CONNECTICUT LIGHT & POWER CO - Quarter Report: 2006 March (Form 10-Q)

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-Q

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Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days:

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer.  See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act.  (Check one):

Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act):

Indicate the number of shares outstanding of each of the issuers’ classes of common stock, as of the latest practicable date:

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NORTHEAST UTILITIES AND SUBSIDIARIES
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

TABLE OF CONTENTS

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NORTHEAST UTILITIES AND SUBSIDIARIES

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NORTHEAST UTILITIES AND SUBSIDIARIES

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

1.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (All Companies)

A.

Presentation

Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission (SEC).  The accompanying unaudited condensed consolidated financial statements should be read in conjunction with this complete report on Form 10-Q and the Annual Reports of Northeast Utilities (NU or the company), The Connecticut Light and Power Company (CL&P), Public Service Company of New Hampshire (PSNH), and Western Massachusetts Electric Company (WMECO), which were filed as part of the Northeast Utilities and subsidiaries combined 2005 Form 10-K (NU 2005 Form 10-K) with the SEC.  The accompanying condensed consolidated financial statements contain, in the opinion of management, all adjustments (including normal, recurring adjustments) necessary to present fairly NU's and the above companies' financial position at March 31, 2006, and the results of operations and cash flows for the three months ended March 31, 2006 and 2005.  The results of operations and statements of cash flows for the three months ended March 31, 2006 and 2005 are not necessarily indicative of the results expected for a full year.  

The condensed consolidated financial statements of NU and of its subsidiaries, as applicable, include the accounts of all their respective subsidiaries.  Intercompany transactions have been eliminated in consolidation.

The preparation of condensed 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 condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.

In NU’s condensed consolidated statement of loss and CL&P's, PSNH's and WMECO's condensed consolidated statements of income for the three months ended March 31, 2005, the classification of certain expense amounts previously included in other income, net was changed.  These expense amounts which were reclassified to other operation expense for the three months ended March 31, 2005 for NU, CL&P, PSNH and WMECO totaled $5.1 million, $0.8 million, $0.9 million, and $0.1 million, respectively.

NU’s condensed consolidated statements of loss for the three months ended March 31, 2006 and 2005 present the operations for the following as discontinued operations:

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Northeast Generation Company (NGC),

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

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

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Woods Electrical Co., Inc. (Woods Electrical),

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

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Woods Network Services, Inc. (Woods Network).

At March 31, 2006, certain assets and liabilities of NGC, Mt. Tom, SESI and Woods Electrical, as well as the retail business of Select Energy, Inc. (Select Energy), have been classified as assets held for sale and liabilities of assets held for sale on the accompanying condensed consolidated balance sheet.  At December 31, 2005, assets held for sale and liabilities of assets held for sale consisted of certain assets and liabilities of SESI and Woods Electrical.  For further information regarding these companies, see Note 4, "Assets Held for Sale and Discontinued Operations" to the condensed consolidated financial statements.

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B.

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 Standard (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 on January 1, 2007.  The company is evaluating the effect of this statement on its accounting for the sale and servicing of certain CL&P accounts receivable.  

C.

Guarantees

NU provides credit assurances on behalf of subsidiaries in the form of guarantees and letters of credit (LOCs) in the normal course of business.  NU would be required to perform under these guarantees in the event of non-performance by NU Enterprises, primarily Select Energy.  At March 31, 2006, the maximum level of exposure in accordance with FASB Interpretation No. (FIN) 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others," under guarantees by NU, primarily on behalf of NU Enterprises, totaled $892.9 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 $221.4 million of LOCs issued, the majority of which were issued for the benefit of NU Enterprises at March 31, 2006.  NU has no guarantees of the performance of third parties.  

At March 31, 2006, NU had outstanding guarantees on behalf of the Utility Group and The Rocky River Realty Company (RRR) of $11 million and $11.6 million, respectively.  These amounts are included in the total outstanding NU guarantee exposure amount of $892.9 million.  The guarantee amount of $870.3 million for NU Enterprises includes $557.2 million for Select Energy and $313.1 million for other NU Enterprises businesses.  The $313.1 million in guarantees related to the other NU Enterprises businesses is comprised of $89.5 million for SESI's obligations under certain financing arrangements, $209.5 million for performance obligations of the energy services businesses, including SESI, and $14.1 million for the guarantee of NGC's debt obligations.

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

Until the repeal of the Public Utility Holding Company Act (PUHCA) on February 8, 2006, NU's level of guarantees was subject to certain authorization levels by the SEC.  With the repeal of PUHCA, there are no regulatory limits on NU's ability to guarantee the obligation of its subsidiaries.

D.

Regulatory Accounting

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

The transmission and distribution businesses of CL&P, PSNH and WMECO, along with PSNH's generation business and Yankee Gas Services Company's (Yankee Gas) distribution business, continue to be cost-of-service rate regulated, and management believes that the application of SFAS No. 71 to those businesses continues to be appropriate.  Management also believes that it is probable that the Utility Group will recover its investments in long-lived assets, including regulatory assets.  In addition, all material net regulatory assets are earning an equity return, except for securitized regulatory assets, which are not supported by equity and substantial portions of the unrecovered contractual obligations regulatory assets.   

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

Included in NU's other regulatory assets/(overrecoveries) above of $304.8 million at March 31, 2006 and $245.9 million at December 31, 2005 are the regulatory assets recorded associated with the implementation of FIN 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143," totaling $48.8 million at March 31, 2006 and $47.3 million at December 31, 2005.  A portion of these regulatory assets totaling $17.6 million at March 31, 2006 and $17.3 million at December 31, 2005 has been approved for deferred accounting treatment.  At this time, management believes that the remaining regulatory assets are probable of recovery.  

Included in WMECO's other regulatory assets/(overrecoveries) are $31.8 million and $37.8 million at March 31, 2006 and December 31, 2005, respectively, of amounts related to WMECO's rate cap deferral.  The rate cap deferral allows WMECO to recover stranded costs, and these amounts represent the cumulative excess of transition cost revenues over transition cost expenses.

Additionally, the Utility Group had $12.6 million and $11.2 million of regulatory costs at March 31, 2006 and December 31, 2005, respectively, that are included in deferred debits and other assets - other on the accompanying condensed consolidated balance sheets.  These amounts represent regulatory costs that have not yet been approved by the applicable regulatory agency.  Management believes these assets are recoverable in future cost of service regulated rates.

As discussed in Note 7D, "Commitments and Contingencies - Deferred Contractual Obligations," substantial portions of the unrecovered contractual obligations regulatory assets have not yet been approved for recovery.  At this time management believes that these regulatory assets are probable of recovery.

Regulatory Liabilities:  The Utility Group had $1.2 billion of regulatory liabilities at March 31, 2006 and $1.3 billion at December 31, 2005, including revenues subject to refund.  These amounts are comprised of the following:

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E.

Allowance for Funds Used During Construction

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

The average Utility Group AFUDC rate is based on a Federal Energy Regulatory Commission (FERC) prescribed formula that develops an average rate using the cost of the company’s short-term financings as well as the company’s capitalization (preferred stock, long-term debt and common equity).  The average rate is applied to eligible construction work in progress amounts to calculate AFUDC.  Fifty percent of construction work in progress associated with CL&P's four major transmission projects in southwest Connecticut is recovered currently in rates.  The increase in the average AFUDC rate in 2006 is primarily due to lower levels of short-term debt outstanding and higher equity levels in the first quarter of 2006 as compared to 2005.  

F.

Share-Based Payments

NU maintains an Employee Stock Purchase Plan (ESPP) and other long-term equity-based incentive plans under the Northeast Utilities Incentive Plan (Incentive Plan).  Effective January 1, 2006, NU adopted SFAS No. 123(R), "Share-Based Payments," under the modified prospective method.  Adoption of SFAS No. 123(R) had a de minimus effect on NU’s net loss, no effect on NU’s loss per share and a tax benefit in excess of compensation cost that (decreased)/increased NU’s cash flows from operating activities and cash flows from financing activities by $(0.2) million and $0.2 million, respectively.   

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 of recording equity-based compensation under the fair value-based method.  In 2006, NU began accounting for its various share-based plans as follows:

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For grants of restricted stock and restricted stock 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 incurred.  Dividend equivalents on RSUs, previously included in compensation expense, are charged to retained earnings net of estimated forfeitures.  

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For shares granted under the Employee Stock Purchase Plan (ESPP), an immaterial amount of compensation expense was recorded in the first quarter of 2006 and no future compensation expense will be recorded as a result of a plan amendment that was effective on February 1, 2006.  

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

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Incentive Plans:  Under the Incentive Plan, 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 employee 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.

Restricted Shares and Restricted Share Units:  NU has granted restricted shares under the 2004, 2003 and 2002 incentive programs which are subject to three and four-year graded vesting schedules.  NU has granted RSUs under the 2004, 2005 and 2006 incentive programs which are subject to three-year and four-year graded vesting schedules.  RSUs are paid in shares plus cash sufficient to satisfy withholding subsequent to vesting, in accordance with the payment schedule as defined in the plan.  A summary of restricted shares and RSUs for the three months ended March 31, 2006 is as follows:

The weighted average grant date fair value per share for RSUs granted during the three months ended March 31, 2005 was $18.76.  The weighted average grant date fair value per share for restricted shares vested and RSUs paid during the three months ended March 31, 2005 was $14.57 and $19.07, respectively.  

The total fair value of restricted shares vested during the three months ended March 31, 2006 and 2005 was $1.1 million and $1.2 million, respectively.  The total aggregate fair value of restricted shares outstanding at March 31, 2006 was $1.1 million   As of March 31, 2006, the remaining compensation cost related to these shares to be recognized was $1 million, which is expected to be recognized over a weighted average period of one year.  The total compensation cost recognized during the three months ended March 31, 2006 and March 31, 2005 was $0.2 million in each period, net of taxes of approximately $0.1 million.  

The total fair value of RSUs paid during the three months ended March 31, 2006 and 2005 was $2 million and $1.2 million, respectively.  The total aggregate fair value of RSUs outstanding at March 31, 2006 was $14.6 million   As of March 31, 2006, the remaining compensation cost related to these units to be recognized was $11.6 million, which is expected to be recognized over a weighted average period of 2.4 years.  The total compensation cost recognized for the three months ended March 31, 2006 and 2005 was $0.6 million and $0.2 million, respectively, net of taxes of approximately $0.4 million and $0.1 million, respectively.  

Stock Options:  Prior to 2003, NU granted stock options to certain employees.  These options were fully vested as of January 1, 2006.  The fair value of each stock option grant has been estimated on the date of grant using the Black-Scholes option pricing model.  The weighted average remaining contractual lives for the options outstanding at March 31, 2006 is 4.6 years.

A summary of stock option transactions is as follows:

Cash received for options exercised during the three months ended March 31, 2006 totaled $0.1 million.  

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

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The following table illustrates the pro forma effect if NU had applied the recognition provisions of SFAS No. 123 to share-based compensation for the three months ended March 31, 2005:

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

G.

Sale of Customer Receivables

At March 31, 2006 and December 31, 2005, CL&P had sold an undivided interest in its accounts receivable of $100 million and $80 million, respectively, to a financial institution with limited recourse through CL&P Receivables Corporation (CRC), a wholly owned subsidiary of CL&P.  CRC can sell up to $100 million of an undivided interest in its accounts receivable and unbilled revenues.  At March 31, 2006 and December 31, 2005, the reserve requirements calculated in accordance with the Receivables Purchase and Sale Agreement were $30.7 million and $21 million, respectively.  These reserve amounts are deducted from the amount of receivables eligible for sale.  At their present levels, these reserve amounts do not limit CL&P’s ability to access the full amount of the facility.  Concentrations of credit risk to the purchaser under this agreement with respect to the receivables are limited due to CL&P’s diverse customer base.

At March 31, 2006 and December 31, 2005, amounts sold to CRC by CL&P but not sold to the financial institution totaling $241.7 million and $252.8 million, respectively, are included in investments in securitizable assets on the accompanying condensed consolidated balance sheets.  These amounts would be excluded from CL&P’s assets in the event of CL&P’s bankruptcy.  On July 6, 2005, CRC renewed its Receivables Purchase and Sale Agreement with CL&P and the financial institution through July 5, 2006.  CL&P’s continuing involvement with the receivables that are sold to CRC and the financial institution is limited to servicing 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."

H.

Other Investments

The operating subsidiaries of NU collectively own 49 percent of the common stock of Connecticut Yankee Atomic Power Company (CYAPC) with a carrying value of $23 million at March 31, 2006.  This amount is included in deferred debits and other assets – other on the accompanying condensed consolidated balance sheets.  CYAPC filed with the FERC to recover the increased estimate of decommissioning and plant closure costs.  The FERC proceeding is ongoing.  Management believes that the FERC proceeding has not impaired the value of its investment in CYAPC at March 31, 2006 but will continue to evaluate the impacts, if any, that the FERC proceeding has on this investment.  For further information, see Note 7D, "Commitments and Contingencies - Deferred Contractual Obligations," to the condensed consolidated financial statements.  

I.

Cash and Cash Equivalents

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

J.

Special Deposits

Special deposits represent amounts Select Energy has on deposit with unaffiliated counterparties and brokerage firms in the amounts of $54.8 million and $103.8 million at March 31, 2006 and December 31, 2005, respectively.  SESI special deposits totaling $11.2

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million and $10.2 million are included in assets held for sale on the accompanying condensed consolidated balance sheets at March 31, 2006 and December 31, 2005, respectively.

K.

Counterparty Deposits

Balances collected from counterparties resulting from Select Energy’s credit management activities totaled $12.9 million at March 31, 2006 and $28.9 million at December 31, 2005.  These amounts are recorded as current liabilities and included as counterparty deposits on the accompanying condensed consolidated balance sheets.  To the extent Select Energy requires collateral from counterparties, cash is received as a part of the total collateral required.  The right to use such cash collateral in an unrestricted manner is determined by the terms of Select Energy’s agreements.  Key factors affecting the unrestricted status of a portion of this cash collateral include the financial standing of Select Energy and of NU as its credit supporter.

L.

Other Income, Net

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

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Investment income for NU includes equity in earnings of regional nuclear generating and transmission companies of $0.9 million of income for the three months ended March 31, 2006 and 2005.  Equity in earnings relates to NU’s investment in CYAPC, Maine Yankee Atomic Power Company (MYAPC), and Yankee Atomic Electric Company (YAEC) (Yankee companies) and the Hydro-Quebec transmission system.

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

2.

WHOLESALE CONTRACT MARKET CHANGES (NU, NU Enterprises)

NU recorded $6.8 million and $188.9 million of pre-tax wholesale contract market changes for the three months ended March 31, 2006 and 2005, respectively, related to the changes in the fair value of wholesale contracts that the company is in the process of exiting.  These amounts are reported as wholesale contract market changes, net on the condensed consolidated statements of loss.  These changes comprised the following items:

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Charges of $6.8 million and $294.3 million for the three months ended March 31, 2006 and 2005, respectively, associated with the mark-to-market on certain long-dated wholesale electricity contracts in New England and New York with municipal and other customers.  Included in the $294.3 million are changes in the fair value of wholesale contracts of $167.9 million that became marked-to-market as a result of the decision to exit the wholesale marketing business, offset by a benefit of $30 million related to previously designated wholesale contracts that were redesignated to help support the retail business.  The decision in March of 2005 to exit the wholesale marketing business changed management’s conclusion regarding the likelihood that these wholesale marketing contracts would result in physical delivery to customers and in turn resulted in a change in the first quarter of 2005 from accrual accounting to fair value accounting for the wholesale marketing contracts.  The charges for the three months ended March 31, 2006 and 2005 reflect mark-to-market movements on these contracts during these periods.

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A charge of $14.4 million for the three months ended March 31, 2005 for mark-to-market contract asset write-offs and a contract termination payment in March of 2005.

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A benefit of $94 million for the three months ended March 31, 2005 for mark-to-market gains primarily related to retail supply contracts by the wholesale business that were previously held to serve retail electric load.  The company has exited or settled many of these contracts but retains certain contracts to source retail sales.  For the three months ended March 31, 2006, retail supply contract mark-to-market charges are included in fuel, purchased and net interchange power.

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A benefit of $25.8 million for the three months ended March 31, 2005 for other wholesale contracts related to electricity that would have been delivered to customers primarily in 2005 and 2006.  As a result of exiting the wholesale marketing business, these contracts were also required to be marked-to-market.  Prior to the decision to exit the wholesale marketing business, it was management's intention to deliver the electricity to the customer and accrual accounting was used.

Included in the charge of $188.9 million for the three months ended March 31, 2005 is a $54.5 million pre-tax mark-to-market charge related to an inter-company contract between Select Energy and CL&P.  This contract was included in the portfolio of contracts Select Energy assigned to a third party wholesale power marketer, and Select Energy stopped serving CL&P on December 31, 2005.  This contract was part of CL&P’s stranded costs, and benefits received by CL&P under this contract were provided to CL&P’s ratepayers.  A $2.8 million pre-tax mark-to-market charge for the three months ended March 31, 2005 was recorded as wholesale contract market changes by Select Energy for an intercompany contract between Select Energy and WMECO for default service.  WMECO’s benefits under this contract were provided to ratepayers in the form of lower than market default service rates.  These charges were not eliminated in consolidation because on a consolidated basis NU retained the over-market obligation to the ratepayers of CL&P and WMECO.  As of December 31, 2005, these contracts expired or were fully assigned.

For further information regarding derivative assets and liabilities that are being exited, see Note 5, "Derivative Instruments," to the condensed consolidated financial statements.

3.

RESTRUCTURING AND IMPAIRMENT CHARGES (NU, NU Enterprises)

The company evaluates long-lived assets such as property, plant and equipment to determine if these assets are impaired when events or changes in circumstances occur such as the announced decisions to exit all of the NU Enterprises businesses.  

When the company believes one of these events has occurred, the determination needs to be made if a long-lived asset should be classified as an asset to be held and used or if that asset should be classified as held for sale.  For assets classified as held and used, the company estimates the undiscounted future cash flows associated with the long-lived asset or asset group and an impairment loss is recognized if the carrying amount of an asset is not recoverable and exceeds its fair value.  The carrying amount is not recoverable if it exceeds the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset.  For assets held for sale, a long-lived asset or disposal group is measured at the lower of its carrying amount or fair value less cost to sell.  

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

NU Enterprises recorded $6.1 million and $45.5 million of pre-tax restructuring and impairment charges for the three months ended March 31, 2006 and 2005, respectively, related to exiting the merchant energy businesses and its energy services businesses.  The amounts related to continuing operations are included as restructuring and impairment charges on the condensed consolidated statements of loss with the remainder included in discontinued operations.  These charges are included as part of the NU Enterprises reportable segment in Note 12, "Segment Information," to the condensed consolidated financial statements.  A summary of these pre-tax charges is as follows:  

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(1)

For segment reporting purposes, $1.8 million of retail restructuring charges and $1.7 million of competitive generation restructuring charges are included in the NU Enterprises - Services and other reportable segment as these amounts were recorded by NU Enterprises parent.  

In the first quarter of 2006, restructuring charges totaling $6.8 million were recorded for consulting fees, legal fees, employee-related costs and other costs.  Additional restructuring costs may be recognized, including professional fees and employee-related and other costs.

In the first quarter of 2006, a benefit of $0.7 million was included in impairment charges.  The $0.7 million recorded to the energy services businesses consists of a gain on the sale of the Massachusetts service location of Select Energy Contracting, Inc. - Connecticut (SECI-CT) that was offset by costs related to the sale of SESI.  

In the first quarter of 2005, an exclusivity agreement intangible asset totaling $7.2 million related to the retail marketing business was written off.

In 2005, NU Enterprises hired an outside firm to assist in valuing its energy services business and their exit.  Based in part on that firm’s work, the company concluded that $29.1 million of goodwill associated with those businesses and $9.2 million of intangible assets were impaired as of March 31, 2005.  An impairment charge of $38.3 million was recorded for the three months ended March 31, 2005.

The following table summarizes the liabilities related to restructuring costs which are recorded in accounts payable and other current liabilities on the accompanying condensed consolidated balance sheets at March 31, 2006 and December 31, 2005:  

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4.

ASSETS HELD FOR SALE AND DISCONTINUED OPERATIONS (NU, NU Enterprises)

Assets Held for Sale:  In November of 2005, NU decided to exit NU Enterprises’ retail marketing and competitive generation businesses.  In the first quarter of 2006, management determined that these businesses became held for sale under applicable accounting guidance, and should therefore be recorded at fair value less cost to sell.  NU recorded a pre-tax charge of $62.9 million in the first quarter of 2006 to record the retail marketing business at fair value less cost to sell, including derivative contracts that no longer qualified for accrual accounting because physical delivery can no longer be asserted.  The $62.9 million includes $3 million related to the estimated costs to sell the retail business, which has been reflected in restructuring and impairment charges.  The remaining amount ($59.9 million) has been included in other operation expenses.

At December 31, 2005, management determined that the wholesale and retail marketing businesses did not meet the held for sale criteria under applicable accounting guidance.  At March 31, 2006, management continues to believe the wholesale marketing business does not meet the held for sale criteria under applicable accounting guidance.

At March 31, 2006, the following businesses are accounted for as held for sale, at the lower of their carrying amount or fair value less cost to sell:  

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Select Energy's retail marketing business, which engages in retail energy marketing activities primarily in the northeastern United States,

·

NGC, which owns generating facilities,

·

Mt. Tom, which is a coal-fired generating facility,

·

Certain assets and liabilities of SESI, a performance contracting subsidiary that specializes in upgrading the energy efficiency of large governmental and institutional facilities, and

·

Certain assets and liabilities of Woods Electrical, which provides electrical services.

On May 1, 2006, NU Enterprises signed an agreement to sell the retail marketing business.  In April of 2006, NU Enterprises sold certain assets of Woods Electrical for approximately $1 million.   On May 5, 2006, NU Enterprises completed the sale of SESI.   

In April of 2006, indicative bids for the competitive generation business were received.  NU continues to expect to close on the sale of the competitive generation business by the end of 2006.  At December 31, 2005, assets held for sale and liabilities of assets held for sale consisted of certain assets and liabilities of SESI and Woods Electrical.  

These businesses are included as part of the NU Enterprises reportable segment in Note 12, "Segment Information," to the condensed consolidated financial statements.  The major classes of assets and liabilities that are held for sale at March 31, 2006 and December 31, 2005 are as follows:

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Discontinued Operations:  NU's condensed consolidated statements of loss for the three months ended March 31, 2006 and 2005 present NGC, Mt. Tom, SESI and Woods Electrical as discontinued operations.  In addition, SECI-NH (including Reeds Ferry) and Woods Network are included in discontinued operations for the three months ended March 31, 2005.  These businesses were sold in November of 2005.  

The retail marketing business is not presented as discontinued operations because separate financial information is not available for this business for the periods prior to the first quarter of 2006.  For information regarding the derivative contracts above, see Note 5, "Derivative Instruments," to the condensed consolidated financial statements.

Under discontinued operations presentation, revenues and expenses of these businesses are classified net of tax in income from discontinued operations on the condensed consolidated statements of loss and all prior periods have been reclassified.  These businesses are included as part of the NU Enterprises reportable segment in Note 12, "Segment Information," to the condensed consolidated financial statements.  Summarized financial information for the discontinued operations is as follows:  

Included in discontinued operations for the three months ended March 31, 2006 and 2005 are $50.1 million and $56.3 million, respectively, of intercompany revenues that are not eliminated in consolidation due to the separate presentation of discontinued operations.  Of this amount, $35.7 million and $14.2 million, respectively, represent revenues on intercompany contracts between the generation operations of NGC and Mt. Tom and Select Energy.  NGC's and Mt. Tom's earnings related to these contracts are included in discontinued operations while Select Energy's related expenses are included in continuing operations.  At March 31, 2006, NU does not expect that after the disposal it will have significant ongoing involvement or continuing cash flows with the entities presented in discontinued operations.

5.

DERIVATIVE INSTRUMENTS (NU, CL&P, Select Energy, Yankee Gas)

Contracts that are derivatives and do not meet the definition of a cash flow hedge and are not elected or do not meet the criteria of normal purchases or normal sales are recorded at fair value with changes in fair value included in earnings.  For those contracts that meet the definition of a derivative and meet the cash flow hedge requirements, the changes in the fair value of the effective portion of those contracts are generally recognized in accumulated other comprehensive income.  Cash flow hedges impact net income when the forecasted transaction being hedged occurs, when hedge ineffectiveness is measured and recorded, when the forecasted transaction being hedged is no longer probable of occurring, or when there is accumulated other comprehensive loss and the hedge and the forecasted transaction being hedged are in a loss position on a combined basis.  The ineffective portion of contracts that meet the cash flow hedge requirements is recognized currently in earnings.  Derivative contracts designated as fair value hedges and the items they are hedging are both recorded at fair value with changes in fair value of both items recognized currently in earnings.  Derivative contracts that are elected 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.  The change in fair value of a normal purchase or sale contract is not included in earnings.  

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The tables below summarize current and long-term derivative assets and liabilities at March 31, 2006 and December 31, 2005.  At March 31, 2006 and December 31, 2005, derivative assets and liabilities have been segregated between wholesale, retail, generation and hedging amounts.  The fair value of these contracts may not represent amounts that will be realized.  

The business activities of NU Enterprises that result in the recognition of derivative assets include exposures to credit risk to energy marketing and trading counterparties.  At March 31, 2006 and December 31, 2005, Select Energy had derivative assets from wholesale, retail, generation, and hedging activities that are exposed to counterparty credit risk.  However, a significant portion of these assets is contracted with investment grade rated counterparties or collateralized with cash.  

NU Enterprises - Wholesale:  Certain electricity and natural gas derivative contracts are part of Select Energy's wholesale marketing business that the company is in the process of exiting.  These contracts include wholesale short-term and long-term electricity supply and sales contracts, which include contracts to sell electricity to utilities under full requirements contracts and a contract to sell electricity to a municipality with a term of seven remaining years.  The fair value of electricity contracts was determined by prices from external sources for years through 2009 and by models based on natural gas prices and a heat-rate conversion factor to electricity for subsequent periods.  The fair value of the natural gas contracts was primarily determined by prices provided by external sources and active markets.  

Derivatives used in wholesale activities are recorded at fair value and included in the condensed consolidated balance sheets as derivative assets or liabilities.  Changes in fair value are recorded in the period of change, mostly in wholesale contract market changes, net on the accompanying condensed consolidated statements of loss.   

NU Enterprises - Retail:  Select Energy is in the process of exiting the retail marketing business.  Select Energy's retail portfolio includes New York Mercantile Exchange (NYMEX) futures, financial swaps, and physical power transactions, the fair value of which is based on closing exchange prices; over-the-counter forwards, and financial swaps, the fair value of which is based on the mid-point of bid and ask market prices; bilateral contracts for the purchase or sale of electricity or natural gas, the fair value of which is determined using available information from external sources; and financial transmission rights and transmission congestion contracts,

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the fair value of which is based on historical settlement prices as well as external sources.  During the first quarter of 2006, management was no longer able to conclude that physical delivery was probable under contracts that extended past the June 1, 2006 expected sale of the retail marketing business.   As a result, retail marketing derivative contracts that were previously accounted for on an accrual basis under the normal purchase and sale exception were marked to market in the first quarter of 2006 and recognized in other operation expenses.  

Select Energy maintains natural gas service agreements with certain retail customers to supply gas at fixed prices for terms extending through 2010.  Select Energy has hedged its gas supply price risk under these agreements through NYMEX futures contracts through May of 2006.  At March 31, 2006 the NYMEX futures contracts had notional values of $13.2 million and were recorded at fair value as derivative liabilities totaling $2.6 million.  At December 31, 2005 the NYMEX futures contracts had notional values of $210.5 million and were recorded at fair value as derivative assets totaling $8.2 million and derivative liabilities of $0.3 million.  

Select Energy also maintains various financial instruments to hedge its electric and gas purchases and sales through May of 2006.  These instruments include forwards, futures and swaps.  These hedging contracts, which are valued at the mid-point of bid and ask market prices, were recorded as derivative assets of $0.3 million and derivative liabilities of $6.5 million at March 31, 2006 and derivative assets of $24.4 million and derivative liabilities of $4.8 million at December 31, 2005.

As of March 31, 2006, Select Energy has retained in accumulated other comprehensive income the portion of cash flow hedges for which the hedged item is probable of being delivered.  Any hedges extending past the assumed sale date have been dedesignated.  For those cash flow hedges that were dedesignated and the hedged transactions which are no longer probable of delivery, the result was a reclassification from accumulated other comprehensive income to other operation expenses of $14.1 million.  A loss was also recognized into earnings for additional amounts not expected to be recovered because the combination of the hedging instrument and hedged transaction would have resulted in the recognition of a net loss.  In addition, a negative $2.2 million was recognized in earnings in the first three months of 2006 for the ineffective portion of cash flow hedges.   For further information, see Note 9, “Comprehensive Income,” to the condensed consolidated financial statements.

Select Energy hedges certain amounts of natural gas inventory with gas futures that are accounted for as fair value hedges.  Changes in the fair value of hedging instruments and natural gas inventory are recorded in fuel, purchased, and net interchange power on the accompanying condensed consolidated statement of loss.  The change in fair value of the futures were included in derivative liabilities and amounted to $0.1 million and $3.4 million at March 31, 2006 and December 31, 2005, respectively.  A negative pre-tax $0.1 million was recognized in earnings and recorded in fuel, purchased, and net interchange power for the first three months of 2006 for the ineffective portion of fair value hedges.

NU Enterprises - Generation:  Derivative contracts include generation asset-specific sales and forward sales of electricity at hub trading points.  The fair value of these contracts was determined by prices from external sources for years through 2009 and by models based on natural gas prices and a heat-rate conversion factor to electricity for subsequent periods.  Certain of these contracts have been recorded at fair value in revenues, while others qualified for accrual accounting until the fourth quarter of 2005 when Select Energy marked them to market when the probability of physical delivery could no longer be asserted.  Changes in fair value of generation contracts formerly accounted for on an accrual basis are recorded in wholesale contract market changes, net for those contracts that are part of continuing operations.  Changes in fair value of generation contracts that are held for sale are included in discontinued operations.  

Utility Group - Electric - Non-Trading:  CL&P has two independent power producer (IPP) contracts to purchase power that contain pricing provisions that are not clearly and closely related to the price of power and therefore do not qualify for the normal purchases and sales exception.  The fair values of these IPP non-trading derivatives at March 31, 2006 include a derivative asset with a fair value of $333.5 million and a derivative liability with a fair value of $36.9 million.  An offsetting regulatory liability and an offsetting regulatory asset were recorded, as these contracts are part of the stranded costs, and management believes that these costs will continue to be recovered or refunded in rates.  At December 31, 2005, the fair values of these IPP non-trading derivatives included a derivative asset with a fair value of $391.2 million and a derivative liability with a fair value of $32.3 million.

CL&P has entered into Financial Transmission Rights (FTR) contracts to limit the congestion costs associated with its transitional standard offer (TSO) contract.  An offsetting regulatory asset has been recorded as this contract is part of the stranded costs and management believes that these costs will continue to be recovered in rates.  At March 31, 2006, the fair value of these contracts is recorded as a derivative asset of $0.9 million and derivative liability of $3.8 million on the accompanying condensed consolidated balance sheets.

Utility Group - Electric - Hedging:  In March of 2006, CL&P entered into a forward swap 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 has locked in a Libor swap rate of 5.322 percent based on the notional amount of $125 million in debt that is expected to be issued in June of 2006.  As a cash flow hedge at March 31, 2006, the change in fair value of this agreement is recorded as a derivative asset of $3.2 million on

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the accompanying condensed consolidated balance sheets and an offsetting amount is included in accumulated other comprehensive income.  

NU Parent - Hedging:  In March of 2003, NU parent entered into a fixed to floating interest rate swap on its $263 million, 7.25 percent fixed rate note that matures on April 1, 2012.  The changes in fair value of the swap and the hedged debt instrument are recorded on the condensed consolidated balance sheets and are equal and offsetting in the condensed consolidated statements of loss.  The cumulative change in the fair value of the hedged debt of $10.9 million is included as a decrease to long-term debt on the condensed consolidated balance sheets.  The hedge is recorded as a derivative liability of $10.9 million at March 31, 2006, and $5.2 million at December 31, 2005.  The resulting changes in interest payments made are recorded as adjustments to interest expense.

6.

GOODWILL AND OTHER INTANGIBLE ASSETS (Yankee Gas, NU Enterprises)

The only NU reporting unit that currently maintains goodwill is the Yankee Gas reporting unit, which is classified under the Utility Group - gas reportable segment.  The goodwill recorded related to the acquisition of Yankee Gas is not being recovered from the customers of Yankee Gas.  The goodwill balance was $287.6 million at both March 31, 2006 and December 31, 2005.   

As a result of NU’s 2005 announcements to exit the competitive wholesale and retail marketing businesses, the competitive generation business and the energy services businesses, certain goodwill balances and intangible assets were deemed to be impaired.  During the three months ended March 31, 2005, goodwill and intangible asset balances at the NU Enterprises energy services businesses were determined to be impaired and $38.3 million in write-offs were recorded.  In addition, $7.2 million of intangible assets, related to an exclusivity agreement held by the retail marketing business, were written off.  

NU recorded amortization expense of $0.9 million for the three months ended March 31, 2005 related to intangible assets subject to amortization.  

7.

COMMITMENTS AND CONTINGENCIES

A.

Regulatory Developments and Rate Matters (CL&P, PSNH, WMECO, Yankee Gas)

Connecticut:

CTA and SBC Reconciliation:  The Competitive Transition Assessment (CTA) allows CL&P to recover stranded costs, such as securitization costs associated with the rate reduction bonds, amortization of regulatory assets, and IPP over market costs, while the 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 with the Connecticut Department of Public Utility Control (DPUC), which compares CTA and SBC revenues to revenue requirements.  For the year ended December 31, 2005, total CTA revenues exceeded the CTA revenue requirement by $60.1 million.  This amount was recorded as a regulatory liability on the accompanying condensed consolidated balance sheets.  For the same period, the SBC revenue requirement exceeded SBC revenues by $1.3 million.  Management expects a decision in this docket from the DPUC by the end of 2006 and does not expect the outcome to have a material adverse impact on CL&P's net income, financial position or cash flows.  

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

Income Taxes: 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 have been sold.   On April 18, 2006, the IRS issued a PLR to CL&P regarding the treatment of UITC and EDIT related to generation assets that CL&P has sold.  EDIT are temporary differences between book and taxable income that were recorded when the federal statutory tax rate was higher than it is now or when those differences were expected to be resolved.  The PLR holds that it would be a violation of tax regulations if the EDIT or UITC is used to reduce customers' rates following the sale of the generation assets.  The statement in the PLR is consistent with proposed regulations released in December 2005.  Previously, CL&P was ordered by the

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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.  CL&P has complied with this order.

In addition to the PLR received by CL&P, proposed regulations were issued by the Treasury Department in December of 2005.  The proposed regulations would generally allow EDIT and UITC generated by property that is no longer regulated to be returned to regulated customers without violating the tax law.  The new proposed regulations, however, would only apply to property that ceases to be regulated public utility property after December of 2005.  As such, under the proposed regulations, the EDIT and UITC cannot be used to reduce CL&P's customers' rates because CL&P sold these assets before December of 2005.  Those proposed regulations have not been finalized.

At March 31, 2006, CL&P's UITC balance is $59.3 million and EDIT balance is $14.7 million related to generation assets that have been sold.  The resolution of this contingency may result in these deferred tax balances being eliminated with a corresponding reduction to income tax expense.

Purchased Gas Adjustment:  On September 9, 2005 the DPUC issued a draft decision regarding Yankee Gas Purchased Gas Adjustment (PGA) clause charges for the period of September 1, 2003 through August 31, 2004.  The draft decision disallowed approximately $9 million in previously recovered PGA revenues associated with two separate Yankee Gas unbilled sales and revenue adjustments.  At the request of Yankee Gas, the DPUC reopened the PGA hearings on September 20, 2005 and requested that Yankee Gas file supplemental information regarding the two adjustments.  Yankee Gas complied with this request.  The DPUC issued a new decision on April 20, 2006 requiring an audit of Yankee Gas' PGA accounting methods and deferring any conclusion on the $9 million of previously recovered revenues until the completion of the audit.  Management believes the unbilled sales and revenue adjustments and resultant charges to customers through the PGA clause were appropriate.  Based on the facts of the case and the supplemental information provided to the DPUC, notwithstanding the new decision, management believes the appropriateness of the PGA charges to customers for the time period under review will be approved.  

New Hampshire:

SCRC Reconciliation Filing:  The Stranded Cost Recovery Charge (SCRC) allows PSNH to recover its stranded costs.  On an annual basis, PSNH files with the New Hampshire Public Utilities Commission (NHPUC) a SCRC reconciliation filing for the preceding calendar year.  This filing includes the reconciliation of stranded cost revenues and costs and Transition Energy Service Rate and Default Energy Service Rate, collectively referred to as Energy Service Rate (ES) revenues and costs.  The NHPUC reviews the filing, including a prudence review of the operations within PSNH's generation business segment.  The cumulative deferral of SCRC revenues in excess of costs was $330 million at March 31, 2006.  At March 31, 2006, this cumulative deferral will decrease the amount of non-securitized stranded costs to be recovered from PSNH's customers in the future from $355.3 million to $25.3 million.

From May of 2001 through January 31, 2006, the difference between PSNH ES revenues and ES costs was deferred and included in the SCRC calculation for recovery or refund.  As part of a settlement agreement with NHPUC staff and OCA regarding 2006 ES rates, PSNH requested a change in accounting for ES to allow the difference between ES revenues and costs to be included in subsequent ES rates.  The NHPUC issued its order on January 20, 2006 approving the settlement agreement including the change in accounting.  Effective February 1, 2006, PSNH began deferring the difference between ES revenues and ES costs for inclusion in the calculation of the subsequent ES rate.  At March 31, 2006, ES revenues exceeded ES costs and PSNH has deferred the $22.7 million difference.   

Litigation with IPPs:  Two wood-fired IPPs that sell their output to PSNH under long-term rate orders issued by the NHPUC brought suit against PSNH in state superior court.  The IPPs and PSNH dispute the end dates of the above-market long-term rates set forth in the respective rate orders.  Subsequent to the IPPs' court filing, PSNH petitioned the NHPUC to decide this matter, and requested that the court stay its proceeding pending the NHPUC's decision.  By court order dated October 20, 2005, the court granted PSNH's motion to stay indicating that the NHPUC had primary jurisdiction over this matter.  PSNH recovers the over market costs of IPP contracts through the SCRC.

On November 11, 2005, the IPPs filed motions with the NHPUC seeking to disqualify two of the three NHPUC commissioners from participating in this proceeding.  As a result, the NHPUC chair excused himself from participating in this proceeding and the term of the second NHPUC commissioner under challenge expired.  On December 7, 2005, the IPPs then filed an interlocutory appeal with the New Hampshire Supreme Court (Supreme Court) on the basis that the forum for resolving this dispute is in state superior court.  On February 7, 2006, the Supreme Court declined to accept the IPP's interlocutory appeal.  As a result, the matter will return to the NHPUC for decision.  

Environmental Legislation:  In November of 2005, PSNH and various legislative, state government and environmental leaders announced that they had reached a consensus to propose legislation to reduce the level of mercury emissions from PSNH's coal-fired plants by 2013 with incentives for early reductions.  A bill to implement that agreement passed the New Hampshire House of Representatives in late-March of 2006, passed the New Hampshire Senate on April 20, 2006 and will be sent to New Hampshire

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Governor Lynch for signing into law.  PSNH intends to comply with the legislation by installing wet scrubber technology at its two Merrimack coal units, which combined generate 433 megawatts (MW) by mid-2013.  PSNH currently estimates the cost to comply of approximately $250 million, however, this amount is subject to change as final design is undertaken.  State law, this new bill and PSNH's restructuring agreement provide for the recovery of its generation costs, including the cost to comply with state environmental regulations.  

Massachusetts:

Transition Cost Reconciliation:  WMECO filed its 2005 transition cost reconciliation with the Massachusetts Department of Telecommunications and Energy (DTE) on March 31, 2006.  This filing reconciles transition costs, default service costs and retail transmission costs with their associated revenues collected from customers.  The DTE has not yet reviewed this filing or issued a schedule for review.  Therefore the timing of a decision is uncertain at this time.  However once reviewed by the DTE, management does not expect the outcome to have a material adverse impact on WMECO's net income or financial position.

B.

NRG Energy, Inc. Exposures (CL&P, Yankee Gas)

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

C.

Long-Term Contractual Arrangements (CL&P, Merchant Energy)

CL&P:  These amounts represent commitments for various services and materials associated with the Bethel, Connecticut to Norwalk, Connecticut and the Middletown, Connecticut to Norwalk, Connecticut transmission projects as of March 31, 2006.  

Merchant Energy:  Select Energy maintains long-term agreements to purchase energy as part of its portfolio of resources to meet its actual or expected sales commitments.  The majority of these purchase commitments are being exited.  Certain purchase commitments are accounted for on the accrual basis, while the remaining commitments are recorded at their mark-to-market value.  These purchase commitments at March 31, 2006 are as follows:

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

The amounts and timing of the costs associated with Select Energy’s purchase agreements will be impacted by the exit from the wholesale and retail marketing businesses.

D.

Deferred Contractual Obligations (NU, CL&P, PSNH, WMECO)

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

The FERC staff filed testimony that recommended a $38 million decrease in the requested rate increase claiming that CYAPC should have used a different gross domestic product (GDP) escalator.  NU's share of this recommended decrease is $18.6 million.  

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On November 22, 2005, a FERC administrative law judge issued an initial decision finding no imprudence on CYAPC's part.  However, the administrative law judge did agree with the FERC staff’s position that a lower GDP escalator should be used for calculating the rate increase and found that CYAPC should recalculate its decommissioning charges to reflect the lower escalator.  A final order from the FERC is expected later in 2006.  Management expects that if the FERC staff's position on the decommissioning GDP cost escalator is found by the FERC to be more appropriate than that used by CYAPC to develop its proposed rates, then CYAPC would review whether to reduce its estimated decommissioning obligation and reduce its customers' obligations, including the obligation of CL&P, PSNH and WMECO.  Due to the terms of the settlement of state court litigation between CYAPC and Bechtel Power Corporation (Bechtel) over the terminated decommissioning contract, Bechtel has withdrawn from the FERC proceedings.

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

On June 10, 2004, the DPUC and the Connecticut Office of Consumer Counsel (OCC) filed a petition with the FERC seeking a declaratory order that CYAPC be allowed to recover all decommissioning costs from its wholesale purchasers, including CL&P, PSNH and WMECO, but that such purchasers may not be allowed to recover in their retail rates any costs that the FERC might determine to have been imprudently incurred.  The FERC and CYAPC have asked the court to dismiss the case and the DPUC has objected to a dismissal.  NU cannot predict the timing or the outcome of these proceedings.

Bechtel Litigation:  CYAPC and Bechtel previously commenced litigation in Connecticut Superior Court over CYAPC's termination of Bechtel's contract for the decommissioning of CYAPC's nuclear generating plant.  After CYAPC terminated the contract, responsibility for decommissioning was transitioned to CYAPC.  On March 7, 2006, CYAPC and Bechtel executed a settlement agreement terminating this litigation.  Bechtel paid CYAPC $15 million and the parties have withdrawn their litigation from state court.  CYAPC expects to credit the net proceeds from the settlement agreement against decommissioning costs recoverable from its customers, including CL&P, PSNH and WMECO.

Spent Nuclear Fuel Litigation:  CYAPC, YAEC and MYAPC commenced litigation in 1998 charging that the federal government breached contracts it entered into with each company in 1983 under the Nuclear Waste Policy Act of 1982.  The trial ended on August 1, 2004 and a verdict has not been reached.  Post-trial findings of facts and final briefs were filed by the parties in January of 2005.  The Yankee Companies' current rates do not include an amount for recovery of damages in this matter.  Management can predict neither the outcome of this matter nor its ultimate impact on NU.

YAEC:  In November of 2005, YAEC established an updated estimate of the cost of completing the decommissioning of its plant resulting in an increase of approximately $85 million.  NU's share of the increase in estimated costs is $32.7 million.  On January 31, 2006, the FERC issued an order accepting the rate increase, effective February 1, 2006, subject to refund by YAEC after hearings and settlement judge proceedings.  

On May 1, 2006, YAEC filed with the FERC a proposed settlement agreement with the DPUC, the Massachusetts Attorney General and the Vermont Department of Public Service.  Under the proposed settlement agreement, YAEC agreed to revise its November 2005 decommissioning cost increase from $85 million to $56.8 million.  The revision includes adjustments for contingencies and projected escalation and certain decontamination and dismantlement (D&D) expenses.  Other terms of the proposed settlement agreement include extending the collection period for charges through December 2014, reconciling and adjusting future charges based on actual D&D expenses and the decommissioning trust fund's actual investment earnings.  The company believes that its share of the increase in decommissioning costs will ultimately be recovered from the customers of CL&P, PSNH and WMECO.  NU has a 38.5 percent ownership interest in YAEC.  The proposed settlement agreement will become effective upon approval from the FERC, but should not materially affect the level of 2006 charges.

E.

Consolidated Edison, Inc. Merger Litigation

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

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

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In an opinion dated October 12, 2005, a panel of three judges at the Second Circuit held that the shareholders of NU had no right to sue Con Edison for its alleged breach of the parties' Merger Agreement.  NU's request for a rehearing was denied on January 3, 2006.  This ruling left intact the remaining claims between NU and Con Edison for breach of contract, which include NU’s claim for recovery of costs and expenses of approximately $32 million and Con Edison's claim for damages of "at least $314 million."  NU opted not to seek review of this ruling by the United States Supreme Court.  On April 7, 2006, NU filed its motion for partial summary judgment on Con Edison’s damage claim which asserts that NU is entitled to judgment in its favor with respect to this claim based on the undisputed material facts and applicable law.  At this stage, NU cannot predict the outcome of this matter or its ultimate effect on NU.

F.

Environmental Matters

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 condensed 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, these costs have increased by $4.5 million during the three months ended March 31, 2006.  At March 31, 2006 and December 31, 2005, NU had $32.6 million and $30.7 million, respectively, recorded as environmental reserves.  A reconciliation of the activity in these reserves for the three months ended March 31, 2006 is as follows:

Manufactured gas plant (MGP) sites comprise the largest portion of NU’s environmental liability and the environmental reserves related to these sites increased by $4.8 million in the first three months of 2006.  MGPs are sites that manufactured gas from coal which produced certain byproducts that may pose a risk to human health and the environment.  At March 31, 2006 and December 31, 2005, $27.6 million and $25.3 million, respectively, represents amounts for the site assessment and remediation of MGPs.

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

8.

MARKETABLE SECURITIES

The following is a summary of NU’s available-for-sale securities related to NU's investment in Globix Corporation (Globix), NU's Supplemental Executive Retirement Plan (SERP) assets and WMECO's prior spent nuclear fuel trust assets, which are recorded at their fair values and are included in current and long-term marketable securities on the accompanying condensed consolidated balance sheets.  Changes in the fair value of these securities are recorded as unrealized gains and losses in accumulated other comprehensive income:

(a)

NU had an investment in the common stock of NEON Communications, Inc. (NEON), a provider of optical networking services.  On March 8, 2005, NEON merged with Globix Corporation (Globix).  In connection with the closing of the merger, a $0.1 million after-tax loss was recognized in the first quarter of 2005 and a pre-tax positive $0.4 million change in fair value

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subsequent to March 8, 2005 was included in accumulated other comprehensive income.  On April 6, 2006, NU sold its investment in Globix.  This sale resulted in net proceeds of $6.7 million and a pre-tax gain of $3 million.

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

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

For information related to the change in net unrealized holding gains and losses included in shareholders' equity, see Note 9, "Comprehensive Income," to the condensed consolidated financial statements.

For the three months ended March 31, 2006 and 2005, realized gains and losses recognized on the sale of available-for-sale securities are as follows:

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For the three months ended March 31, 2006 and 2005, realized gains of $0.2 million and $0.1 million, respectively, are included in other income, net on the accompanying condensed consolidated statements of loss.  For the three months ended March 31, 2006 and 2005, realized losses of $37,000 and $11,000, respectively, relating to the WMECO spent nuclear fuel trust are included in fuel, purchased and net interchange power on the accompanying condensed consolidated statements of loss.

NU utilizes the specific identification basis method for the Globix and SERP securities and the average cost basis method for the WMECO prior spent nuclear fuel trust to compute the realized gains and losses on the sale of available-for-sale securities.

Proceeds from the sale of these securities, including proceeds from short-term investments, totaled $18.3 million and $18.7 million for the three months ended March 31, 2006 and 2005, respectively.

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

NU's investment in Globix and all other available-for-sale equity securities are included in the less than one year maturity category in the table above.

9.

COMPREHENSIVE INCOME (NU, CL&P, PSNH, WMECO, NU Enterprises, Yankee Gas)

Total comprehensive income, which includes all comprehensive income/(loss) items by category, for the three months ended March 31, 2006 and 2005 is as follows: