CONNECTICUT LIGHT & POWER CO - Quarter Report: 2006 June (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, the first quarter 2006 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, and the current report on Form 8-K dated June 7, 2006 that updated the 2005 Form 10-K to present certain portions of the business as discontinued operations for all periods.  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 June 30, 2006, and the results of operations for the three and six months ended June 30, 2006 and 2005 and cash flows for the six months ended June 30, 2006 and 2005.  The results of operations and statements of cash flows for the six months ended June 30, 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 statements of income/(loss) and CL&P's, PSNH's and WMECO's condensed consolidated statements of income, the classification of expense amounts relating to compensation costs not recoverable from regulated customers, advertising costs, environmental charges and rate reduction bond service fees previously included in other income, net was changed to a more preferable presentation.  These expense amounts, which were reclassified to other operation expense for NU, CL&P, PSNH, and WMECO, totaled $3.7 million, $1.9 million, $1 million and $0.2 million, respectively, for the three months ended June 30, 2005.  Similar amounts for the six months ended June 30, 2005 for NU, CL&P, PSNH, and WMECO totaled $9.1 million, $2.9 million, $1.9 million and $0.4 million, respectively.  These reclassifications had no impact on the companies' results of operations, cash flows, financial condition or changes in shareholders' equity.  

NU’s condensed consolidated statements of income/(loss) for all periods presented classify the operations for the following as discontinued operations, which were reflected in the report on Form 8-K dated June 7, 2006:

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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 Services, 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 June 30, 2006, all assets and liabilities of NGC and Mt. Tom 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."

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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 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 and may affect the accounting treatment of CL&P Receivables Corporation (CRC), a wholly owned subsidiary of CL&P.  Implementation of this statement is not expected to have a material effect on the company's financial statements.

Uncertain Tax Positions:  On July 13, 2006, the FASB issued FASB Interpretation No. (FIN) 48, "Accounting for Uncertainty in Income Taxes - An Interpretation of FASB Statement No. 109."  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 in the first quarter of 2007 prospectively as a change in accounting principle with a cumulative effect adjustment reflected in the opening balance of retained earnings.  The company is currently evaluating the potential impacts of FIN 48 on its financial statements.

C.

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.   Amortization and deferrals of regulatory assets are included on a net basis in amortization expense on the accompanying condensed consolidated statements of income/(loss).  

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

At June 30, 2006, CL&P's CTA was recorded as a $73 million regulatory asset as CTA unrecovered costs were in excess of CTA collections due to refunds to customers.  At December 31, 2005, CTA collections were in excess of CTA costs and a $26 million regulatory liability was recorded.  

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Included in NU's other regulatory assets/(overrecoveries) above are regulatory assets associated with the implementation of FIN 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143," totaling $50.8 million at June 30, 2006 and $47.3 million at December 31, 2005.  A portion of these ARO regulatory assets totaling $17.7 million at June 30, 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 also probable of recovery.  

The restructuring settlement agreement between PSNH and the state of New Hampshire, which was implemented in May of 2001, requires that non-securitized stranded costs be recovered from PSNH's customers prior to a recovery end date of October 31, 2007.  On June 30, 2006, under the terms of the restructuring settlement agreement, PSNH completed the recovery of its non-securitized stranded costs and offset the remaining stranded cost regulatory asset balances totaling $345.8 million against an offsetting regulatory liability for the cumulative deferral of Stranded Cost Recovery Charge (SCRC) revenues.  As of June 30, 2006 PSNH had $2.4 million of accumulated SCRC costs remaining for recovery.  The SCRC costs will be recovered from customers over the six month period beginning in July of 2006 through December of 2006 in the SCRC rate.  

Included in WMECO's other regulatory assets/(overrecoveries) are $25.4 million and $37.8 million at June 30, 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 $12.3 million and $11.2 million of regulatory costs at June 30, 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 $844.3 million of regulatory liabilities at June 30, 2006 and $1.3 billion at December 31, 2005, including revenues subject to refund.  These amounts are comprised of the following:

For information regarding derivative assets, see Note 5, "Derivative Instruments."

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D.

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 income/(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 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 amounts to calculate AFUDC.  Fifty percent of construction work in progress of CL&P's four major transmission projects in southwest Connecticut is recovered currently in rates.  The remaining fifty percent earns AFUDC.  The increase in AFUDC from borrowed funds during the three months ended June 30, 2006 as compared to the three months ended June 30, 2005 results from CL&P’s issuance of additional debt in June of 2006.  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 2006 as compared to 2005.  

E.

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).  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 minimus effect on NU’s net income/(loss) and no effect on NU’s income/(loss) per share.  For the six months ended June 30, 2006, a tax benefit in excess of compensation cost totaling $0.2 million increased cash flows from financing activities.  

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.  

NU accounts 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 they occurred.  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 was recorded in the second quarter of 2006 or will be recorded in future periods as a result of a plan amendment that was effective on February 1, 2006.  

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

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 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.

Restricted Shares and Restricted Share Units:  NU has granted restricted shares under the 2004, 2003 and 2002 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 restricted shares and RSUs for the six months ended June 30, 2006 is as follows:

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The weighted average grant date fair value per share for restricted shares vested was $14.60 for the six months ended June 30, 2005.  The total weighted average fair value of restricted shares vested was $1.4 million during the six months ended June 30, 2005.  No shares were vested during the three months ended June 30, 2006 or 2005.  

The total compensation cost recognized during the three and six months ended June 30, 2006 was $0.1 million and $0.3 million, net of taxes of approximately $0.1 million and $0.2 million, respectively.  The total compensation cost recognized during the three and six months ended June 30, 2005 was $0.2 million and $0.4 million, net of taxes of approximately $0.1 million and $0.2 million, respectively.  

The weighted average grant date fair value per share for RSUs granted during the three and six months ended June 30, 2005 was $20.86 and $18.79, respectively.  The weighted average grant date fair value per share for RSUs paid during the three and six months ended June 30, 2005 was $18.90 and $19.06, respectively.  The total weighted average fair value of RSUs paid during the three and six months ended June 30, 2005 was approximately $4 thousand and $1.8 million, respectively.  

The total compensation cost recognized for the three and six months ended June 30, 2006 was $0.8 million and $1.4 million, respectively, net of taxes of approximately $0.5 million and $0.9 million, respectively.  The total compensation cost recognized during the three and six months ended June 30, 2005 was $0.8 million and $1 million, net of taxes of approximately $0.6 million and $0.7 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 was estimated on the date of grant using the Black-Scholes option pricing model.  The weighted average remaining contractual lives for the options outstanding at June 30, 2006 is 4.4 years.

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A summary of stock option transactions is as follows:

Cash received for options exercised during the three and six months ended June 30, 2006 totaled $0.9 million and $1 million, respectively.  

Employee Share Purchase Plan (ESPP):  NU maintains an ESPP for all eligible employees.  Prior to February 1, 2006, NU common shares were purchased by employees 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 on the last day of the purchase period.  As a result, the ESPP qualifies as a non-compensatory plan under SFAS No. 123(R).

The following table illustrates the pro forma effect if NU had applied the recognition provisions of SFAS No. 123 to share-based compensation:

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

F.

Sale of Customer Receivables

At June 30, 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 CRC.  CRC can sell up to $100 million of an undivided interest in its accounts receivable and unbilled revenues.  At June 30, 2006 and December 31, 2005, the reserve requirements calculated in accordance with the Receivables Purchase and Sale Agreement were $17.8 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 June 30, 2006 and December 31, 2005, amounts sold to CRC by CL&P but not sold to the financial institution totaling $272.1 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 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 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."  

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In addition, the company is in the process of evaluating the effect of SFAS No. 156 on its accounting for the sale of these receivables.  See Note 1B, "Accounting Standards Issued But Not Yet Adopted," for further information.

G.

Investment in CYAPC

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 $23.4 million at June 30, 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.  This FERC proceeding is ongoing.  Parties to these proceedings are currently engaged in settlement discussions, the outcome of which management cannot determine at this time.  Management believes that the FERC proceeding has not impaired the value of its investment in CYAPC at June 30, 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," and Note 1K, "Other Income, Net."

H.

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.

I.

Special Deposits

Special deposits represent amounts Select Energy, Inc. (Select Energy) has on deposit with unaffiliated counterparties and brokerage firms in the amounts of $17.8 million and $103.8 million at June 30, 2006 and December 31, 2005, respectively.  SESI special deposits totaling $10.2 million at December 31, 2005 are included in assets held for sale on the accompanying condensed consolidated balance sheets.  SESI was sold in the second quarter of 2006.

J.

Counterparty Deposits

Balances collected from counterparties resulting from Select Energy’s credit management activities totaled $6.7 million at June 30, 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.

K.

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/(losses) of regional nuclear generating and transmission companies of $(2.2) million and $1 million for the three months ended June 30, 2006 and 2005, respectively, and $(1.2) million and $1.9 million for the six months ended June 30, 2006 and 2005, respectively.  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.

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.  Because the contingency surrounding these regulatory assets existed at June 30, 2006, the write-off was recorded in the second quarter.  NU recorded a total after-tax write-off of $3 million ($2.1 million, $0.3 million and $0.6 million for CL&P, PSNH and WMECO, respectively) for its ownership share of this charge, which is included in investment income in the tables above.

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

L.

Asset Retirement Obligations

The Department of Public Utility Control (DPUC) initiated a proceeding relating to an incident involving the failure of certain porcelain cutouts that are used in CL&P's distribution system.  A cutout is a protective device that stops the flow of electricity if there is a surge.  On April 26, 2006, the DPUC issued an order requiring CL&P to report its progress in replacing porcelain cutouts.  As a result of a requirement to remove the porcelain cutouts, an asset retirement obligation (ARO) has been recorded.  At June 30, 2006, the fair value of the ARO asset recorded is $4.7 million, accumulated depreciation is $0.6 million, and the ARO liability is $4.7 million.  The charge to record the $0.6 million of accumulated depreciation was recorded as a regulatory asset, as management believes that this amount is recoverable in rates.  Removal of these assets is expected to occur over three years beginning in 2006.  

2.

WHOLESALE CONTRACT MARKET CHANGES (NU, NU Enterprises)

NU recorded $12.9 million and $69.6 million of pre-tax wholesale contract market changes for the three months ended June 30, 2006 and 2005, respectively, and $19.7 million and $258.5 million for the six months ended June 30, 2006 and 2005, respectively, related to the changes in the fair value of wholesale contracts.  These changes are comprised of the following items:

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Charges of $11.9 million and $18.7 million for the three and six months ended June 30, 2006 and $64.2 million and $358.5 million for the three and six months ended June 30, 2005, respectively, associated with the mark-to-market on certain long-dated wholesale electricity contracts in New England, New York and PJM and contracts to purchase generation products in New England and New York.  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.  This in turn resulted in a change in the first quarter of 2005 from accrual accounting to mark-to-market accounting for the wholesale marketing contracts.  

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A charge of $1 million in the second quarter and first half of 2006 related to the mark-to-market of certain asset specific sales and forward sales of electricity at hub points for generation contracts.  

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A positive mark-to-market of $100 million in the first half of 2005.  This includes 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 used to serve retail electric load and a benefit of $20.4 million for other wholesale contracts related to electricity that would have been delivered to customers primarily in 2005 and 2006.  The positive mark-to-market is offset by a charge of $14.4 million for mark-to-market contract asset write-offs and a contract termination payment in March of 2005.

·

A charge of $5.4 million in the second quarter of 2005 related to a decrease in the mark-to-market on certain retail marketing supply contracts and other wholesale contracts (included in the first half benefit of $20.4 million above) related to electricity for delivery to customers primarily in 2005 and 2006.

Included in the mark-to-market on long-term wholesale electricity contracts is a $15.7 million and $70.2 million pre-tax mark-to-market charge for the three and six months ended June 30, 2005, respectively, related to an intercompany 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 in the form of lower than market standard offer service rates.  A $2.8 million pre-tax mark-to-market charge in the first half of 2005 was recorded as wholesale contract market changes by Select Energy for the intercompany contract between Select Energy and WMECO for default service from April to June of 2005.  There were no wholesale contract market changes in the second quarter of 2005 as this contract expired on June 30, 2005.  WMECO’s benefits under this contract were provided to its 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 its ratepayers of CL&P and WMECO.

 

For further information regarding derivative assets and liabilities, see Note 5, "Derivative Instruments."

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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 2005 announced decisions to exit all of the NU Enterprises businesses.  

When the company believes one of these events has occurred, a 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.  

NU Enterprises recorded $9.5 million and $2.3 million of pre-tax restructuring and impairment charges for the three months ended June 30, 2006 and 2005, respectively, and $15.6 million and $47.8 million for the six months ended June 30, 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 income/(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."  A summary of these pre-tax charges is as follows:  

For segment reporting purposes, $0.4 million and $0.4 million of wholesale marketing restructuring charges, $0.9 million and $2.6 million of Retail Marketing restructuring charges and $0.9 million and $2.6 million of Competitive Generation restructuring charges for the three and six months ended June 30, 2006, respectively, are included in the NU Enterprises - Services and Other reportable segment, as these amounts were recorded by NU Enterprises parent.

On May 5, 2006, NU Enterprises completed the sale of SESI to Ameresco, Inc. (Ameresco).  In connection with the closing of this transaction, NU Enterprises paid Ameresco approximately $7.7 million and recorded a pre-tax restructuring charge of $5.6 million in the second quarter of 2006 in the Energy Services and Other segment, which is included in loss from sale of discontinued operations on the accompanying condensed consolidated statements of income.  In addition to the $5.6 million charge, a restructuring charge of $0.9 million was recorded in the first quarter of 2006, resulting in a $6.5 million loss from sale of discontinued operations recorded in the first half of 2006.  Offsetting the first half loss is a restructuring benefit of $1.7 million for the gain on the sale of Massachusetts service location of Select Energy Contracting, Inc. - Connecticut (SECI-CT).  In addition to these charges, restructuring charges of $1.2 million and $1.7 million were recorded in the first quarter and first half of 2006 for consulting fees, legal fees, employee-related costs and other costs.

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On June 1, 2006, NU Enterprises completed the sale of SENY to Hess Corporation (Hess).  In connection with the closing of this transaction, NU Enterprises recorded restructuring charges of $0.3 million to the Retail Marketing segment, which is included in restructuring and impairment charges on the accompanying condensed consolidated statements of income/(loss) for the three and six months ended June 30, 2006.  In addition to the $0.3 million charge, restructuring charges of $0.5 million and $5.2 million were recorded in the first quarter and first half of 2006 for consulting fees, legal fees, employee-related costs and other costs.

In the second quarter and first half of 2006, $0.3 million of impairments were recorded to the Competitive Generation segment related to certain long lived assets of Northeast Generation Services Company (NGS) that were no longer recoverable and written off.  Restructuring charges of $0.9 million and $2.6 million were recorded in the first quarter and first half of 2006 for consulting fees, legal fees, employee-related and other costs.

In the second quarter and first half of 2006, $0.6 million of restructuring charges were recorded to the Wholesale Marketing segment for consulting fees, legal fees, employee-related and other costs.  

In the first half of 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.  In the second quarter of 2005, the energy services businesses and NU Enterprises parent recorded an additional impairment charge of $0.8 million due to the impairment of certain fixed assets resulting in a total impairment charge of $39.1 million for the first half of 2005 included in the Energy Services and Other segment.  

Also in the first quarter of 2005, an exclusivity agreement intangible asset included in the Retail Marketing segment totaling $7.2 million was written off.  

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 June 30, 2006 and December 31, 2005:  

In addition to the $0.6 million of retail marketing severance costs included in restructuring charges above, $3.7 million of other retail marketing severance costs and other employee benefits were recorded in other operating expenses on the accompanying condensed consolidated statements of income/(loss) for the six months ended June 30, 2006 because these amounts are for severance under an existing benefit arrangement.  For further information, see Note 11, "Pension Benefits and Postretirement Benefits Other Than Pensions."

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4.

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

A summary of the NU Enterprises businesses held for sale status as of June 30, 2006 and December 31, 2005, as well as the discontinued operations status for all periods presented including date sold, is as follows:

Assets Held for Sale:  In November of 2005, NU decided to exit NU Enterprises’ retail marketing and competitive generation businesses.  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.  

In the first quarter of 2006, management determined that the retail marketing and competitive generation businesses now met held for sale criteria under applicable accounting guidance, and should therefore be recorded at the lower of carrying amount or fair value less cost to sell.  In April of 2006, indicative bids for the competitive generation business were received.  The retail marketing business was reduced to its fair value less cost to sell in the first half of 2006 by a $53.9 million pre-tax charge which was recorded in other operating expenses.  The competitive generation assets are carried at their historical carrying value, which is less than their fair value less cost to sell.  For further information see Note 12, "Segment Information," and Note 13, "Subsequent Events."

At June 30, 2006, management continues to believe the wholesale marketing business does not meet the held for sale criteria under applicable accounting guidance.

Certain assets and liabilities of Select Energy's retail marketing business remaining which will be assigned or transferred to Hess, are recorded at fair value less cost to sell and are included in assets held for sale and liabilities of assets held for sale.  

The businesses above are included as part of the NU Enterprises reportable segment in Note 12, "Segment Information." The major classes of assets and liabilities that are held for sale at June 30, 2006 and December 31, 2005 are as follows (amounts at December 31, 2005 will not be comparable to amounts at June 30, 2006 as the assets held for sale portfolio has changed):

Discontinued Operations:  NU's condensed consolidated statements of income/(loss) for all periods presented classify NGC, Mt. Tom, SESI and Woods Electrical in discontinued operations.  In addition, SECI-NH (including Reeds Ferry) and Woods Network are included in discontinued operations for the three and six months ended June 30, 2005.  These businesses were sold in November of 2005.  

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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.  

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 income/(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."  Summarized financial information for the discontinued operations is as follows:  

On May 5, 2006, NU Enterprises completed the sale of SESI to Ameresco and recorded a pre-tax charge to income of $5.6 million ($3.3 million net of tax) in the second quarter of 2006.  

Included in discontinued operations are $48.2 million and $98.3 million for the three and six months ended June 30, 2006, respectively, and $57.2 million and $113.4 million for the three and six months ended June 30, 2005, respectively, of intercompany revenues that are not eliminated in consolidation due to the separate presentation of discontinued operations.  Of these amounts, $48.3 million and $98.1 million for the three and six months ended June 30, 2006, respectively, and $52.1 million and $105 million for the three and six months ended June 30, 2005, respectively, represent revenues on intercompany contracts between the generation operations of NGC and Mt. Tom and Select Energy.  NGC’s and Mt. Tom’s revenues and earnings related to these contracts are included in discontinued operations while Select Energy’s related expenses and losses are included in continuing operations.  

At June 30, 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 requirements to be treated as a cash flow hedge or 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, including those related to initial and ongoing documentation, 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 meet the requirements of a normal purchase or sale, and are so designated, 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 June 30, 2006 and December 31, 2005.  At June 30, 2006 and December 31, 2005, derivative assets and liabilities of NU Enterprises 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 June 30, 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, a contract to sell electricity to a municipality with a term of seven remaining years, and two contracts to purchase the output of generating plants.  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 income/(loss).   

NU Enterprises - Retail:  On June 1, 2006, Select Energy closed on the sale of its retail marketing business to Hess and the related derivative assets and liabilities were transferred to Hess, except in cases where a customer has not yet consented to assignment.  The remaining retail derivative assets and liabilities are recorded at fair value, which is determined using information from available external sources.  During the first quarter of 2006, management was no longer able to conclude that physical delivery was probable

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under contracts that extended past the expected June 1, 2006 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.  At June 30, 2006, Select Energy had no hedges.  A negative $2.2 million was recognized in earnings as of March 31, 2006 for the ineffective portion of cash flow hedges delivered through June 1, 2006.  The retail marketing business was reduced to its fair value less cost to sell in the first half of 2006 by a $53.9 million pre-tax charge which was recorded in other operating expenses.  

As of June 30, 2006, Select Energy has derivative assets and liabilities totaling $5.3 and $4.3 million, respectively, related to back-to-back agreements for electric and gas sourcing contracts for which Select Energy has not yet received consent from the customers to assign the contracts to Hess.  

At December 31, 2005, Select Energy maintained natural gas service agreements with certain retail customers to supply gas at fixed prices for terms extending through 2010.  New York Mercantile Exchange (NYMEX) futures contracts acquired to meet these commitments were recorded at fair value as derivative assets totaling $8.2 million and derivative liabilities of $0.3 million.  Select Energy also maintained various financial instruments to hedge its electric and gas purchases and sales which included forwards, futures and swaps.  At December 31, 2005, these hedging contracts, which were valued at the mid-point of bid and ask market prices, were recorded as derivative assets of $24.4 million and derivative liabilities of $4.8 million.  These amounts were zero at June 30, 2006 because the contracts expired or were assigned to Hess.

Select Energy hedged 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 were recorded in fuel, purchased, and net interchange power.  The change in fair value of the futures were included in derivative liabilities and amounted to $3.4 million at December 31, 2005.  These amounts were zero at June 30, 2006 because the contracts expired or were assigned to Hess.

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 the period of the contracts.  Certain of these short-term forward purchase and sales contracts have been recorded at fair value in revenues, while other generation asset specific sales and forward sales of electricity at hub points qualified for accrual accounting until the fourth quarter of 2005 when Select Energy marked them to market because 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.  These contracts extend through 2008.

Utility Group - Gas - Non-Trading:  Yankee Gas’s non-trading derivatives consist of peaking supply arrangements to serve winter load obligations and firm retail sales contracts with options to curtail delivery.  These contracts are subject to fair value accounting as these contracts are derivatives that cannot be designated as normal purchase and sales because of the optionality in the contract terms.  Non-trading derivatives at June 30, 2006 included assets of $0.2 million.  At December 31, 2005, non-trading derivatives included assets of $0.1 million and liabilities of $0.4 million.

Utility Group - Electric - Non-Trading:  CL&P has contracts with two independent power producers (IPP) 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 June 30, 2006 include a derivative asset with a fair value of $325.2 million and a derivative liability with a fair value of $35.7 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 cost of service, regulated 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) contracts.  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 June 30, 2006, the fair value of these contracts is recorded as a derivative asset of $0.5 million and derivative liability of $1.7 million on the accompanying condensed consolidated balance sheets.  The fair value of CL&P's FTRs at December 31, 2005 was zero.  

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 income/(loss).  The cumulative change in the fair value of the hedged debt of $14.5 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 $14.5 million at June 30, 2006, and $5.2 million at December 31, 2005.  The resulting changes in interest payments made are recorded as adjustments to interest expense.

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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 June 30, 2006 and December 31, 2005.   

As a result of NU’s 2005 announcements to exit all of NU Enterprises' businesses, certain goodwill balances and intangible assets were deemed to be impaired.  During the six months ended June 30, 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 $0.2 million and $1.1 million for the three and six months ended June 30, 2005, respectively, 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.  On July 24, 2006, the DPUC issued a final decision which approved the reconciliation of the CTA and SBC rates for the year 2005.  

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 were 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.  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.  

CL&P's UITC balance is $59 million and EDIT balance is $15 million, totaling $74 million related to generation assets that have been sold.  On July 27, 2006, the DPUC held that the UITC and EDIT amounts were no longer required to be held in their existing accounts.  The $74 million balance will be reflected as a reduction of CL&P's third quarter 2006 income tax expense and will increase CL&P's earnings by the same amount.  

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 deferred 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, management believes the appropriateness of the PGA charges to customers for the time period under review will be approved.  

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New Hampshire:

DS, SCRC and ES Rates: On January 20, 2006, the New Hampshire Public Utilities Commission (NHPUC) approved a PSNH request to move reconciliation of its generation costs and revenues (including the prudency of its generation operations) from the Stranded Cost Recovery Charge (SCRC) to Energy Service (ES) proceedings.  The change was effective on February 1, 2006.

On May 1, 2006, PSNH filed its 2005 SCRC reconciliation with the NHPUC, and proceedings have begun.  While management believes that the operation of the generation business segment has been prudent and consistent with industry practices, it is unable to determine the impact, if any, of the NHPUC’s review of the SCRC on PSNH’s earnings or financial position.

On May 30, 2006, PSNH filed with the NHPUC to increase its delivery service (DS) rate by approximately $50 million, to decrease its SCRC to recognize the full recovery of its non-securitized part 3 stranded costs, and to decrease its ES rate to recognize changes in its power supply costs.  On June 29, 2006, the NHPUC approved a temporary DS rate increase of $24.5 million, the requested decrease in the SCRC and a decrease in the ES rate.  All rate changes were effective on July 1, 2006.  The impact of the combined rate changes is an overall decrease of 15.5 percent.  The temporary DS rate increase will be reconciled to the NHPUC decision in a full rate case to be decided in 2007, effective back to July 1, 2006.  

Coal Procurement Docket:  During the second quarter of 2006, the NHPUC opened a docket to review PSNH's coal procurement and coal transportation policies and procedures.  PSNH is currently responding to data requests from the NHPUC's outside consultant.  While management believes its coal procurement and transportation policies and procedures are prudent and consistent with industry practice, it is unable to determine the impact, if any, of the NHPUC's review on PSNH's earnings or financial position.

Environmental Legislation:  In April of 2006, New Hampshire adopted legislation requiring PSNH to reduce the level of mercury emissions from its coal-fired plants by 2013 with incentives for early reductions.  To comply with the legislation PSNH intends to install wet scrubber technology by mid-2013 at its two Merrimack coal units, which combined generate 433 megawatts (MW).  PSNH currently estimates the cost to comply with this law to be approximately $250 million.  However, this amount is subject to change as final design of the project is undertaken.  State law 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.  Management does not expect the outcome of the DTE's review to have a material adverse impact on WMECO's earnings 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 refunding of approximately $30 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, 2) the recovery of approximately $23.8 million of CL&P’s station service billings from NRG, which is currently the subject of an arbitration, and 3) the recovery of, among other claimed damages, approximately $17.5 million of capital costs and expenses incurred by Yankee Gas 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 earnings or financial position.  

C.

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

CL&P:  These amounts represent commitments for various services and materials associated primarily with the Bethel, Connecticut to Norwalk, Connecticut, the Middletown, Connecticut to Norwalk, and the Norwalk to Northport-Long Island, New York transmission projects as of June 30, 2006.