 12 sites that are included in the company's liability for environmental costs, for three of these sights 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 MGP sites. At December 31, 2006, $1.8 million of the $2.8 million total liability has been accrued as a liability for these sites, which represents management's best estimate of the liability for environmental costs. This amount differs from an estimated range of loss from $1.7 million to $6.1 million as management utilizes the probabilistic model approach to make its estimate of the liability for environmental costs. For the nine remaining sites for which an estimate is based on the probabilistic model approach, determining a range of estimated losses is not possible at this time.

On January 19, 2005, the DPUC issued a final decision approving the sale of a former MGP site. The final decision approved the price of $24 million for the sale of the land and also approved the deferral of the gain in the amount of $14 million ($8.4 million after-tax). During 2005, the former MGP site was sold to an independent third party.

CERCLA Matters: The Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA) and its’ amendments or state equivalents impose joint and several strict liabilities, regardless of fault, upon generators of hazardous substances resulting in removal and remediation costs and environmental damages. Liabilities under these laws can be material and in some instances may be imposed without regard to fault or for past acts that may have been lawful at the time they occurred. Of the 12 sites, two are superfund sites under CERCLA for which it has been notified that it is a potentially responsible party (PRP). For sites where there are other PRPs and 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, prior to the sale of its ownership in the Millstone and Seabrook nuclear power stations.

The DOE is responsible for the selection and development of repositories for, and the disposal of, spent nuclear fuel and high-level radioactive waste. For nuclear fuel used to generate electricity prior to April 7, 1983 (Prior Period Spent Nuclear Fuel), an accrual has been recorded for the full liability, and payment must be made prior to the first delivery of spent fuel to the DOE. After the sale of Millstone, CL&P remains responsible for its share of the prior period spent nuclear fuel. Until such payment is made, the outstanding balance will continue to accrue interest at the 3-month treasury bill yield rate. At December 31, 2006 and 2005, fees due to the DOE for the disposal of Prior Period Spent Nuclear Fuel are included in long-term debt and were $227.5 million and $216.9 million, respectively, including interest costs of $160.9 million and $150.4 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 $19.1 million in 2006, $15.3 million in 2005 and $15.9 million in 2004.

Electricity Procurement Contracts: CL&P has entered into various arrangements that extend through 2024 for the purchase of electricity, including payment obligations resulting from the buydown of electricity purchase contracts. The total cost of purchases and obligations under these arrangements amounted to $206.1 million in 2006, $148 million in 2005 and $200 million in 2004. These amounts relate to IPP contracts and do not include contractual commitments related to CL&P's TSO or standard offer. The majority of the contracts expire by 2014.

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 $11.7 million in 2006, $12 million in 2005 and $13.5 million in 2004.

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

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

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

Estimated Future Annual Costs: The estimated future annual costs of CL&P’s significant long-term contractual arrangements at December 31, 2006 are as follows:


(Millions of Dollars)	2007		2008		2009		2010		2011		Thereafter
VYNPC	$	16.4	$	16.6	$	18.0	$	17.3	$	17.7	$	4.3
Electricity procurement contracts		208.3		200.8		172.6		149.9		147.8		592.5
Hydro-Quebec		12.0		12.1		12.0		12.0		11.9		107.5
Transmission business project commitments		474.7		278.2		40.6		0.1		-		-
Yankee Companies billings		29.4		23.2		19.1		21.5		18.8		73.2
Totals	$	740.8	$	530.9	$	262.3	$	200.8	$	196.2	$	777.5

Deferred Contractual Obligations

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

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

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

MYAPC: MYAPC is collecting amounts in rates that are adequate to recover the remaining cost of decommissioning its plant, and CL&P expects to recover its share of such costs from its customers.

Uranium Enrichment Litigation: In 2001, NU asserted claims against the DOE in the Court of Federal Claims for overcharges for purchases of uranium enrichment separative work units (SWUs) for CYAPC's unit and the Millstone units between 1986 and 1993 (D&D Claims). The NU case was stayed by the Court of Federal Claims while other D&D Claims cases were being litigated. Beginning in 2005, NU joined a number of other utilities in a consortium in an attempt to negotiate a settlement agreement with the DOE. In late-2006, a settlement was reached between the consortium and the DOE. The distribution of proceeds under the settlement agreement totals approximately $0.8 million for CYAPC and approximately $1.4 million for Millstone and the Millstone portion was received on January 30, 2007. This distribution is based on the total number of SWUs purchased for CYAPC's unit and the Millstone units during the applicable period covered by the litigation. The company believes it is likely that the net proceeds from the settlement agreement will be credited to ratepayers. Prior to March 31, 2001, CL&P owned 81 percent of Millstone 1 and 2 and 52.93 percent of Millstone 3.

NRG Energy, Inc. Exposures

CL&P has entered into transactions with NRG Energy, Inc. (NRG) and certain of its subsidiaries. On May 14, 2003, NRG and certain subsidiaries of NRG filed voluntary bankruptcy petitions, and on December 5, 2003, NRG emerged from bankruptcy. CL&P's NRG-related exposures as a result of these transactions relate to 1) the refunding of approximately $28 million of congestion charges previously withheld from NRG prior to the implementation of standard market design on March 1, 2003, which is still pending before the court, and 2) the recovery of approximately $25.8 million of CL&P's station service billings from NRG, which is currently the subject of an arbitration. 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 earnings, financial position or cash flows.

Guarantees

NU provides credit assurances on behalf of subsidiaries, including CL&P, in the form of guarantees and letters of credit (LOCs) in the normal course of business. At December 31, 2006, the maximum level of exposure in accordance with FIN 45, "Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others," under guarantees by NU on behalf of CL&P totaled $1.9 million. A majority of these guarantees do not have established expiration dates, and some guarantees have unlimited exposure to commodity price movements. Additionally, NU had $20 million of LOCs issued on behalf of CL&P at December 31, 2006. 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.

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

Other Litigation and Legal Proceedings

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

Fair Value of Financial Instruments

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

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


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


	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

Other long-term debt includes $227.5 million and $216.9 million of fees and interest due for spent nuclear fuel disposal costs at December 31, 2006 and 2005, respectively.

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

Leases

CL&P has entered into lease agreements, some of which are capital leases, for the use of data processing and office equipment, vehicles, and office space. In addition, CL&P incurs costs associated with leases entered into by NUSCO and RRR. These costs are included below in operating lease payments charged to expense and amounts capitalized as well as future operating lease payments from 2007-2011 and thereafter. 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 $2.9 million in 2006 and $3 million in both 2005 and 2004. Interest included in capital lease rental payments was $1.7 million in 2006 and $1.8 million in both 2005 and 2004. Capital lease asset amortization was $0.7 million in 2006, and $0.6 million in both 2005 and 2004.

Operating lease rental payments charged to expense were $17.3 million in 2006, $14.3 million in 2005 and $14.7 million in 2004. The capitalized portion of operating lease payments was approximately $6.2 million, $6.2 million and $4.2 million for the years ended December 31, 2006, 2005 and 2004, respectively.

Future minimum rental payments excluding executory costs, such as property taxes, state use taxes, insurance, and maintenance, under long-term noncancelable leases, at December 31, 2006 are as follows:


(Millions of Dollars)	Capital Leases		Operating Leases
2007	$	2.5	$	21.0
2008		3.1		19.4
2009		3.5		15.4
2010		1.7		13.2
2011		1.7		10.0
Thereafter		18.7		48.8
Future minimum lease payments		31.2	$	127.8
Less amount representing interest		(16.9)
Present value of future minimum lease payments	$	14.3

Dividend Restrictions

The Federal Power Act limits the payment of dividends by CL&P to its retained earnings balance. In addition, certain state statutes may impose additional limitations on CL&P. CL&P also has a revolving credit agreement that imposes a leverage restriction.

Accumulated Other Comprehensive Income/(Loss)

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


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


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

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


(Millions of Dollars)	2006		2005		2004
Qualified cash flow hedging instruments	$	(3.1)	$	-	$	-
Unrealized gains on securities		-		-		-
Minimum SERP liability		(0.2)		(0.1)		0.1
Accumulated other comprehensive (loss)/income	$	(3.3)	$	(0.1)	$	0.1

The unrealized gains on securities above relate to $2.2 million and $2 million of SERP securities at December 31, 2006 and 2005, respectively, that are included in prepayments and other on the accompanying consolidated balance sheets.

Adjustments to accumulated other comprehensive income/(loss) for NU's qualified cash flow hedging instruments are as follows:


	At December 31,
(Millions of Dollars, Net of Tax)	2006
Balance at beginning of year	$	-
Hedged transactions recognized into earnings		(0.1)
Cash flow transactions entered into for the period		4.6
Net change associated with the current period hedging transactions	$	4.5

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

At December 31, 2006, it is estimated that a pre-tax benefit of $0.3 million included in the accumulated other comprehensive income balance will be reclassified into earnings in 2007 related to the amortization of interest rate locks.

10.

Preferred Stock Not Subject to Mandatory Redemption

CL&P’s charter authorizes it to issue up to 9 million shares of preferred stock ($50 par value per share) of which 2,324,000 shares were outstanding at December 31, 2006 and 2005. In addition, CL&P’s charter authorizes it to issue up to 8 million shares of Class A preferred stock ($25 par value per share). There were no Class A preferred shares outstanding at December 31, 2006 or 2005. The issuance of additional preferred shares would be subject to approval by the DPUC.

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


Description	December 31, 2006 Redemption Price	Shares Outstanding at December 31, 2006 and 2005	December 31,
Description	December 31, 2006 Redemption Price	Shares Outstanding at December 31, 2006 and 2005	2006		2005
$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,	2006		2005
	(Millions of Dollars)
First Mortgage Bonds:

4.800% Series A due 2014	$	150.0	$	150.0
7.875% Series D due 2024		139.8		139.8
5.750% Series B due 2034		130.0		130.0
5.000% Series A due 2015		100.0		100.0
5.625% Series B due 2035		100.0		100.0
6.350% Series A due 2036		250.0		-
Total First Mortgage Bonds		869.8		619.8
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		1,293.7		1,043.7
Fees and interest due for spent nuclear fuel disposal costs		227.5		216.9
Less amounts due within one year		-		-
Unamortized premium and discount, net		(1.8)		(1.7)
Long-term debt	$	1,519.4	$	1,258.9

There are no cash sinking fund requirements or debt maturities for the years 2007 through 2011.

The majority of CL&P's utility plant 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 June 7, 2006, CL&P issued $250 million of First Mortgage Bonds (the Series A Bonds) with a fixed coupon of 6.35 percent and a maturity of June 1, 2036. The proceeds 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, 2006, 2005 and 2004 is as follows. Cash flows for total investments in plant included in the segment information below are cash capital expenditures that do not include cost of removal, AFUDC related to equity funds, and the capitalized portion of pension expense or income.


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


	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		(2,899.1)		(54.1)		(2,953.2)
Operating income		161.1		40.9		202.0
Interest expense, net of AFUDC		(108.5)		(11.5)		(120.0)
Interest income		2.9		0.4		3.3
Other income, net		34.8		6.9		41.7
Income tax expense		(26.2)		(6.0)		(32.2)
Net income	$	64.1	$	30.7	$	94.8
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		(2,315.4)		(47.7)		(2,363.1)
Operating income		184.6		31.0		215.6
Interest expense, net of AFUDC		(101.1)		(8.9)		(110.0)
Interest income		3.9		0.2		4.1
Other income, net		21.8		2.0		23.8
Income tax expense		(41.0)		(4.5)		(45.5)
Net income	$	68.2	$	19.8	$	88.0
Cash flows for total investments in plant	$	254.7	$	134.6	$	389.3

(1)

Information for segmenting total assets between distribution and transmission is not available at December 31, 2006 or 2005. 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,
2006
Operating Revenues	$	1,004,760	$	939,720	$	1,083,299	$	952,032
Operating Income		60,769		47,941		54,731		72,629
Net Income		33,830		17,472		101,033		47,672

2005
Operating Revenues	$	838,901	$	797,568	$	952,444	$	877,507
Operating Income		59,676		43,237		59,337		39,799
Net Income		26,533		12,443		27,463		28,406


Selected Consolidated Financial Data (Unaudited)
(Thousands of Dollars)	2006		2005		2004		2003		2002
Operating Revenues	$	3,979,811	$	3,466,420	$	2,832,924	$	2,704,524	$	2,507,036
Net Income		200,007		94,845		88,016		68,908		85,612
Dividends on Common Stock		63,732		53,834		47,074		60,110		60,145
Property, Plant and Equipment, net (c)		3,634,370		3,166,692		2,824,877		2,561,898		2,332,693
Total Assets (d)		6,321,294		5,765,072		5,306,913		5,206,894		4,786,083
Rate Reduction Bonds		743,899		856,479		995,233		1,124,779		1,245,728
Long-Term Debt (d)		1,519,440		1,258,883		1,052,891		830,149		827,866
Preferred Stock - Non-Redeemable		116,200		116,200		116,200		116,200		116,200
Obligations Under Capital Leases (d)		14,264		13,488		14,093		14,879		15,499

(a)

Operating revenue amounts totaling $0.5 million for the quarter ended June 30, 2006 were reclassified to operating expenses as a result of the change in classification of certain revenues and associated expenses from a gross presentation to a net presentation.

(b)

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


Quarter Ended	2006		2005
March 31,	$	930	$	(1,923)
June 30,		(1,992)		(669)
September 30,		(977)		(459)

(c)

Amount includes construction work in progress.

(d)

Includes portions due within one year.


Consolidated Sales Statistics (Unaudited)

	2006		2005		2004		2003		2002
Revenues: (Thousands)
Utility Group:
Residential	$	1,709,700	$	1,440,142	$	1,155,492	$	1,151,707	$	1,028,425
Commercial		1,405,281		1,170,038		939,579		960,678		874,713
Industrial		380,479		327,598		275,730		290,526		274,228
Other Utilities		318,958		344,650		295,833		322,955		271,484
Streetlighting and Railroads		42,099		37,054		31,897		35,358		33,788
Miscellaneous		123,294		146,938		134,393		(56,700)		24,398
Total	$	3,979,811	$	3,466,420	$	2,832,924	$	2,704,524	$	2,507,036
Sales: (KWH - Millions)
Residential		10,053		10,760		10,305		10,359		9,699
Commercial		9,995		10,307		9,922		9,829		9,644
Industrial		3,306		3,501		3,623		3,630		3,707
Other Utilities		3,749		4,179		5,375		5,885		6,281
Streetlighting and Railroads		284		298		298		298		292
Total		27,387		29,045		29,523		30,001		29,623
Customers: (Average)
Residential		1,084,937		1,078,723		1,071,249		1,058,247		1,048,096
Commercial		101,563		108,558		108,865		104,750		103,408
Industrial		3,848		3,976		4,078		3,989		4,035
Other		2,592		2,630		2,694		2,643		2,768
Total		1,192,940		1,193,887		1,186,886		1,169,629		1,158,307
Average Annual Use Per Residential Customer (KWH)		9,266		9,974		9,620		9,790		9,244
Average Annual Bill Per Residential Customer	$	1,575.87	$	1,335.02	$	1,078.40	$	1,089.63	$	979.86