GLOSSARY OF TERMS

The following is a glossary of frequently used abbreviations or acronyms that are found in this report:

COMPANIES

i

MILLSTONE UNITS

REGULATORS

OTHER

ii

iii

NORTHEAST UTILITIES

THE CONNECTICUT LIGHT AND POWER COMPANY

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE

WESTERN MASSACHUSETTS ELECTRIC COMPANY

20062007 Form 10-K Annual Report
Table of Contents

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NORTHEAST UTILITIES

THE CONNECTICUT LIGHT AND POWER COMPANY

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE

WESTERN MASSACHUSETTS ELECTRIC COMPANY

SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES

LITIGATION REFORM ACT OF 1995

In connection withReferences in this Annual Report on Form 10-K to "NU," "we," "our," and "us" refer to Northeast Utilities and its consolidated subsidiaries.

From time to time we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, assumptions or future events, performance or growth and other statements that are not historical facts.  These statements are "forward-looking statements" within the safe harbor provisionsmeaning of the Private Securities Litigation Reform Act of 1995 (Reform Act), Northeast Utilities (NU) and its reporting subsidiaries are herein filing cautionary statements identifying important factors that could cause NU or its subsidiaries' actual results to differ materially from those projected in forward looking statements (as such term is defined in the Reform Act) made by or on behalf of NU or its subsidiaries in this combined Form 10-K, in any subsequent filings with the Securities and Exchange Commission (SEC), in presentations, in response to questions, or otherwise. Any statements that express or involve discussions as to expectations, beliefs, plans, objectives, assumptions or future events, performance or growth (often, but not always,1995.  You can generally identify our "forward-looking statements" through the use of words or phrases such as estimate, expect, anticipate, intend, plan, believe, forecast, should, could"believe," "estimate," "expect," "anticipate," "intend," "plan," "project," "believe," "forecast," "should," "could," and other similar expressions)expressions.  Forward-looking statements are based on the current expectations, estimates, assumptions or projections of management and are not statementsguarantees of historical facts and may be forwar d looking.  Forward looking statements involvefuture performance.  These expectations, estimates, assumptions and uncertainties that could causeor projections may vary materi ally from actual results to differ materially from those expressed in the forward looking statements.results.  Accordingly, any such statements are qualified in their entirety by reference to, and are accompanied by, the following important factors that could cause NU or its subsidiaries'our actual results to differ materially from those contained in forward lookingour forward-looking statements, of NU or its subsidiaries made by or on behalf of NU or its subsidiaries.

Some important factors that could cause actual results or outcomes to differ materially from those discussed in the forward looking statements include,including, but are not limited to, actions by state and federal regulatory bodies, competition and industry restructuring, changes in economic conditions, changes in weather patterns, changes in laws, regulations or regulatory policy, changes in levels and timing of capital expenditures, developments in legal or public policy doctrines, technological developments, changes in accounting standards and financial reporting regulations, fluctuations in the value of our remaining competitive electricity positions, actions of rating agencies, and other presently unknown or unforeseen factors.  Other risk factors are detailed from time to time in our reports filed with the Securities and Exchange Commission (SEC) and we encourage you to the SEC filed by NU and its subsidiaries.consult such disclosures.

All such factors are difficult to predict, contain uncertainties which may materially affect our actual results and are beyond our control. You should not place undue reliance on the control of NU or its subsidiaries.  Any forward looking statementforward-looking statements, each speaks only as of the date on which such statement is made, and NU and its subsidiarieswe undertake no obligation to update any forward lookingforward-looking statement or statements to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events.  New factors emerge from time to time and it is not possible for management to predict all of such factors, nor can it assess the impact of each such factor on the business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward lookingforward-looking statements.  For more information, see Item 1A, "Risk Factors" included in this report.  This Annual Report on Form 10-K also describes material contingencies and critical accounting policies and estimates in the accompanying "Management’s Discussion and Analysis" and "Notes to Consolidated Financial Statements."  We encourage you to review these items.

PART I

Item 1.  Business

NORTHEAST UTILITIES

NU, headquartered in Berlin, Connecticut, is a public utility holding company registered with the Federal Energy Regulatory Commission (FERC) under the Public Utility Holding Company Act of 2005 (PUHCA 2005).  NU had been registered with the SEC as a public utility holding company under the Public Utility Holding Company Act of 1935 (PUHCA 1935) until that Act was repealed, effective February 8, 2006.  NU is2005.  We are engaged primarily in the energy delivery business providing franchised retail electric service to approximately 1.9 million customers in 419 cities and towns in Connecticut, New Hampshire and western Massachusetts through three of itsthe following wholly-owned subsidiaries; regulated utility subsidiaries:

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The Connecticut Light and Power Company (CL&P), a regulated electric utility which serves residential, commercial and industrial customers in parts of Connecticut.  

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Public Service Company of New Hampshire (PSNH), and Western Massachusetts Electric Company (WMECO), and franchised retail natural gas service to approximately 200,000a regulated electric utility which serves residential, commercial and industrial customers in 71 citiesparts of New Hampshire.   

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Western Massachusetts Electric Company (WMECO), a regulated electric utility which serves residential, commercial and townsindustrial customers in Connecticut, through i ts wholly-owned indirect subsidiary, parts of western Massachusetts; and

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Yankee Gas Services Company (Yankee Gas)., a regulated gas utility which serves residential, commercial and industrial customers in parts of Connecticut.  

NU's

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We sometimes refer to CL&P, PSNH, WMECO and Yankee Gas collectively in this Annual Report on Form 10-K as the "regulated companies."

NU also owns certain unregulated businesses through its wholly-owned subsidiary, NU Enterprises, Inc. (NU Enterprises), is in the process.  We have exited most of exiting its competitive energy and related businesses and, asthese businesses. As of December 31, 2006, had exited substantially all2007, NUEI’s remaining business consisted of these businesses.  (i) Select Energy Inc.’s (Select Energy) few remaining wholesale marketing contracts, and (ii) NU Enterprises’ remaining energy services business. 

Although NU consolidated, CL&P, PSNH and WMECO report their financial results separately, we also include information in this report on a segment, or line of business basis.  The regulated companies include three business segments: the electric distribution segment (which includes PSNH’s regulated generation activities), the natural gas distribution segment and the electric transmission segment.  The regulated companies’ segment of our business represented approximately 92.8% of our total earnings for 2007, with electric distribution (including PSNH’s generation activities) representing approximately 50.1%, electric transmission representing approximately 33.5% and natural gas transmission representing approximately 9.2%.  At December 31, 2007, the NU Enterprises business segment included the following legal entities: (i) Select Energy, Inc. (Select Energy), (ii) Northeast Generation Services Company (NGS), (iii) E.S. Boulos Company (Boulo s), (iv) the remaining business of Select Energy Contracting, Inc. (SECI) and (iv) NU Enterprises parent.

For information regarding each of the NU system's reportableNU’s segments, see FootnoteNote 16, "Segment Information"Information," contained within NU's 20062007 Annual Report to Shareholders, which is incorporated into this Annual Report on Form 10-K by reference.

References in this Form 10-K to the "Company," "NU," "we," "our," and "us" refer to Northeast Utilities and its consolidated subsidiaries.

REGULATED ELECTRIC DISTRIBUTION

NU's subsidiaries, General

CL&P, PSNH and WMECO, sometimes referred to herein as the "operating companies", are primarily engaged in the distribution of electricity in Connecticut, New Hampshire and western Massachusetts.Massachusetts, respectively, with PSNH also participating in the regulated electric generation business.  The following table shows the sources of 20062007 electric franchise retail revenues for CL&P, PSNH and WMECO,the operating companies, collectively, based on categories of customers:

The actualA summary of changes in retailthe operating companies’ electric kilowatt-hour (kWh) sales for the last two years12-month period ended December 31, 2007 as compared to December 31, 2006 on an actual and the forecasted retail sales growth estimates for the five-year period 2007 through 2011 for CL&P, PSNH and WMECO, collectively, are set forth below:weather normalized basis is as follows:

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

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THE CONNECTICUT LIGHT AND POWER COMPANY (CL&P)

Distribution and Sales

CL&P is engaged in the purchase, transmission, delivery and sale of electricity to its residential, commercial and industrial customers.  At December 31, 2006,2007, CL&P furnished retail franchise electric service to approximately 1.2 million customers in 149 cities and towns in Connecticut.  CL&P sold all of its generating assets in 2000-2001 as required by statedoes not own any electric industry restructuring legislation, and no longer generates any electricity.generation facilities.

The following table shows the sources of 20062007 electric franchise retail revenues for CL&P based on categories of customers:

The actual changes in retail kWh sales for the last two years and the forecasted retail sales growth estimates for the five-year period 2007 through 2011 for CL&P are set forth below:

Rates

CL&P's retail rates are&P is subject to regulation by the Connecticut Department of Public Utility Control (DPUC). which, among other things, has jurisdiction over rates, accounting procedures, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, standards of service, management efficiency and construction and operation of facilities.  CL&P's present general rate structure consists of various rate and service classifications covering residential, commercial and industrial services.  Connecticut utilities are entitled under state law to charge rates that are sufficient to allow them an opportunity to cover their reasonable operation and capital costs, to attract needed capital and maintain their financial integrity, while also protecting relevant public interests.

CL&P's retail rates include a delivery service component, which includes distribution, transmission, conservation, renewables, competitive transition assessment (CTA) and other charges that are assessed on all customers, andcustomers.  Such rates also include an electric generation service component, which includes the costscost of power supply itwhich CL&P purchases for customers that do not choose to be served by a competitive retail supplier.  

CL&P has also received regulatory orders allowing it to recover all or substantially all of its prudently incurred "stranded" costs, which are pre-restructuring expenditures incurred, or commitments made for future expenditures, on behalf of customers with the expectation such expenditures would continue to be recoverable in the future through rates.  CL&P has financed a significant portion of its stranded costs through the issuance of rate reduction certificates (securitization) and is recovering the costs of securitization through the Competitive Transition Assessment (CTA) component of its rates.  As of December 31, 2006, CL&P had fully recovered all stranded costs, except those being recovered through securitization, ongoing independent power producer costs, costs associated with the ongoing decommissioning of the Maine Yankee, Connecticut Yankee and Yankee Rowe nuclear units, and annual decontamination and decommissioning costs payable under federal law.

Under state law, all of CL&P's customers are now able to choose their energy suppliers, with CL&P furnishing service to those customers who do not choose a competitive supplier.  Beginning January 1, 2007, this service is termed "Standard Service" for customers that are less than 500 kW of demand and "Supplier of Last Resort Service" for customers who are not eligible for Standard Service.  

Most of CL&P's customers have continued to buy their power from CL&P at these rates but CL&P is experiencing accelerating customer migration to alternative suppliers, with the movement concentrated among the larger customers.  As of December 31, 2006, approximately 40,000 customers out of 1.2 million, representing approximately 9% of December load, had selected competitive energy supply.  

On December 8, 2006, the DPUC approved CL&P's Standard Service rates, effective as of January 1, 2007.  The new Standard Service rates reflect an increase of approximately 7.8% and are expected to remain effective until July 1, 2007 when these rates will likely be adjusted to reflect additional supplier bids received for 2007 and updated wholesale transmission costs.  Supplier of Last Resort rates will vary, and total bills for those customers increased by 19% on January 1, 2007.  On August 4, 2006, CL&P notified the DPUC that it intended to postpone filing a distribution rate case until mid-2007, and the case, when filed, would target new rates to be effective in early 2008.

As a result of Connecticut legislation passed in July 2005, CL&P filed for a transmission adjustment clause on August 1, 2005 with the rate tracking mechanism to be effective on July 6, 2005.  On December 20, 2005, the DPUC approved the tracking mechanism, which provides for semi-annual adjustments in January and July of each year.  CL&P adjusts its retail transmission rates on a regular basis, thereby recovering all of its retail transmission expenses on a timely basis.  (See "Regulated Electric Transmission" in this Annual Report on Form 10-K).

CL&P has also received regulatory orders allowing it to recover all or substantially all of its prudently incurred stranded costs, which are pre-restructuring expenditures incurred, or commitments for future expenditures made, on behalf of customers with the expectation such expenditures would continue to be recoverable in the future through rates.  CL&P has financed a significant portion of its stranded costs through the issuance of rate reduction certificates secured by its right to recover stranded costs over time (securitization).  CL&P recovers the costs of securitization through the CTA component of its rates.  In addition to those being recovered through securitization, CL&P’s stranded costs, included, as of December 31, 2007, ongoing independent power producer costs and costs associated with the ongoing decommissioning of the Maine Yankee, Connecticut Yankee and Yankee Rowe nuclear units.

Under state law, all of CL&P's customers are entitled to choose their energy suppliers while retaining CL&P as their distribution company. CL&P purchases power for, and passes through the cost to those customers who do not choose a competitive energy supplier.  Beginning January 1, 2007, this service was termed "Standard Service" for customers with less than 500 kW of demand and "Supplier of Last Resort Service" for customers with 500 kW of demand or greater.  CL&P receives the cost for this service through the "Generation Service Charge" and "Bypassable Federally Mandated Congestion Charge" (FMCC) components of the customer’s bill, which is adjusted and reconciled on a semi-annual basis.

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A large percentage of CL&P's customers have continued to buy their power from CL&P at Standard Service or Supplier of Last Resort rates.  However, CL&P is experiencing some customer migration to competitive energy suppliers, with the movement concentrated among the larger customers.  As of December 31, 2007, approximately 69,000 customers or 6% out of 1.2 million, representing approximately 33% of December 2007 load, had selected competitive energy suppliers.  This customer migration is for energy supply service only so there is no impact on the delivery portion of the business or the operating income of CL&P.  Energy supply service costs have been, and remain a 1-for-1 pass-through cost with no return.

On July 30, 2007, CL&P filed an application with the DPUC for an increase in its distribution rates, including an authorized regulatory return on equity (ROE) of 11% and a proposed capital budget of approximately $294 million for 2008 and $288 million for 2009.  CL&P’s application also contained, as required by Connecticut Public Act 07-242, "An Act Concerning Electricity and Energy Efficiencies" (Energy Efficiency Act), a proposal to implement distribution revenue decoupling from the volume of electricity sales using a revenue per customer tracking mechanism.  On January 28, 2008, the DPUC issued its decision in the proceeding.  The decision approved annualized increases in CL&P’s distribution rates of $77.8 million for 2008 and $20.1 million for 2009, and a regulatory ROE of 9.4%, with CL&P continuing the existing earnings sharing mechanism, which provides that ratepayers and shareholders share equally in any earnings in excess of its allowed regulatory ROE.  The decision also approves substantially all of CL&P’s proposed capital budget.  In its decision, the DPUC did not approve CL&P’s proposal to achieve decoupling using a "revenue per customer" adjustment mechanism.  In lieu of this proposal, the DPUC authorized compliance with the decoupling provisions of the Energy Efficiency Act via rate design that includes greater fixed recovery of distribution revenue.  As compared to previous tariffs, CL&P's new distribution rates are intended to recover proportionately greater revenue through the fixed Customer and Demand charges and proportionately less distribution revenue through the per kWh charges.  The new 2008 rates took effect on February 1, 2008, and the 2009 increase will take effect on February 1, 2009.

Regulatory Update

On March 30, 2007, CL&P filed a metering compliance plan with the DPUC that would meet the DPUC's objective of making time-of-use rates available to all CL&P customers.  CL&P's filing discussed the technology, implementation options and costs comparing an open advanced metering infrastructure (AMI) system deployed on a geographic basis to a fixed automated metering reading (AMR) network system deployed on a usage-based priority schedule.  The plan provided for full deployment by 2010.  On July 2, 2007, CL&P filed a revised AMI plan consistent with the requirements of the Energy Efficiency Act, which provided for a less aggressive implementation schedule based on customer interest and allowed for future DPUC input at various milestones.  CL&P requested cost recovery through its FMCC.  On December 19, 2007, the DPUC issued a final decision on CL&P’s compliance plan that authorized a pilot program involving the instal lation of 10,000 AMI meters and a rate design pilot to test new time-of-use and real-time rates to determine customer acceptance and load response to various pricing structures.  For further information on CL&P rates, see "Regulatory Developments and Rate Matters" in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," contained in our Annual Report to Shareholders which is incorporated herein by reference.

In April 2007, pursuant to Public Act 05-01, "An Act Concerning Energy Independence" (Energy Independence Act), CL&P entered into a 15-year contract to purchase energy, capacity and renewable energy credits from a biomass energy plant beginning after completion of the plant.  The contract has been approved by the DPUC and it provides for annual purchases of up to approximately 15 megawatts (MW) The DPUC has approved a sharing agreement between CL&P and The United Illuminating Company (UI) under which they will share the net costs and benefits of this contract and other contracts ultimately entered into under this program, with approximately 80% to CL&P and approximately 20% to UI, regardless of which contracts are signed by CL&P and which contracts are signed by UI.  CL&P's portion of the net costs or net benefits of such contracts will be paid by or returned to CL&P's customers.  

On January 30, 2008, the DPUC issued a decision approving contracts with seven more renewable energy projects of different designs totaling approximately 109 MW.  The DPUC also gave contingent approval of a contract with another renewable energy project representing approximately 20 MW.  The DPUC’s contingent approval of this contract would become final if one or more of the seven projects having an approved contract (representing at least 20 MW) is unable to obtain a financing commitment letter.  CL&P's share of the future costs or benefits under all these contracts will be paid by or refunded to CL&P's customers.  A third round of solicitations is expected to be conducted by the Connecticut Clean Energy Fund (CCEF) for an additional 26 MW of recoverable energy generation by October 1, 2008.    

Also pursuant to the Energy Independence Act, the DPUC conducted a request for proposal process and selected three generating projects to be built or modified that would be eligible to sign contracts for differences (CfDs) with CL&P and UI for a total of approximately 782 MW of capacity.  The process also selected one new 5 MW demand response project.  The CfDs obligate CL&P or UI to pay the difference between a set capacity price and the value that the projects receive in the New England Independent System Operator (ISO-NE) capacity markets.  The terms of the contracts are for periods of up to 15 years and would be subject to another similar sharing agreement between CL&P and UI.  These contracts have been approved by the DPUC and signed by either CL&P or UI, whichever is the primary

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obligor.  CL&P’s portion of the costs and benefits of these contracts will be paid by, or refunded to, CL&P’s customers.  On October 5, 2007, NRG Energy, Inc. filed an appeal of the DPUC's decision selecting the generation projects.   On February 13, 2008, the Superior Court dismissed NRG’s appeal.    

The Energy Efficiency Act requires CL&P and UI to negotiate in good faith to potentially enter into cost-of-service based contracts for the energy associated with the three above-mentioned generation projects that were awarded CfDs by the DPUC, for term lengths equivalent to the associated CfDs.  These energy contracts must be approved by the DPUC after a finding that they will stabilize the cost of electricity for Connecticut ratepayers.  Depending on its terms, a long-term contract to purchase energy from a project that is also under a CfD could result in CL&P consolidating these projects into its financial statements.  CL&P would seek to recover from customers any costs that result from consolidation of a project.  As of February 1, 2008, only one of the three CfD project developers has requested that CL&P enter into negotiations for such a contract.  For further information, see Notes 5 and 3, "Derivative Instruments," to our consolidated financial statements contained in NU’s and CL&P’s Annual Report to Shareholders, respectively, and incorporated herein by reference.

In addition, the Energy Efficiency Act requires electric distribution companies to file with the Connecticut Energy Advisory Board (CEAB) an integrated resource plan (IRP) which includes an assessment of the state’s energy and capacity resources, including, but not limited to, conventional and renewable generating facilities, energy efficiency, load management, demand response, combined heat and power facilities, distributed generation and other emerging energy technologies to meet the projected requirements of their customers in a manner that minimizes the cost of such resources to customers over time and maximizes consumer benefits consistent with the state's environmental goals and standards. CL&P and UI filed a joint IRP with the CEAB on January 2, 2008. The CEAB may modify or accept the plan prior to filing it with the DPUC by May 1, 2008.

The Energy Efficiency Act also requires electric distribution companies to file proposals with the DPUC to build cost-of-service peaking generation facilities.  CL&P filed a qualification submission with the DPUC on February 1, 2008, proposing two sites for peaking generation, and will file a detailed proposal on or about March 3, 2008.  For further information, see "Legislative Matters" in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," contained in our Annual Report to Shareholders which is incorporated herein by reference.

On February 27, 2008, the DPUC issued a final decision in a docket examining the manner of operation and accuracy of CL&P's electric meters.  While finding that the meters generally operated within industry standards, the DPUC imposed significant new testing, analytical and reporting requirements on CL&P.  The DPUC also found that CL&P failed to be responsive to customer complaints by refusing meter tests or not allowing customers to speak with supervisors.  The decision acknowledges recent corrective actions taken by CL&P but requires changes in numerous customer service practices.  The decision also places substantial new tracking and reporting obligations on CL&P.  The decision does not fine CL&P but holds that possibility open if CL&P fails to meet benchmarks to be established in this docket.

Sources and Availability of Electric Power Supply

As noted above, CL&P owns nodoes not own any generation assets and purchases its energy requirements to serve its Standard Service and Supplier of Last Resort loads from a variety of competitive sources through periodic requests for proposals (RFPs).  On June 21, 2006, the DPUC approved a plan for CL&P to issueissues RFPs periodically for periods of up to three years to layer Standard Service full requirements supply contracts in order to mitigate market volatility for its residential and lower usesmall and medium commercial and industrial customers.  Additionally, the DPUC approved the issuance ofCL&P issues RFPs for Supplier of Last Resort service for larger commercial and industrial customers every sixthree months.  Previously, all ofCurrently, CL&P's residential, commercial and industrial requirements, regardless of customer size, were bid together.&P has in place contracts with various suppliers through 2010.  The DPUC's decision also provides for enhanced accessDPUC is evaluating whether it will implement any changes to the RFP materials, bids and other data during and after the RFP process.

In September of 2006, CL&P received bids and awarded contracts for a portion of Standard Service loads for 2007 and 2008.  CL&P also received bids and awarded contracts for a portion of Standard Service loads for 2007 through 2009 in October of 2006.  CL&P will receive bids in 2007 for Standard Service for remaining 2007 load requirements and for some load requirements in 2008 and 2009.  CL&P also received bids and awarded contracts in September of 2006 for its Supplier of Last Resort Service for its larger commercial and industrial customers for January through June of 2007.  None of CL&P's suppliers for 2007 and beyond are affiliated with CL&P. CL&P is fully recovering all of the payments it is making to those suppliers through DPUC-approved rates billed to customers, and has financial assurances from each supplier or from a parent or affiliate of each supplier to protect CL&P from loss in the event any of the suppliers encounters fi nancial difficulties.   

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE (PSNH)

Distribution and Sales(Including Regulated Generation)

PSNH is primarily engaged in the generation, purchase, transmission, delivery and sale of electricity to its residential, commercial and industrial customers.  At December 31, 2006,2007, PSNH furnished retail franchise electric service to approximately 487,000491,000 retail customers in 211 cities and towns in New Hampshire.  PSNH also owns and operates approximately 1,200 megawatt (MW)MW of electricity generation assets.  Approximately 70 MW of those generation assets with a current claimed capability representing winter rates, of approximately 1,170 MW.are hydroelectric units.  Included among these generating assets is a 50 MW wood-burning generating unit in Portsmouth, New Hampshire, which was converted from a coal-burning unit and went into full operation in December 2006.

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The following table shows the sources of 20062007 electric franchise retail revenues based on categories of customers:

The actual changes in retail kWh sales for the last two years and the forecasted retail sales growth estimates for the five-year period 2007 through 2011 for PSNH are set forth below:

Rates

Default Energy Service (ES):  PSNH's retail rates arePSNH is subject to regulation by the New Hampshire Public Utilities Commission (NHPUC) which has jurisdiction over, among other things, rates, certain dispositions of property and plant, mergers and consolidations, issuances of securities, standards of service, management efficiency and construction and operation of facilities.

Default Energy Service (ES) Rates.  PSNH’s ES rate recovers PSNH's generation and purchased power costs, including an ROE on PSNH's generation assets.  PSNH files for approval of updated ES rates periodically with the NHPUC to ensure timely recovery of its costs.  The ES rate recovers PSNH's generation and purchased power costs, including a return on equity (ROE) on PSNH's generation assets.  PSNH defers for future recovery or refund any difference between its ES revenues and the actual costs incurred.  

On December 2, 2005, the NHPUC issued a decision lowering PSNH's allowed generation ROE to 9.62% retroactive to an effective date of August 1, 2005.  This decrease in allowed generation ROE lowers PSNH's net income by approximately $1.5 million annually based on the current level of generation assets.

On January 20, 2006,28, 2007, the NHPUC approved new ES rates of $0.0913 per kWh for the eleven month period February 1, 2006 through December 31, 2006.  In its order, the NHPUC also allowed PSNH to implement deferred accounting treatment for the new accounting associated with asset retirement obligations.  On June 29, 2006, the NHPUC decreasedan increase in the ES rate to $0.0818$0.0882 per kWh, based upon updatedeffective January 1, 2008.  Among other items, the new rate reflects an increase in PSNH’s authorized generation ROE to 9.81% effective January 1, 2008.

Under the terms of the order issued by the NHPUC approving PSNH’s new wood-burning generation plant (Northern Wood Power Project), which replaced one of the three 50 MW boiler units at the coal-fired Schiller Station, certain revenue, credits and cost informationavoidances (revenue sources) are shared between PSNH and its customers.  These revenue sources include sales of renewable energy certificates (RECs) to other utilities, brokers, or suppliers, and production tax credits.  In any given year, if the combination of revenue sources falls short of a stipulated revenue level, PSNH and its customers each share half of any deficiency, and if the combination exceeds the stipulated revenue level, PSNH and its customers each share half of any excess.  The Northern Wood Power Project entered commercial operation on December 1, 2006, and revenue sources exceeded stipulated levels in 2007 due to its performance and favorable pricing in the Massachusetts market for the period July 1, 2006 through December 31, 2006.  RE Cs.  As a result, customers and shareholders will share equally a benefit of about $9.2 million of incremental revenues for 2007.  A majority of PSNH’s share of these benefits will be recognized in 2008 when the 2007 RECs are delivered.

On September 8, 2006,Although PSNH's customers are entitled to choose competitive energy suppliers, PSNH filedhas experienced only a petition with the NHPUC requesting a change in its ES rate for the 12-month period January 1, 2007 through December 31, 2007.  On December 15, 2006, the NHPUC issued an order approving the filed ES 2007 ratesmall amount of $0.0859 per kWh.  As in previous NHPUC ES rate orders, there is a provisioncustomer migration to update the ES rate during the 2007 rate year based upon updated actual and projected cost information.date.

Delivery Service (DS) Rates:.  On May 30, 2006, PSNH filed a petition with the NHPUC requesting a permanentan increase in its delivery service (DS) rate of approximately $50 million, the approval of a transmission cost tracking mechanism, and a decrease in its stranded cost charge and energy charge to reflect the completed recovery of certain stranded costs and changes in PSNH's actual costs to provide transition energy service.DS rates.  On June 29, 2006,May 25, 2007, the NHPUC approved a temporary DSdistribution and transmission rate increase of $24.5 million, effective on July 1, 2006.  This temporary rate increase will be reconciled to the allowed permanent rate increase effective back to the July 1, 2006 date.  On November 17, 2006, PSNH updated its permanent DS rate filing, increasing the request to $60 million, due primarily to updated rate base projections and higher reliability spending.  

On February 26, 2007, PSNH filed acase settlement agreement it reached with(PSNH rate settlement agreement) between PSNH, the NHPUC staff and the Office of Consumer Advocate related to itsAdvocate.  The PSNH rate case filing.  The settlement agreement includes, among other things, a transmission cost tracking mechanism, effective on July 1, 2006, to be reset annually, and an allowed ROE of 9.67 percent.  The allowed generation ROE of 9.62 percent was unaffected.  The settlement providesprovided for a $37.7 million estimated annualized increase ($26.5 million estimated for distribution and $11.2 million estimated for transmission) beginningtransmission in base rates subject to tracking) that was effective on July 1, 2007, in addition to thereplacing a previous $24.5 million temporary distribution rate settlement increase that was effective on July 1, 2006.  The $37.7 million includes a one-year revenue increase of approximately $9 million to recoup the difference between the temporary and the approved rates for the period July 1, 2006 through June 30, 2007.  An additional delivery revenue increase of approximately $3 million would takemi llion took effect on January 1, 2008 with a final estimated rate decrease of approximately $9 million scheduled for July 1, 2008.  

Transmission Cost Adjustment Mechanism.  On June 1, 2007, PSNH filed a petition with the NHPUC seeking to establish a Transmission Cost Adjusting Mechanism (TCAM) rate consistent with the PSNH rate settlement agreement.  The increased revenues will enableTCAM rate filing was amended on June 6, 2007 to reflect updates to wholesale transmission rates that were made available to PSNH to fundafter the initial June 1, 2007 filing.  The NHPUC issued an order on June 29, 2007 approving a $10 million annual Reliability Enhanc ement Program and more accurately fund its Major Storm Cost Reserve.  The increased revenues also include approximately $9 million related to additional revenuesTCAM rate of $0.00752 per kWh for the period July 1, 20062007 through June 30, 2007 that will be recovered over one year.  The NHPUC has scheduled hearings on the proposed settlement beginning in March 2007, with a final decision expected by late spring of 2007.2008.

Stranded Cost Recovery Charge (SCRC(SCRC).):  Under New Hampshire law, the SCRC allows PSNH to recover its stranded costs.  PSNH has financed a significant portion of its stranded costs through securitization by issuing rate reduction bonds.bonds secured by the right to recover these stranded costs from customers over time.  It recovers the securitization costs which are known as Part 1 costs,of these bonds through the SCRC rate.  

On an annual basis, PSNH files with the NHPUC a SCRC/ESan SCRC reconciliation filing for the preceding calendarprevious year.  This filing includes the reconciliation of SCRC revenues and costs and the ES revenues and costs.  The NHPUC reviews the filing, including a prudence review of the operations within PSNH's generation business segment.  On October 25, 2006,For further information on PSNH the NHPUC Staff and the Office of Consumer Advocate filed a settlement agreement with the NHPUC which resolved all outstanding issues associated with PSNH's 2005 reconciliation. After hearings, the NHPUC issued its order approving the settlement agreement.  The terms of the settlement had virtually no impact on PSNH's financial position.rates, see "Regulatory

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In accordance with the "AgreementDevelopments and Rate Matters" in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," in our Annual Report to Settle PSNH Restructuring", PSNHShareholders which is required to periodically recalculate its SCRC once its non-securitized (Part 3) costs are fully recovered.  PSNH fully recovered its remaining Part 3 costs in June 2006, and an initial reduction of the SCRC from $0.0355 per kWh to $0.0155 per kWh was approvedincorporated herein by the NHPUC on June 29, 2006 and effective July 1, 2006.  

On September 22, 2006, PSNH filed a petition with the NHPUC requesting a decrease in its SCRC for the period January 1, 2007 through December 31, 2007 based upon market conditions and the NHPUC's decision regarding the duration of certain independent power producer agreements.  On November 17, 2006, PSNH filed a revised petition with the NHPUC on the SCRC rate which was approved by the NHPUC on December 15, 2006 and resulted in a reduction in the SCRC rate to $0.0130 per kWh, effective in 2007.

Although PSNH's customers are able to choose competitive energy suppliers, PSNH has experienced almost no customer migration to date.reference.  

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.  A consultant hired by the NHPUC conducted an investigation and made certain preliminary findings and recommendations.  PSNH responded to data requests from the NHPUC's outside consultant.  While management believes PSNH'sconsultants report and consulted with the NHPUC Staff.  As a result of those discussions, PSNH agreed to many of the recommendations made concerning the conduct of its coal procurement and transportation policies and procedures are prudent and consistent with industry practice, it is unable to determineactivities.  There will be no material adverse financial impact on PSNH as a result of implementing the impact, if any, of the NHPUC's review on PSNH's earnings or financial position.Staff's recommendations.

Sources and Availability of Electric Power Supply

During 2006,2007, about 75%70% of PSNH load was met through ownedits own generation and long-term power supply contracts.rate orders and contracts with third parties.  The remaining 25%30% of PSNH's load was met by short-term (less than one year) purchases and spot purchases fromin the competitive New England Independent System Operator (ISO-NE) wholesale power market.  For 2007,  PSNH expects to meet its load requirements in 2008 in a similar mannermanner.

On May 11, 2007, New Hampshire Governor Lynch signed into law the "Renewable Energy Act," establishing renewable portfolio standards for electricity sold in the state, and ultimately requiring that 23.8% of the electricity sold to 2006.retail customers have direct ties to renewable sources by 2025.  The renewable sourcing requirements begin in 2008 and increase each year to reach 23.8% by 2025.  PSNH will be required to comply with these standards, which it plans to do primarily through the purchase of RECs or through Alternative Compliance Payments allowed under state law.  PSNH expects that the additional costs incurred in meeting this new requirement will be recovered through PSNH’s energy service rates.  For further information, see "Other Regulatory and Environmental Matters" in this Annual Report on Form 10-K.

WESTERN MASSACHUSETTS ELECTRIC COMPANY (WMECO)

Distribution and Sales

WMECO is engaged in the purchase, transmission, delivery and sale of electricity to residential, commercial and industrial customers. At December 31, 2006,2007, WMECO furnished retail franchise electric service to approximately 210,000206,000 retail customers in 59 cities and towns in the western third of Massachusetts.  WMECO sold all of itsdoes not own any electricity generating assets in 2000-2001 as required by state electric industry restructuring legislation, and no longer generates any electricity.facilities.

The following table shows the sources of 20062007 electric franchise retail revenues based on categories of customers:

The actual changes in retail kWh sales for the last two years and the forecasted retail sales growth estimates for the five-year period 2007 through 2011 for WMECO are set forth below:

Rates

Under state law, all of WMECO's customers are now able to choose their energy suppliers, with WMECO furnishing "basic service" to those customers who do not choose a competitive supplier.  Most of WMECO's residential and smaller customers have continued to buy their power from WMECO at these rates.  A greater proportion of larger commercial and business customers have opted for a competitive retail supplier.  As of December 31, 2006, approximately 11,000 out of nearly 210,000 customers have elected this option, representing about 43% of the energy delivered by WMECO.

WMECO's retail rates areis subject to regulation by the Massachusetts Department of Public Utilities (formerly the Department of Telecommunications and Energy (DTE).Energy) (DPU), which has jurisdiction over, among other things, rates, accounting procedures, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, standards of service, management efficiency and construction and operation of distribution, production and storage facilities.  WMECO's present general rate structure consists of various rate and service classifications covering residential, commercial and industrial services.  Massachusetts utilities are entitled under state law to charge rates that are sufficient to allow them an opportunity to cover their reasonable operation and capital costs, to attract needed capital and maintain their financial integrity, while also protecting relevant public interests.

Under state law, all of WMECO's customers are now entitled to choose their energy suppliers, while retaining WMECO as their distribution company.  WMECO purchases electric power for and passes through the cost to those customers who do not choose a competitive energy supplier (basic service).  Basic service charges are adjusted and reconciled on an annual basis.  Most of WMECO's residential and smaller customers have continued to buy their power from WMECO at basic service rates.  A greater proportion of large commercial and business customers have opted for a competitive energy supplier.  As of December 31, 2007, approximately 15,000 or 7% out of nearly 206,000 customers had elected this option, representing about 45% of the energy delivered by WMECO.

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WMECO collects its transmission costs through a transmission adjustment clause.  The DTEDPU approved the tracking mechanism in January 2002, which provides for annual adjustments, thereby allowing WMECO to recover all of its retail transmission expenses on a timely basis.

WMECO has also received regulatory orders allowing it to recover all or substantially all of its prudently incurred "stranded"stranded costs.  WMECO has financed a portion of its stranded costs through securitization by issuing rate reduction certificates andsecured by the right to recover stranded costs from customers over time.  It is recovering the costs of securitization through rates.  

Rate Case SettlementSettlement.:  On December 14, 2006, the DTE approved  WMECO implemented a $1 million rate settlement agreement (the Settlement) between WMECO, the Attorney General of the Commonwealth of Massachusetts, the Low-income Energy Affordability Network, and the Associated Industries of Massachusetts which was filed with the DTE in lieu of a base rate proceeding.  The Settlement provides a $1.0 million increase in WMECO's distribution rates effectiveon January 1, 2007 and anto reflect a distribution rate increase approved by the DPU in December 2006.  An additional increase in distribution rate of $3.0$3 million became effective on January 1, 2008.  Also includedRates were also adjusted January 1, 2008 to include approved adjustments in the Settlement are costvarious tracking mechanisms for pension and other postretirement benefit costs, uncollectible amounts relatednew basic service contracts.  For further information on WMECO rates, see "Regulatory Developments and Rate Matters" in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," contained in our Annual Report to energy costs, and recovery of certain capital improvements and related expenses needed for system reliability.  The Settlement includes an earnings sharing mechanism that will equally share with customers any earnings in excess of an actual ROE of 12% and any shortfall below an actual ROE of 8 % during the two-year settlement period.  The determination of any excess or shortfall would be done annually, with any such excess being recorded as a regulatory liability and any such shortfall being recorded as a regulatory asset.Shareholders which is incorporated herein by reference.

Annual Rate Change Filing:  On November 30, 2006, WMECO made its 2006 annual rate change filing.  Because the timing of this filing coincided with WMECO's rate case settlement decision described above, the DTE combined WMECO's annual rate change filing with its rate case settlement compliance filing.  The combined filing implements the $1 million distribution rate increase and associated cost tracking mechanisms as allowed under its rate case settlement agreement and reflects rate increases for 2007 default service supply.  On average, total rates increased 17.8 %.  On December 29, 2006, the DTE approved the rates effective January 1, 2007.

Sources and Availability of Electric Power Supply

As noted above, WMECO owns nodoes not own any generation assets and purchases its energy requirements from a variety of competitive sources through periodic RFPs.  For basic service power supply, WMECO makes periodic market solicitationsissues RFPs periodically, consistent with DTEDPU regulations.  During 2006,For 2008, WMECO entered into power purchasean agreements on May 15, 2007, to meet its entire basic service supply obligation, other than to its largest customers,secure 50% of residential, small commercial and industrial, and street lighting loads for the period JanuaryJuly 1, 2007 through June 30, 2008 period, and on November 13, 2007 to secure power for half of its residential, small commercial and industrial, and street lighting loads for the January 1 through December 31, 2008 period.  WMECO will issue an RFP in the second quarter of 2008 to secure the remaining 50% of its obligation, other than to these large customers,residential, small commercial and industrial, and street lighting loads for the second-halfJuly 1 through December 31, 2008 period and 50% of 2007.  WMECO has entered into short-term power purchase agreements to meet its entire basic service supply obligationthe load for large customers for the period January 1, 2007 through March 2007 and April 12009 through June 30, 2007.  An RFP2009.  For its large commercial and industrial customers, WMECO entered into an agreement on November 13, 2007 to secure power for the first quarter of 2008 and an agreement to secure power for the second quarter 2008 on February 12, 2008.  RFPs will be issued quarterly in 2007 forto address the remainderbalance of the obligation for large customers and semi-annually for non-large customers.  For 2006, WMECO entered into agreements for either thre e or twelve-month periods.year.

LICAP AND FCM DEVELOPMENT

On March 6, 2006, ISO-NE and a broad cross-section of critical stakeholders from around the region, including CL&P and PSNH, filed a comprehensive settlement agreement at the FERC proposing a forward capacity market (FCM) in place of the previously proposed locational installed capacity (LICAP), an administratively determined electric generation capacity pricing mechanism.  The settlement agreement provided for a fixed level of compensation to generators from December 1, 2006 through May 31, 2010 without regard to location in New England, and annual forward capacity auctions, beginning in 2008, for the 1-year period ending on May 31, 2011, and annually thereafter.  According to preliminary estimates, FCM would require our utility subsidiaries to pay approximately the following amounts from December 1, 2006 through December 31, 2009:  CL&P - $470 million; PSNH - $80 million; and WMECO - $100 million.  CL&P, PSNH and WMECO expect to recover these costs from their ratepayers.  On June 16, 2006, the FERC accepted thea FERC-approved Forward Capacity Market settlement agreement.  Several parties sought rehearing of this issue by the FERC, which was denied on October 31, 2006.  On December 1, 2006 the Settlement Agreementagreement was implemented, and the payment of fixed compensation to generators began.  Several parties challenged the FERC’s approval of the FCM settlement agreement and that challenge is pending in the Court of Appeals.  The first forward capacity auction concluded in early February of 2008 for the capacity year of June of 2010 through May of 2011.  The bidding reached the establishment minimum of $4.50 per kilowatt-month with 2,047MW of excess remaining capacity which means the effective capacity price will be $4.25 per kilowatt-month compared to the established price of $4.10 per kilowatt-month for the 12-month capacity period ending May 31, 2010.  These costs are recoverable in all jurisdictions through the currently established rate structures.

For more information regarding CL&P, WMECO and PSNH state regulatory matters, see "Utility Group Regulatory Issues"Regulatory Developments and Rate Matters" under  Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained within NU's and CL&P's Annual Reports to Shareholders, which is incorporated into this Annual Report on Form 10-K by reference.

REGULATED GAS DISTRIBUTION

Yankee Energy System, Inc. (Yankee) is the holding company of Yankee Gas and several immaterial non-utility subsidiaries, including NorConn Properties, Inc., which holds certain minor properties and facilities of Yankee and its subsidiaries, and Yankee Energy Financial Services Company, which was in the business of providing Yankee Gas customers and other energy end-users with financing primarily for energy equipment installations, but which is in the process of winding down its business operations.

Yankee Gas operates the largest natural gas distribution system in Connecticut as measured by number of customers (approximately 200,000), and size of service territory (2,088 square miles).  Total throughput (sales and transportation) for 2007 was 49.7 billion cubic feet (Bcf) compared with 45.2 Bcf in 2006.  Yankee Gas provides firm gas sales service to customers who require a continuous gas supply throughout the year, such as residential customers who rely on gas for their heating, hot water and cooking needs, and commercial and industrial customers who choose to purchase gas from Yankee Gas.  Yankee Gas also offers firm transportation service to its commercial and industrial customers who purchase gas from sources other than Yankee Gas as well as interruptible transportation and interruptible gas sales service to those certain commercial and industrial customers that have the capability to switch from natural gas to an alternative fuel

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on short notice.  Yankee Gas can interrupt service to these customers during peak demand periods or at any other time to maintain distribution system integrity.  

In 2007,Yankee Gas completed construction of a liquefied natural gas (LNG) facility in Waterbury, Connecticut at a total cost of approximately $108 million.  The LNG facility is capable of storing the equivalent of 1.2 Bcf of natural gas.  The facility was put in service in July 2007 and filling of the LNG tank was completed by the end of October 2007 to serve customers during the 2007-2008 heating season.

Yankee Gas earned $22.6 million on total gas operating revenues of approximately $514 million for 2007.  The following table shows the sources of 2007 total gas operating revenues:

For more information regarding Yankee Gas’s financial results, see Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," and Item 8, "Financial Statements and Supplementary Data," which includes Note 16, "Segment Information," within the notes to the consolidated financial statements, contained within our Annual Report to Shareholders, which is incorporated into this Annual Report Form 10-K by reference.

Although Yankee Gas is not subject to the FERC's jurisdiction, the FERC has limited oversight with respect to certain intrastate gas transportation that Yankee Gas provides.  In addition, the FERC regulates the interstate pipelines serving Yankee Gas’s service territory.

Rates

Yankee Gas is subject to regulation by the DPUC, which has jurisdiction over, among other things, rates, accounting procedures, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, standards of service, management efficiency and construction and operation of distribution, production and storage facilities.  

On December 29, 2006, Yankee Gas filed an application with the DPUC requesting an increase to its distribution service rate primarily for the recovery of costs associated with its newly constructed LNG facility.  The filing also included increases in operating and maintenance and depreciation costs as well as a requested ROE of 10.5%.  Yankee Gas negotiated a settlement with the Connecticut Office of Consumer Counsel (OCC) and the DPUC’s Prosecutorial Division which resulted in an annualized increase of $22 million, or 4.2%, in Yankee Gas’s base rates, net of expected pipeline and commodity cost savings resulting primarily from completion of Yankee Gas’s LNG facility.  The settlement included, among other things, the recovery of the costs of construction of its LNG facility, higher costs-of-service and an authorized ROE of 10.1%.  Yankee Gas will return to ratepayers 100% of all earnings in excess of the allowed 10.1% ROE.  The settl ement also allows Yankee Gas to defer certain costs for future recovery associated with the Department of Transportation’s Office of Pipeline Safety regulations regarding pipeline integrity and improved pipeline safety.  The DPUC approved the settlement on June 29, 2007 for rates effective July 1, 2007.

Yankee Gas recovers its cost of gas supplied to customers through a Purchased Gas Adjustment clause in its rate tariff.  In 2005 and 2006, the DPUC issued decisions requiring an audit by an independent party of approximately $11 million in previously recovered PGA revenues associated with unbilled sales and revenue adjustments for the period of September 1, 2003 through August 31, 2005.  The audit was concluded, and a final report was submitted to the DPUC.  A DPUC hearing was held on October 9, 2007.  Management believes the unbilled sales and revenue adjustments and resulting charges to customers through the PGA clause for the audit period were appropriate and will be approved.

In 2007, in addition to the approximately $108 million capitalized for the LNG facility, Yankee Gas also capitalized $51.8 million related to reliability improvements, new customer connections and other initiatives.

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REGULATED ELECTRIC TRANSMISSION

General

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

Wholesale Rates

Wholesale transmission revenues are based on formula rates that are approved by the FERC.  Most of NU'sour wholesale transmission revenues are collected through a combination of ISO-NEunder the FERC Electric Tariff No. 3, Open Access Transmission, Markets and Services Tariff (Tariff No. 3).  Tariff No. 3 includes the Regional Network Service (RNS), and Schedule 21 - NULocal Network Service (LNS) to that tariff.rate schedules, among other things.  The RNS (or regional network service) tariff israte, administered by ISO-NE and is billed to all New England transmission users.  RNS recovers the revenue requirements associated with facilities that are deemed to provide a regional benefit, or pool transmission facilities.  The RNS rateowners, is reset on June 1^st of each year and NU collects approximately 75 percent of its wholesalerecovers the revenue requirements associated with transmission revenues under its RNS tariff.  NU'sfacilities that benefit the New England region.  The LNS (or local network service) rate, which we administer, is reset on January 1^st and June 1^st of each year and providesrecovers the revenue requirements for a true-uplocal transmission facilities and other transmission costs not covered under the RNS rate, including 50% of the costs of construction work in progress (CWIP) on our remaining southwest Connect icut transmission projects.  Both the LNS and RNS rates are based on projected costs and the projected in-service dates of transmission projects and provide for annual true-ups to actual costs, which ensures that NU's transmission businesscosts.  The LNS rate calculation recovers its total transmission revenue requirements including the allowed ROE.net of revenues received from other sources (i.e. RNS, rental, etc.), thereby ensuring that we recover all regional and local revenue requirements as described in Tariff No. 3.  

FERC ROE Decision

On October 31, 2006, the FERC issued itsa decision (FERC ROE decision) on the specific ROE and incentives fora request by New England transmission owners.owners, including CL&P, PSNH and WMECO, for a number of incentives related to new transmission facilities.  The FERC set thea base ROE (before incentives) atrate of 10.2% for the historical locked-in period of February 1, 2005 (when the New England RTO was activated) to October 31, 2006.  Effectiveand effective November 1, 2006, the FERC also added a 70 basis point adjustment, to reflect upward pressure on the 10-year treasury rate, bringing the going forwardgoing-forward base ROE to 10.9%.  In addition, the FERC approved (i) a 50 basis point adder for joining an RTO participation and approved(ii) a 100 basis point adder for all new transmission investment where the projects have been identified as necessary by the ISO-NE regional planning process.  Bothprocess for a potential ROE adders for certain projects are retroactive to February 1, 2005.of 12.4%.

On a going forward basis, our transmission capital program is largely comprised of regional infrastructure that is included within the regional planning process.  Overprocess and thus eligible for FERC incentive treatment.  Approximately 90% of our projected $2.5$3 billion transmission capital program for 2007the period 2008 through 20112012 is expected to be in this category, and therefore is expected to earn at the RNS rate'sROE of 12.4% ROE..

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

On November 30, 2006, the New England Transmission Ownerstransmission owners jointly filed a rehearing request for an additional 30 basis points for the base ROE to correct what appears to be an error in the FERC's base ROE calculation.  Additionally, several New England Public Utilities Commissions, Consumer Counsels and Municipals have filed a rehearing request challenging the 70 basis point Treasury rate adderadjustment and the 100 basis point adder for new regional transmission investment.

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

As a result of theFERC ROE decision, we recorded an estimated regulatory liability for refunds of $25.6 million as of December 31, 2006.  During the first half of 2007, we completed the customer refunds that were calculated in accordance with the compliance filing required by the FERC ROE decision, and refunded approximately $23.9 million to regional, local and localized transmission customers. The $1.7 million positive pre-tax difference ($1 million after-tax) between the estimated regulatory liability recorded and the actual amount refunded was recognized in earnings in 2007.  

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

The transmission segment of our regulated companies refunded approximately $2.2 million of revenues related to the July 26, 2007 FERC order (approximately $1.4 million after-tax) while the distribution segment received a net after-tax benefit of approximately $0.3 million as a result of these refunds.  The refunds, net of benefits, totaling $1.1 million after-tax were recorded in 2007.  For further information, see "Transmission Rate Matters and FERC Regulatory Issues" in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," contained in our Annual Report to Shareholders which is incorporated herein by reference.

Other Rate Matters

Effective on February 1, 2006, NU began including 50% of construction work in progress (CWIP) for its four major southwest Connecticut transmission projects in its LNS rate for transmission service.  The new rates allow NU to collect 50% of the construction financing expenses while these projects are under construction.

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

On July 28, 2006, the FERC approved CL&P's proposal to allocate certain localized costs associated with the Bethel to Norwalk transmission project that are determined to be localized costs to all customers in Connecticut, as all of Connecticut will benefit from the reduction in congestion charges associated with the project.  There are three load serving entities in Connecticut:  CL&P, United Illuminating (UI)UI and the Connecticut Municipal ElectricalElectric Energy Cooperative.Cooperative (CMEEC).  These customers wouldbegan to pay their allocated shares of the localized costs on a projected basis commencing on June 1, 2006, subject to true-up based on actual costs.  On December 26, 2006, FERC rejected a request by UI for rehearing of this decision.  On February 23, 2007, UI appealed the FERC's orders to the D.C. Circuit Court of Appeals.  On January 8, 2008, UI withdrew its appeal.  

On September 22, 2006,November 1, 2007, we made a filing at FERC requesting recovery of deferred costs that we incurred as a result of our participation in the development, formation and startup of ISO-NE issued its determination letter with regard to CL&P's February 3, 2006 revised transmission cost allocation applicationas the RTO for the BethelNew England region.  We requested FERC’s approval to Norwalk transmission project.  The decision foundtransfer the costs to a regulatory asset account and to amortize them over a three year period beginning January 1, 2008.  On December 31, 2007, the FERC conditionally accepted our proposed rate recovery subject to refund and subject to a compliance filing.  For the compliance filing, FERC requested that $239.8 millionwe demonstrate that the proposed accounting will not cause any greater economic harm to our customers than if we had filed earlier and that we provide the purpose and nature of our costs in relation to the formation of the total estimated cost of $357.2 million qualifies as pool-supported pool transmission facilities costs, indicating $117.4 million of total estimated costs that are localized.  CL&P has decided not to challenge ISO-NE's cost allocation decision.RTO.

Transmission Projects

Our capital expenditures, including cost of removal, the allowance for funds used in construction, and the capitalized portion of pension expense or income, onongoing transmission projects in 2006 totaled approximately $465.5 million, mostcurrently consist of it at CL&P.  For 2006, CL&P's transmission capital expenditures totaled $415.6 million, PSNH's transmission capital expenditures totaled $36.1 million and WMECO's transmission capital expenditures totaled $13.0 million.

CL&P's transmission capital expenditures were primarily on fourthree major transmission projects in southwest Connecticut: 1) the completed Bethel to Norwalk project, 2) a 69-mile Middletown to Norwalk 115kV/345kV transmission project, 3) a related two-cable 115 kV underground project between Norwalk and Stamford, Connecticut (Glenbrook Cables), and 4) the replacement of the existing 138 kV cable between Connecticut and Long Island.  Each of these projects has received approval from the Connecticut Siting Council (CSC) and ISO-NE.   Connecticut;

The Bethel to Norwalk project, a 21-mile, 345 kV project between Bethel, Connecticut and Norwalk, Connecticut, was completed in the fourth quarter of 2006 at a cost of approximately $340 million, approximately $10 million below budget, and was fully energized and placed into service on October 12, 2006.·

CL&P has commenced site work on theA 69-mile, 345 kilovolt (kV)/115 kV transmission lineproject from Middletown to Norwalk, to be jointly built by UI and CL&P.  The project still requires some CSC review of certain detailed construction plans.  Although this project is currently expected to be completed by the end of 2009, opportunities to optimize schedule performance may result in an earlier completion date.  This project is currently 16 percent complete andConnecticut.  CL&P's portion of this project is estimated to cost approximately $1.05 billion.  At February 20, 2008, CL&P's portion of this project was approximately 70% complete.  As of December 31, 2006,2007, CL&P hashad capitalized $186.4$593 million associated with this project.  Although the project is scheduled to be completed by the end of 2009, construction of the project is currently ahead of schedule, and CL&P has reviewed the remaining work to determine whether it can be completed at an earlier date.  As a result of this review, we now expect to complete this project in mid-2009.

Construction has begun on the Glenbrook Cables Project, two 9-mile·

A two-cable, nine-mile, 115 kV underground transmission linesproject between Norwalk and Stamford, Connecticut (Glenbrook Cables), construction of which began in October of 2006.  This project is expectedestimated to cost approximately $183$223 million.  This project is currentlyscheduled to be completed by the end of 2008.  At February 20, 2008, this project was approximately 20% complete and on schedule for a December 2008 in-service date.  As of73% complete.  At December 31, 2006,2007, CL&P had capitalized $40.9$133 million of associated with this project.costs.  

Design·

The replacement of the 11-mile undersea 138 kV electric transmission cable between Connecticut and engineering work on theNorthport, Long Island, New York.  Permitting, contracting, and cable manufacturing for this project is complete.  CL&P and the Long Island Power Authority (LIPA) plans to replace a 138 kV undersea electric transmission line between Norwalk, Connecticut and Northport - Long Island, New York, is complete, and cable manufacturing commenced in mid-January, 2007.  CL&P and LIPA each own approximately 50% of thethis line.  CL&P's portion of the project is estimated to cost $72 million.  Final permits are expected by mid-2007 with marineMarine construction activities commencingcommenced in October 2007.  The projectedof 2007 and we expect that the project will be placed in service date remains in the second half of 2008.  ThroughThe previous cables were decommissioned in September 2007, and approximately 94% of the cables were removed as of December 31, 2006,2007, including all portions located in Connecticut.  Installation of the new cable began in early February 2008.  At February 20, 2008, the project was approximately 71% complete.  At December 31, 2007, CL&P had capitalized $16.9$45 million of associated with this project.costs, including the co st of the new cable which was delivered in the fourth quarter of 2007.

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In Decemberaddition, CL&P’s $335 million Bethel, Connecticut to Norwalk 345-kV transmission project, which entered service in late 2006, CL&P completedoperated well in 2007 and reduced Connecticut congestion costs by approximately $150 million in its first full year in service.

In addition to our current transmission construction and commenced commercial operationin southwest Connecticut, we continue to work with ISO-NE to refine the design criteria of a new substation in Killingly, Connecticut which will improve CL&P'sour next series of major transmission projects: (i) the New England East-West 345 kV and 115 kV transmission systems in northeast Connecticut.  As of December 31, 2006 CL&P had capitalized $25.9 million associated with thisOverhead project (NEEWS Overhead project) and estimates(ii) the final cost to be approximately $29 million, slightly below the budget of $32 million.   115 kV Springfield Underground Cables project (Springfield Underground Cables project).

As part of a larger regional system plan, NU, ISO-NE and National Grid have begun planningThe NEEWS Overhead project includes three 345 kV transmission upgrades to the transmission system connecting Massachusetts, Rhode Island and Connecticut in a comprehensive study called the Southern New England Transmission Reinforcement (SNETR) Project.  That study has led to the identification of three interdependent NU projects that work together towill collectively address the region's transmission needs --and better connect the major east-west transmission interfaces in Southern New England: 1) the Greater Springfield 345 kV Reliability Project, 2) the Central Connecticut Reliability Project, and 3) the Interstate Reliability Project.  Together, these three projects, along withA fourth upgrade, National Grid's Rhode Island Reliability project, are referred to asProject, is also included in the New England East-West Solution (NEEWS).  NU andNEEWS Overhead project.  In early 2007, we entered into a formal agreement with National Grid to plan and permit these projects and expect the ISO-NE technical review process with respect to the NEEWS Overhead project to conclude by mid- to late- 2008.  We will make the filing of the first project applications with the various state siting authorities shortly after receiving the technical approvals from ISO-NE.  We continue to work with ISO-NE to ensure that the design of these projects balances needs and reliability, operational flexibility, and cost.  At this time, we expect the siting process for the NEEWS Overhead project to be completed by 2010 and to complete construction in 2013.  We have not yet completed aupdated our detailed estimate of the total cost for the NEEWS Overhead project, and the timing of expenditures is highly dependent upon receipt of technical and siting approvals.  

The second major transmission project, the Springfield Underground Cables project, consists of a significant upgrade of the 115 kV electrical system around Springfield, Massachusetts to address thermal overload and voltage issues.  WMECO received a favorable vote from the ISO-NE Reliability Committee regarding the project’s technical feasibility in December 2007, and WMECO filed the siting application immediately thereafter with the Massachusetts siting agencies.  We expect the siting process to be completed in 2009 and expect WMECO to complete the project by the end of 2011.

Assuming that virtually all of the 345 kV portions of the NEEWS Overhead project are constructed overhead and on existing rights of way, we are maintaining our estimate of our share of the cost of the NEEWS Overhead project at approximately $1.05 billion.  We are also maintaining our estimate of the cost of the Springfield Underground Cables project at approximately $350 million at this time.  However, as we continue to review the designs of the NEEWS Overhead project and the Springfield Underground Cables project with ISO-NE over the coming months, we expect these upgrades, but NU estimatesfigures to change.  We anticipate that its sharewe will have additional information on the scope and costs of these projects may range from $1.1 billion to $1.4 billion of which approximately $710 million is included in its $2.5 billion 2007 thr ough 2011 capital budget.  NU and National Grid have entered into a formal agreement to plan and permit these projects.  by mid-2008.

We continue to review and analyze potential transmission solutions for New England’s environmental and operating challenges, particularly, meeting renewable portfolio standard and regional greenhouse gas initiative requirements, and improving reliability and fuel diversity.  In December, 2007 we delivered a presentation describing a conceptual set of high voltage direct current projects and their potential economic and environmental benefits at ISO-New England’s Planning Advisory Committee meeting.  We are continuing discussions with Canadian suppliers, New England transmission owners, New England state regulators and other key stakeholders to better understand the costs and benefits of new regional transmission solutions and the potential for a firm project total transmission capital expenditures for the period 2007-2011 to be approximately $2.5 billion.  Of that amount, we project that CL&P will spend approximately $2 billion, PSNH will spend approximately $246 million, and WMECO will spend approximately $200 million.proposal.

Transmission Rate Base

Under NU'sour FERC-approved tariffs, transmission projects enter rate base once they enterare placed in commercial operation.  Additionally, 50 percent50% of NU'sour capital expenditures on its foureach of our three major transmission projects still under construction in southwest Connecticut enter rate base during the construction period, with the remainder entering rate base once the projects are complete.  At the end of 2006, NU's2007, our estimated transmission rate base was $1.1approximately $1.5 billion, including approximately $840 million$1.2 billion at CL&P, $140$175 million at PSNH and $75$80 million at WMECO.  NU's total transmission rate base was approximately $600 million at the end of 2005.  The company forecastsWe forecast that itsour total transmission rate base will grow to approximately $1.4$3.9 billion atby the end of 2007, $1.9 billion at the end of 2008, $2.6 billion at the end of 2009, $2.8 billion at the end of 2010, and $3 billion at the end of 2011.2012. This increase in transmission rate base is driven by the need to improve the capacity and reliability of NU's reg ulatedour regulated transmission system.

A summary of projected year endyear-end transmission rate base by Utility Groupregulated company is as follows (millions of dollars):

For more information regarding Regulated Transmission matters, see "Transmission Rate Matters and FERC Regulatory Issues" and "Business Development and Capital Expenditures" under  Item 7, "Management's Discussion and Analysis of Financial Condition and

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Results of Operations" contained within NU's and CL&P's Annual Reports to Shareholders, which is incorporated into this Annual Report on Form 10-K by reference.

REGULATED GAS OPERATIONS

Yankee Energy System, Inc. (Yankee) is the holding company of Yankee Gas and two active non-utility subsidiaries, NorConn Properties, Inc., which holds certain minor properties and facilities of Yankee and its subsidiaries, and Yankee Energy Financial Services Company, which was in the business of providing Yankee Gas customers and other energy end-users with financing primarily for energy equipment installations, but which is in the process of winding up its business operations.

Yankee Gas operates the largest natural gas distribution system in Connecticut as measured by number of customers (approximately 200,000), and size of service territory (2,088 sq. miles).  Total throughput (sales and transportation) for 2006 was 45.2 BcF.  Yankee Gas provides firm gas sales service to customers who require a continuous gas supply throughout the year, such as residential customers who rely on gas for their heating, hot water and cooking needs.  Yankee Gas also offers firm transportation service to its commercial and industrial customers as well as interruptible transportation and interruptible gas sales service to those certain commercial and industrial customers that have the capability to switch from natural gas to an alternative fuel on short notice.  Yankee Gas can interrupt service to these customers during peak demand periods or at any other time to maintain distribution system integrity.  Yankee Gas offers firm and interruptible transporta tion services to customers who purchase gas from sources other than Yankee Gas.  In addition, Yankee Gas performs gas sales, gas exchanges and capacity releases to other market participants to reduce its overall gas expense.  

Yankee Gas earned $11.9 million on total gas operating revenues of approximately $454 million for the full-year 2006, compared with earnings of $17.3 million for full-year 2005.  Yankee Gas earnings were lower due primarily to an 11.2 percent decline in firm natural gas sales in 2006, compared with 2005, largely the result of milder weather in 2006.  The following table shows the sources of 2006 total gas operating revenues:

For more information regarding Yankee Gas' financial results, see Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," and Item 8, "Financial Statements and Supplementary Data," which includes Note 16, "Segment Information," within the notes to the consolidated financial statements, contained within NU's Annual Report to Shareholders, which is incorporated into this Form 10-K by reference.

Although Yankee Gas is not subject to the FERC's jurisdiction, the FERC does have limited oversight over certain intrastate gas transportation that Yankee Gas provides.  In addition, the FERC regulates the interstate pipelines serving Yankee Gas' service territory.

Yankee Gas is subject to regulation by the DPUC, which, among other things, has jurisdiction over rates, accounting procedures, certain dispositions of property and plant, mergers and consolidations, issuances of securities, standards of service, management efficiency and construction and operation of distribution, production and storage facilities.  

On December 29, 2006, Yankee Gas filed a request with the DPUC for a rate increase of approximately $67.8 million effective July 1, 2007.  The request proposes to recover the costs of constructing the liquefied natural gas (LNG) storage facility (described below) and the increased costs of providing distribution and delivery service.  Yankee Gas expects that this increase will be offset by savings in commodity and pipeline-related savings for a net revenue increase of approximately $37.2 million or 8.4% above current rates.  

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' previously recovered PGA costs and deferred any conclusion on the approximately $9 million of previously recovered revenues until the completion of the audit.  In a recent draft decision regarding Yankee Gas PGA charges for the period September 1, 2004 through August 31, 2005, an additional $2 million related to pre viously recovered revenues was also identified, bringing the total maximum amount at issue with regard to PGA clause charges under audit to $11 million.

The DPUC has hired a consulting firm which has begun an audit of Yankee Gas' previously recovered PGA costs.  Yankee Gas expects that the audit will be completed in the first half of 2007.  Management believes the unbilled sales and revenue adjustments and resultant charges to customers through the PGA clause for both periods were appropriate.  Based on the facts of the case and the supplemental

information provided to the DPUC, Yankee Gas believes the appropriateness of the PGA charges to customers for the time period under review will be approved, and has not reserved for any loss.

Yankee Gas is constructing an LNG facility in Waterbury, Connecticut capable of storing the equivalent of 1.2 billion cubic feet of natural gas.  It is expected to be put into service by mid-2007 in time for the 2007-2008 heating season at a total cost of approximately $108 million.  At December 31, 2006, the project was approximately 89% complete and Yankee Gas had capitalized $95.3 million related to this project.  In 2006, Yankee Gas also capitalized $41 million related to reliability improvements, new customer connections and other initiatives.

CONSTRUCTION AND CAPITAL IMPROVEMENT PROGRAM

The principal focus of our construction and capital improvement program is maintaining, upgrading and expanding the existing electric transmission and distribution system and natural gas distribution system.  Our consolidated capital expenditures for 2006,in 2007, including amounts incurred but not paid, cost of removal, allowance for funds used during construction and the capitalized portion of pension expense or income, totaled approximately $946 million,$1.3 billion, almost all of which approximately $908 million was expended by CL&P, PSNH, WMECO and Yankee Gas.  Approximately $466 million was spent by CL&P, PSNH and WMECO on transmission projects.the regulated companies.  The capital expenditures of these companies in 20072008 are estimated to total approximately $1.2$1.3 billion.  Of such totalthis amount, approximately $860$872 million is expected to be expended by CL&P, $211$275 million by PSNH, $50$85 million by WMECO and $62$56 million by Yankee Gas.  This construction program databudget includes all anticipated costs necessary for all committed capital projects (i.e. generation, transmission, distribution, environmental compliance and forothers) and those reasonably expected to become committed projects in 2007, regardless of whether the need for the project arises from environmental compliance, reliability requirements or other causes.  The construction program's ma in focus is maintaining, upgrading and expanding the existing electric transmission and distribution system and natural gas distribution system, including the construction of Yankee Gas' LNG facility.2008.  We expect to evaluate our needs beyond 20072008 in light of future developments, such as restructuring, industry consolidation, performance and other events.  If current plansIncreases in proposed distribution capital expenditures stems primarily from increasing labor and material costs and an aging infrastructure.  The costs (both labor and material) that our regulated companies incur to construct and maintain their electric delivery systems have increased dramatically in recent years.  These increases have been driven primarily by higher demand for commodities and electrical products, as well as increased demand for skilled labor.  Our regulated companies have many major classes of equipment that are implemented on schedule, we would likely requireapproaching or beyond their useful lives, such as old and obsolete distribution poles, underground primary cables and substation switchgear.  Replacement of this equipment is extremely costly.  Construction of the currently anticipated projects will r equire additional external debt financing at the subsidiary level to construct these projects.and debt and equity financing at the NU Parent level.

In 2006, CL&P's&P’s transmission capital expenditures in 2007 totaled $416approximately $661 million.  InThe increase in transmission segment capital expenditures in 2007 as compared with 2006 primarily relates to three major transmission projects under construction in southwest Connecticut: 1) the Middletown to Norwalk project, 2) the Glenbrook Cables project, and 3) the replacement of the underwater 138 kV cable between Connecticut and Long Island.

For 2008, CL&P projects transmission capital expenditures of approximately $590$538 million.  During the period 20072008 through 2011,2012, CL&P plans to invest approximately $2$1.95 billion in transmission projects, including $860$571 million to constructcomplete the Middletown to Norwalk transmission line, and $142 million for the Glenbrook Cables Project.  Approximately $55 million will be invested during this period to pay for CL&P's shareconstruction of replacing the 138 kV transmission line beneath Long Island Sound jointly owned by CL&P and LIPA.  If all of the transmission projects are built as proposed, our investment in electric transmission would increase from approximately $1.1 billion at the end of 2006 to nearly $3.0 billion by the end of 2011.its three southwest Connecticut projects.

In addition to its transmission projects, CL&P plans to make distribution capital expenditures intended to meet growth requirements and improve the reliability of its distribution system and to meet growth requirements on the distribution system.  In 2006,2007, CL&P's distribution capital expenditures totaled $210.3approximately $283 million.  In 2007, as a result ofDue to significant peak load growth in recent years, CL&P projects increasing distribution capital expenditures to approximately $270 million.$334 million in 2008.  CL&P plans to spend approximately $1.4$1.5 billion on distribution projects during the period 2007-2011.2008-2012.  If all of the distribution and transmission projects are built as proposed, CL&P’s rate base for electric transmission is projected to increase from approximately $1.2 billion at the end of 2007 to approximately $2.8 billion by the end of 2012, and its rate base for distribution assets is projected to increase from approximately $1.9 billion to approximately $2.7 billion over the same period.

In December, 2006, PSNH completed final testing and began commercial operation of its new wood-burning generation plant (Northern Wood Power Project), which replaced one of the three 50 MW boiler units at the coal-fired Schiller Station.  As of December 31, 2006, PSNH had capitalized approximately $74 million related to this project.

In 2006, PSNH's transmission capital expenditures totaled $36 million and its distribution capital expenditures totaled $77.5 million.  PSNH's generation capital expenditures totaled $32.1 million in 2006.  In 2007, PSNH's transmission capital expenditures are projected to betotaled approximately $83$81 million, its distribution capital expenditures are expected to be approximately $91totaled $88 million and its generation capital expenditures totaled $35 million.  For 2008, PSNH projects transmission capital expenditures of approximately $37$108 million, distribution capital expenditures of approximately $104 million and generation capital expenditures of approximately $63 million.  The increase in distribution capital expenditures is mostly due to additional reliability spending.expenditures, the new Cyber Security program and a number of major substation projects.  The declineincrease in generation capital expenditures is mostly due to the completion in 2006 ofMerrimack 2 HP/IP and air heater tube replacement projects as well as higher expenditures for the Northern Wood Power Project.Merrimack Scrubber project. During the period 2007-2011,2008-2012, PSNH plans to spend approximately $246$401 million on transmission projects and approximately $650$887 million on distribution and generation projects.projects, including the installation of a wet scrubber to reduce mercury and sulfur emissions at its 440 MW coal-fired plant at Merrimack Station.  If all of the distribution, generation and transmission projects are built as proposed, PSNH’s rate base for electric transmission is projected to increase from approximately $175 million at the end of 2007 to approximately $458 million by the end of 2012, and its rate base for distribution and generation assets is projected to increase from approximately $925 million to approximately $1.4 billion over the same period.

In 2006,2007, WMECO's transmission capital expenditures totaled $13approximately $19 million and its distribution capital expenditures totaled $30approximately $34 million.  In 2007,2008, WMECO projects transmission capital expenditures to beof approximately $16$50 million and its distribution capital expenditures to beof approximately $34$35 million.  During the period 2007-2011,2008-2012, WMECO plans on spendingto spend approximately $200$648 million on transmission projects, with the bulk of that amount to be spent on the 115 kV Springfield Underground Cables project and the NEEWS 115 kV and 345 kV Overhead projects, and approximately $159$177 million on distribution projects.  If all of the distribution and transmission

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projects are built as proposed, WMECO’s rate base for electric transmission is projected to increase from approximately $81 million at the end of 2007 to approximately $606 million by the end of 2012 and its rate base for distribution assets is projected to increase from approximately $372 million to approximately $503 million over the same period.

In 2006,2007, Yankee Gas'Gas’s capital expenditures totaled $89.9approximately $64 million, approximately 54%$12 million of which was for the construction of theits LNG facility.  The facility is expectedwas filled with LNG by the end of October 2007 to be put intoserve customers during the 2007/2008 heating season. The LNG facility was placed in service in mid-2007 in time for the 2007/ 2008 heating season atJuly 2007 on budget with a final cost of approximately $108 million. In 2006,2007, Yankee Gas also spent $20.3$23 million on its reliability improvement program, $13.8$20 million on connecting new customers, and $6.9$9 million on other initiatives, including meters and information technology systems.  In 2007,For 2008, Yankee Gas projects total capital expenditures of approximately $62$56 million.  The decline from 2006 is attributable to the expected completion of the LNG facility.  During the period 2007-2011,2008-2012, Yankee Gas plans on making approximately $227$305 million of capital expenditures.  If all of Yankee Gas’s projects are built as proposed, Yankee Gas’s investment in its regulated assets is projected to increase from approximately $666 m illion at the end of 2007 to approximately $806 million by the end of 2012.

Strategic Initiatives: We are also evaluating certain development projects that would benefit our customers, such as new regulated generating facilities, investments in AMI systems to provide time-of-use rates to our customers, and transmission projects to better interconnect new renewable generation in northern New England and Canada with southern New England, as well as interconnections within New Hampshire. The estimated capital expenditures and projected rate base amounts discussed above do not include expenditures related to these initiatives.

For more information regarding NU and its subsidiaries' construction and capital improvement program,programs, see "Business Development and Capital Expenditures" under Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained within NU's and CL&P's Annual Reports to Shareholders, which is incorporated into this Annual Report on Form 10-K by reference.

STATUS OF EXIT FROM COMPETITIVE ENERGY BUSINESSES

Since we announced in March 2005, that we intended to exit from the wholesale energy marketing and energy services businesses of our subsidiary NU Enterprises, and our announcement in November 2005 that we would exit from the retail energy marketing and competitive generation businesses of NU Enterprises as well, we have made substantial progress towards our goalbeen in the process of exiting suchour competitive energy businesses and are now focusing exclusively on our regulated business.  An overviewbusinesses.  At December 31, 2007, our competitive businesses consisted solely of this progress follows:(i) Select Energy’s few remaining wholesale marketing contracts and (ii) NU Enterprises’ remaining energy services business, consisting of NGS, Boulos and the Connecticut division of SECI.

Competitive Generation.  On November 1, 2006, we closed onFour of the sale of NU Enterprises' 100% ownership in Northeast Generation Company (NGC), and of Holyoke Water Power Company's (HWP) 146 MW Mt. Tom coal-fired plant for an aggregate amount of $1.34 billion, which included the assumption of $320 million of NGC debt.  We now own no competitive or merchant generation assets.

Wholesale Marketing Business:  In 2005,five remaining Select Energy Inc. (Select Energy) completed the divestiture of its New England wholesale sales contracts.  Select Energy continues to serve itscontracts that were in the PJM power pool at the beginning of 2007 expired on May 31, 2007.  The remaining PJM and New York wholesale sales contract obligations.  Aswill expire on May 31, 2008.  Select Energy’s wholesale contract with The New York Municipal Power Agency (NYMPA) expires in 2013.  In addition to the PJM and NYMPA contracts, Select Energy's only other long-term wholesale obligation is a long-term non-derivative contract to purchase the output of December 31, 2006,a certain generating facility in New England through 2012.  

Also in 2007, the remaining sales obligations were approximately 7.5 million megawatt-hours (MWh), down from approximately 22 million MWh ascontracts of March of 2005 when we announced we were exiting the wholesale marketing business.  Select Energy has also taken steps to reduce the volatility of these obligations by hedging a portion of them.

Retail Marketing Business:  On June 1, 2006, Select Energy sold its retail marketing business, including its retail sales obligations and related supply contracts.  Under the terms of the agreement, Select Energy paid the buyer approximately $11.5 million at closing and approximately $12.9 million in December of 2006, and will pay approximately $15 million by the end of 2007.  

Energy Services Businesses:  Woods Network, Inc.SECI and the New Hampshire operations of Select Energy Contracting, Inc. (SECI), including Reeds Ferry, Inc., were sold in November of 2005.  In January of 2006, the Massachusetts service division of SECI was sold.  In April of 2006, NU Enterprises sold the services division of NGS Acquisition, Inc. (formerlyformer Woods Electrical Co., Inc.), and in May of 2006, NU Enterprises sold its 100% ownership of Select Energy Services, Inc. (SESI).

Competitive Energy Business Assets Retained:  Assets that have not yet either been sold or placed under contract to be sold by NU Enterprises are as follows:

-

Select Energy's wholesale contracts (five PJM sales contracts, four of which expire in 2007 and one of which expires in 2008, one NYMPA sales contract that expires in 2013 and three power purchase contracts, two of which expire in 2007);

-

Remaining assets, liabilities and contingencies associated with previously divested businesses or companies, including a contract to complete a cogeneration facility;

-

Contracts associated with the wind-down of the remaining operations of Northeast Generation Services Company, SECI and NGS Acquisition, Inc., (formerly Woods Electrical Co., Inc.); and

-

E.S. Boulos Company.

In addition, provisions of the SESI purchase and sale agreement require NU to indemnify the buyer for estimated costs to complete or modify specific construction projects above specified levels.  Provisions of the purchase and sale agreements related to the other divested businesses contain indemnifications and/or guarantees by NU.  See Note 8H "Guarantees and Indemnifications," for further information regarding these guarantees and indemnifications.

wound down.  For more information regarding the exit of the competitive businesses, see "NU Enterprises Exit"Divestitures" under Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 3, "Assets Held for Sale and Discontinued Operations," to the consolidated financial statements, contained within NU'sour Annual Report to Shareholders, which is incorporated into this Annual Report on Form 10-K by reference.

FINANCING

NUWe paid dividends on our common dividendsshares totaling $121 million in 2007, compared to $112.7 million in 2006, compared to $87.6 million paid in 2005, reflecting an increase in the number of outstanding common shares of NU as a result of its share offering in December 2005, and increases in the quarterly dividend rateamount that were effective in the third quarters of 20052006 and 2006.2007.

TotalOur total debt, of NU and its subsidiaries, including short-term debt, capitalized lease obligations and prior spent nuclear fuel liabilities, but not including rate reduction bonds or certificates, was approximately $3.0$3.7 billion as of December 31, 2006.2007.

During 2007, the regulated companies issued the following debt:

On March 27, 2007, CL&P issued $150 million of its 10-year first and refunding mortgage bonds carrying a coupon rate of 5.375%, and $150 million of its 30-year first and refunding mortgage bonds carrying a coupon rate of 5.75%.  

On August 17, 2007, WMECO issued $40 million of its 30-year unsecured senior notes with a coupon rate of 6.7%.

On September 17, 2007, CL&P issued $100 million of its 10-year first and refunding mortgage bonds carrying a coupon rate of 5.75%, and $100 million of its 30-year first and refunding mortgage bonds carrying a coupon rate of 6.375%.

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On September 24, 2007, PSNH issued $70 million of its 10-year first mortgage bonds with a coupon rate of 6.15%.

At December 31, 2006,2007, NU parent maintained a parent company revolving credit facility of $500 million, and CL&P, PSNH, WMECO and Yankee Gasthe regulated companies maintained a joint revolving credit facility of $400 million, both of which expire on November 6, 2010.  At December 31, 2006, NU had no2007, there were $42 million in borrowings on that credit line, but approximately $67.5and $27 million ofin letters of credit issued in connection with Select Energy's businessoutstanding under the NU parent credit facility.  There were secured$45 million of long-term borrowings by that line.  Neither CL&P, PSNH, WMECO nor Yankee Gas had any borrowings outstanding under their creditthe regulated companies’ facility at December 31, 2006.2007.  In addition, there were $10 million and $27 million in short-term borrowings by PSNH and Yankee Gas, respectively, outstanding under the regulated companies’ facility at December 31, 2007.

In addition, CL&P has access to funds under an arrangement with its subsidiary, CL&P Receivables Corporation (CRC).  CRC has an agreement with CL&P to purchase up to $100 million of an undivided interest in CL&P's accounts receivables and unbilled revenues, which CRC sells to a highly rated financial institution on a limited recourse basis.  CL&P's continuing involvement with the receivables that are sold to CRC and the financial institution is limited to the servicing of those receivables.  At December 31, 2006,2007, CL&P had no borrowingssold $20 million under this facility.

Financial Covenants in Credit Facilities

.  Under their revolving credit facility agreement,agreements, each of NU, CL&P, WMECO, PSNH and Yankee Gas must each maintain a ratio of consolidated debt to total capitalization of no more than 65%.  At December 31, 2006,2007, NU, CL&P, WMECO, PSNH, and Yankee Gas ratios were, and are expected to remain, in compliance with these ratios.

Under its revolving credit agreement, NU must maintain a ratio of debt to total capitalization of no more 67.5% through March 31, 2006 and 65.0% thereafter.  At December 31, 2006, NU was, and expects to, remain in compliance with this ratio.

For more information regarding NU and its subsidiaries' financing, see "Notes to Consolidated Financial Statements" in NU's financial statements, the footnotes related to long-term debt, short-term debt, leases and the sale of accounts receivables, as applicable, in the notes to NU's, CL&P's, PSNH's, and WMECO's financial statements, and "Liquidity" under Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained within NU's and CL&P's Annual Reports to Shareholders, which are incorporated into this Annual Report on Form 10-K by reference.

STATUS OF NUCLEAR DECOMMISSIONING

General

CL&P, PSNH, WMECO and other New England electric utilities are the stockholders inof three regional nuclear companies, Connecticut Yankee Atomic Power Company (CYAPC), Maine Yankee Atomic Power Company (MYAPC) and Yankee Atomic Electric Company (YAEC) (the Yankee Companies).  EachUntil recently, each Yankee Company ownsowned a single nuclear generating unit –the Connecticut Yankee nuclear unit, (CY), the Maine Yankee nuclear unit, (MY), and the Yankee Rowe nuclear unit (YA).  YA, CY and MYunit.  The Yankee Companies have been permanently removed from servicecompleted the physical decommissioning of their respective facilities and are being decontaminated and decommissioned.  The stockholder-sponsors of each Yankee Company are responsible for proportional shares of the operating and decommissioning costs of each respective Yankee Company.  CL&P's, PSNH's and WMECO's stock ownership percentagesnow engaged in the Yankee Companies are set forth below:

The Nuclear Regulatory Commission (NRC) has broad jurisdiction over the decommissioning activities at the Yankee Companies.

Decommissioning

CL&P, PSNH and WMECO each have significant decommissioning and plant closure cost obligations to CYAPC, YAEC and MYAPC.long-term storage of their spent nuclear fuel.  Each Yankee Company collects thesedecommissioning and closure costs through wholesale FERC-approved rates charged under power purchase agreements with several New England utilities, including CL&P, PSNH and WMECO.  These companies in turn passrecover these costs on tofrom their customers through state regulatory commission-approved retail rates.  

On June 10, 2004, the DPUC and the Connecticut Officera tes.  The stock ownership percentages 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 should not be allowed to recover in their retail rates any costs that the FERC might determine to

have been imprudently incurred.  The FERC rejected the DPUC's and OCC's petition, whereupon the DPUC filed an appeal of the FERC's decision with the D.C. Circuit Court of Appeals (Court of Appeals).

On November 16, 2006, FERC approved a settlement agreement between CYAPC, the DPUC, the OCC and Maine state regulators.  The settlement agreement, which provides a revised decommissioning estimate of $642.9 million (in 2006 dollars), taking into account actual spending through 2005 and the current estimate for completing decommissioning and long-term storage of spent fuel, a gross domestic product escalator of 2.5% for costs incurred after 2006, and a 10% contingency factor for all decommissioning cost, disposes of the pending litigation at the FERC and the Court of Appeals, among other issues.  

Spent Nuclear Fuel Litigation

YAEC, MYAPC, and CYAPC commenced litigation in 1998 against the United States Department of Energy (DOE) charging that the federal government breached contracts it entered into with each Yankee Company in 1983 under the Nuclear Waste Policy Act of 1982 to begin removing spent nuclear fuel from the respective nuclear plants no later than January 31, 1998 in return for payments by each Yankee Company into the Nuclear Waste Fund.  The funds for those payments were collected from regional electric customers.  The Yankee Companies initially claimed damages for incremental spent nuclear fuel storage, security, construction and other costs through 2010.

In a ruling released on October 4, 2006, the Court of Federal Claims held that the DOE was liable for damages to CYAPC for $34.2 million through 2001, YAEC for $32.9 million through 2001 and MYAPC for $75.8 million through 2002.  The Yankee Companies had claimed actual damages for the same period as follows: CYAPC: $37.7 million; YAEC: $60.8 million; and MYAPC: $78.1 million.  The Yankee Companies believe they will have the opportunity in future lawsuits to seek recovery of actual damages incurred in the years following 2001-2002.  The refund to CL&P, PSNH and WMECO of any damages that may be recovered from the DOE is established in the Yankee Companies'Companies are set forth below:

Our share of the obligations to support the Yankee Companies under FERC-approved rate settlement agreement, although implementation will be subject to final determination of FERC.  CL&P, PSNH and WMECO expect to pass any recovery onto its customers therefore no earnings are expected to result.  The DOE appealed this decision in December 2006.rules is the same as the ownership percentages above.

For more information regarding Nuclear matters,decommissioning and nuclear assets, see "Notes to Consolidated Financial Statements" in NU's financial statements, the footnotes related to Spent Nuclear Fuel Disposal Costs, in the notes to NU's, CL&P's, PSNH's, and WMECO's financial statements and "Deferred Contractual Obligations" under Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" containedOperations," within NU's and CL&P'sour Annual ReportsReport to Shareholders, which is incorporated into this Annual report on Form 10-K by reference.

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OTHER REGULATORY AND ENVIRONMENTAL MATTERS

General

We are regulated in virtually all aspects of our business by various federal and state agencies, including the SEC, the FERC, the NRCSEC, and various state and/or local regulatory authorities with jurisdiction over the industry and the service areas in which each of our companies operates, including the DPUC having jurisdiction over CL&P and Yankee Gas, the NHPUC having jurisdiction over PSNH, and the DTEDPU having jurisdiction over WMECO.  Pursuant to the Energy Policy Act of 2005 (EPAct), PUHCA 1935, which provided the SEC with jurisdiction over various aspects of our operations, was repealed on February 8, 2006, and jurisdiction over a number of areas covered by PUHCA 1935 was assumed by the FERC under the PUHCA 2005 provisions of EPAct.

Environmental Regulation

We are subject to various federal, state and local requirements with respect to water quality, air quality, toxic substances, hazardous waste and other environmental matters.  Additionally, our major generation and transmission facilities may not be constructed or significantly modified without a review of the environmental impact of the proposed construction or modification by the applicable federal or state agencies.  Compliance with increasingly stringent environmental laws and regulations, particularly air and water pollution control requirements, may limit operations or require substantial investments in new equipment at existing facilities.

Water Quality Requirements

The federal Clean Water Act requires every "point source" discharger of pollutants into navigable waters to obtain a National Pollutant Discharge Elimination System (NPDES) permit from the United States Environmental Protection Agency or state environmental agency specifying the allowable quantity and characteristics of its effluent.  States may also require additional permits for discharges into state waters.  Our facilitiesWe are in the process of obtaining or renewing all required NPDES or state discharge permits in effect.effect for our facilities. Compliance with NPDES and state discharge permits has necessitated substantial expenditures and may require further significant expenditures, which are difficult to estimate, because of additional requirements or restrictions that could be imposed in the future, including requirements related to Sections 316(a) and 316(b) of the Clean Water Act for facilities owned by PSNH.  

Air Quality Requirements

The Clean Air Act Amendments of 1990 (CAAA), as well as state laws in Connecticut, Massachusetts and New Hampshire, impose stringent requirements on emissions of sulfur dioxide (SO2)(SO₂) and nitrogen oxide (NOX)(NO_X) for the purpose of controlling acid rain and ground level ozone.  In addition, the CAAA address the control of toxic air pollutants.  Installation of continuous emissions monitors and expanded permitting provisions also are included.    

In New Hampshire, the Multiple Pollutant Reduction Program was signed into law in May 2002.  Under this law, NOX, SO2NO_X, SO₂ and Carbon Dioxide (CO2)(CO₂) emission are capped for current compliance beginning in 2007.  A law was passed during the 2006 legislative session requiring reductions in emissions of mercury from PSNH's coal-fired plants.plants, including those owned by PSNH.  The law requires PSNH to install a wet flue gas desulphurization system, known as "scrubber" technology, to reduce mercury emissions (with the co-benefit of reductions in SO2SO₂ emissions as well) at Merrimack Station no later than July 1, 2013.  PSNH currently anticipates the cost to complythat compliance with this law to bewill cost $250 million, but this amount has the potential to increase materially as the project is undertaken, primarily as a result of changes in commodity prices and labor costs.  

The Regional Greenhouse Gas Initiative (RGGI) is a cooperative effort by ninea group of northeastern states, including Massachusetts, New Hampshire and Connecticut, to develop a regional program for stabilizing and reducing CO2CO₂ emissions from fossil-firedfossil fuel-fired electric generators.  This initiative proposes to stabilize CO2CO₂ emissions at current levels and require a ten percent10% reduction from the initial 2009 permitted emissions levels by 2020.  The RGGI agreement (MOU) was signed on December 20, 2005 by the states of Connecticut, Delaware, Maine, New Jersey, New Hampshire, New York and Vermont. On January 18, 2007, Massachusetts also committed to the MOU.2018.  Each signatory state committed to propose for approval legislative and/or regulatory mechanisms to implement the program.  The Connecticut Department of Environmental Protection (CDEP) released draft RGGI may impact PSNH's Merrimack, Newingtonregulations on December 28, 2007 and Schiller stations.  Athad a public hearing on February 8, 2008.  The CDEP plans to have these rules finalized by May 2008 and to participate in a proposed open regional auction of CO₂ allowances in June 2008.  Connecticut has proposed an auction of 91% of allocat ed CO₂allowances with the remainder set aside for certain clean energy projects.  Connecticut has proposed the first compliance period for affected facilities to begin on January 1, 2009.  Although neither CL&P nor Yankee Gas currently have any facilities subject to the RGGI program, CL&P expects the cost of purchased energy supply to increase due to RGGI requirements.  NU Enterprises manages a facility in Connecticut under a non-derivative contract which will likely be required to purchase CO₂ allowances.  Massachusetts Department of Environmental Protection and Division of Energy Resources released their draft RGGI regulations on August 10, 2007.  The final rule is expected in early 2008 and Massachusetts also plans to participate in the June 2008 regional auction.  Although WMECO has no facilities that would be subject to this rule, it also expects the cost of purchased energy to increase.  PSNH is the only one of our regulated compani es that currently owns any generation assets that could be subject to the RGGI standards.

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In New Hampshire, draft legislation has been proposed during this 2008 session that is consistent with the RGGI initiative.  However, at this time because the draft legislation has not yet been finalized and because the cost of CO₂ allowances under RGGI cannot be identified with any certainty, we cannot quantifyare unable to determine the actual cost of RGGI and its impact on customer rates.    

On May 11, 2007, New Hampshire adopted renewable portfolio standards for electricity sold in the state which ultimately requires that 23.8% of the MOUelectricity sold to retail customers have direct ties to renewable sources by 2025.  The renewable sourcing requirements begin in 2008 and increase each year to reach 23.8% by 2025.  PSNH will be required to comply with these standards.  We expect that the additional costs incurred to meet this new requirement will be recovered through PSNH’s energy service rates.

In addition, many states and environmental groups have challenged certain of the federal laws and regulations relating to air emissions as not being sufficiently strict.  As a result, it is possible that state and federal regulations could be developed that will impose more stringent limitations on our companies.  A model set of regulations was promulgated by the RGGI Statesemissions than are currently in August 2006 to implement the program.  Individual R GGI States are now initiating legislative and/or regulatory processes to implement their individual programs.   effect.

Hazardous Materials Regulations

Prior to the last quarter of the 20^th century when environmental best practices and laws were implemented, we, like most industrial companies, disposed of residues from operations were often disposed of by depositing or burying such materials on-site or disposing of them at off-site landfills or facilities.  Typical materials disposed of include coal gasification waste, fuel oils, ash, gasoline and other hazardous materials that might contain polychlorinated biphenyls.  It has since been determined that deposited or buried wastes, under certain circumstances, could cause groundwater contamination or create other environmental risks.  We have recorded a liability for what we believe is, based upon currently available information, our estimated environmental investigation and/or remediation costs for waste disposal sites for which we expect to bear legal liability, and continue to evaluate the environmental impact of our former disposal practices.  Under federal and state law, gov ernment agenciesgovernment age ncies and private parties can attempt to impose liability on us for such past disposal.  At December 31, 2006,2007, the liability recorded by us for our estimatedestimable environmental remediation costs for known sites needing investigation and/or remediation, exclusive of recoveries from insurance or from third parties, was approximately $26.8$25.8 million, representing 51 sites.53 liabilities.  All cost estimates were made in accordance with generally accepted accounting principles where investigation and/or remediation costs are probable and reasonably estimable.  These costs could be significantly higher if additional remedial actions become necessary.necessary or when additional information as to the extent of contamination becomes available.

The greatestmost significant liabilities currently relate to future clean up costs at former manufactured gas plant (MGP) facilities which represent the largest share of future clean up costs.facilities.  These facilities were owned and operated by predecessor companies to us from the mid-1800's to mid-1900's.  By-products from the manufacture of gas using coal resulted in fuel oils, hydrocarbons, coal tar, purifier wastes, metals and other waste products that may pose risks to human health and the environment.  We, through our subsidiaries, currently have partial or full ownership responsibilities at 28 former MGP sites.  Of our total recorded liabilities of $26.8$25.8 million, a reserve of approximately $24.8$23.6 million has been established to address future investigation and/or remediation costs at MGP sites.  In addition, remediation has been conducted at a coal tar contaminated river site in Massachusetts that is at least partially the responsibility of HWP.Holyoke Water Power Company (HWP), a subsidiary of NU, which previously own ed generating assets.  The cost to clean up that contamination may be more significant than cu rrentlycurrently estimated, but the level and extent of contamination is not yet known.remains unknown.  Any and all exposure related to this site is not subject to ratepayer recovery.  An increase to the environmental reserve for this site would be recorded in earnings forin future periods and may be material.

In the past, we or our subsidiaries have received other claims from government agencies and third parties for the cost of remediating sites not currently owned by us but affected by our past disposal activities and may receive moreadditional such claims in the future.  We expect that the costs of resolving claims for remediating sites about which we have been notified will not be material, but we cannot estimate the costs with respect to sites about which we have not been notified.

For further information on environmental liabilities, see FootnoteNote 8B, "Commitments and Contingencies - Environmental Matters" contained within NU's 20062007 Annual Report to Shareholders, which is incorporated into this Annual Report on Form 10-K by reference.

Electric and Magnetic Fields

For more than twenty years, published reports have discussed the possibility of adverse health effects from electric and magnetic fields (EMF) associated with electric transmission and distribution facilities and appliances and wiring in buildings and homes.  Although weak health risk associations reported in some epidemiology studies remain unexplained, most researchers, as well as numerous scientific review panels, considering all significant EMF epidemiology and laboratory studies, to date, agreehave concluded that currentthe available body of scientific information does not support the conclusion that EMF affects human health.

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We have closely monitored research and government policy developments for many years and will continue to do so.  In accordance with recommendations of various regulatory bodies and public health organizations, NU reduceswe reduce EMF associated with new transmission lines by the use of designs that can be implemented without additional cost or at a modest cost.  We do not believe that other capital expenditures are appropriate to minimize unsubstantiated risks.

FERC Hydroelectric Project Licensing

New Federal Power Act licenses may be issued for hydroelectric projects for terms of 30 to 50 years as determined by the FERC.  Upon the expiration of an existing license, (i) the FERC may issue a new license to the existing licensee, or (ii) the United States may take over the project or (iii) the FERC may issue a new license to a new licensee, upon payment to the existing licensee of the lesser of the fair value or the net investment in the project, plus severance damages, less certain amounts earned by the licensee in excess of a reasonable rate of return.

PSNH owns nine hydroelectric generating stations with an aggregate of approximately 66.3 MW of capacity, with a current claimed capability representing winter rates, of approximately 69.5 MW.  Of these nine plants, eight are licensed by the FERC under long-term licenses that expire on varying dates from 2009 through 20362036.  As a licensee under the FPA,Federal Power Act (FPA), PSNH and its licensed hydroelectric projects are subject to conditions set forth in the FPA and related FERC regulations, including provisions related to the condemnation of a project upon payment of just compensation, amortization of project investment from excess project earnings, possible takeover of a project after expiration of its license upon payment of net investment and severance damages and other matters.   

FERC hydroelectric project licenses expire periodically and the generating facilities must be relicensed at such times.  PSNH's Merrimack River Hydroelectric Project and Canaan Hydroelectric Project are currently in FERC relicensing proceedings.  TheA new FERC license for thePSNH’s Merrimack River Hydroelectric Project, which consists of the Amoskeag, Hooksett and Garvins Falls generating stations, expiredwas issued on December 31, 2005.  This project is currently operating under an annual FERC license, and the issuance of a new long-term license for the Merrimack RiverMay 18, 2007.  PSNH's Canaan Hydroelectric Project is anticipated during the first half of 2007.currently in FERC relicensing proceedings.  The license for the Canaan Hydroelectric Project expires in 2009, and the issuance of a new license for the Canaan Hydroelectric Project is not anticipated for several years.2009.

Licensed operating hydroelectric projects are not generally subject to decommissioning during the license term in the absence of a specific license provision which expressly permits the FERC to order decommissioning during the license term.  However, the FERC has taken the position that under appropriate circumstances it may order decommissioning of hydroelectric projects at relicensing or may require the establishment of decommissioning trust funds as a condition of relicensing.  The FERC may also require project decommissioning during a license term if a hydroelectric project is abandoned, the project license is surrendered or the license is revoked.

At this time, it appears unlikely that the FERC will order decommissioning of PSNH's hydroelectric projects at relicensing or that the projects will be abandoned, surrendered or the project licenses revoked.  However, it is impossible to predict the outcome of the FERC relicensing proceedings with certainty, or to determine the impact of future regulatory actions on project economics.  Until such time as a project is ordered to be decommissioned and the terms and conditions of a decommissioning order are known, any estimates of the cost of project decommissioning are preliminary and subject to change as new information becomes available.

EMPLOYEES

As of December 31, 2006, the NU system companies had2007, we employed a total of 5,869 employees, on their payrolls, excluding temporary employees, of which 1,8121,825 were employed by CL&P, 1,2861,210 by PSNH, 336337 by WMECO, and 395393 by Yankee Gas.Gas and 1,954 were employed by Northeast Utilities Service Company (NUSCO).  

Approximately 2,2002,217 employees of CL&P, PSNH, WMECO, NUSCO and Yankee Gas are covered by 11 union agreements.    During 2005 and 2006, 11 contracts under negotiation have been ratified.  

INTERNET INFORMATION

Our Web sitewebsite address is http://www.nu.com.  We make available through our Web sitewebsite a link to the SEC's EDGAR site, at which site NU's, CL&P's, WMECO's and PSNH's annual reportsAnnual Reports on Form 10-K, quarterly reportsQuarterly Reports on Form 10-Q, current reportsCurrent Reports on Form 8-K and any amendments to those reports may be reviewed.  Printed copies of these reports may be obtained free of charge by writing to our Investor Relations Department at Northeast Utilities, 107 Selden Street, Berlin, Connecticut 06037.

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Item 1A.

Risk Factors

We are subject to a variety of significant risks in addition to the matters set forth under "Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995" in Item 1, "Business," above.  Our susceptibility to certain risks, including those discussed in detail below, could exacerbate other risks.  These risk factors should be considered carefully in evaluating our risk profile.

The Infrastructure Of Our Transmission And Distribution System May Not Operate As Expected, And Could Require Additional Unplanned Expense Which Would Adversely Affect Our Earnings.infrastructure of our transmission and distribution system may not operate as expected, and could require additional unplanned expense which could adversely affect our earnings.

Our ability to manage operational risk with respect to our transmission and distribution systems is critical to the financial performance of our business.  Our transmission and distribution businesses face several operational risks, including the breakdown or failure of or damage to equipment or processes (especially due to age), accidents and labor disputes.  The costs (both labor and material) that our regulated companies incur to construct and maintain their electric delivery systems have increased in recent years.  These increases have been driven primarily by higher demand for commodities and electrical products, as well as increased demand for skilled labor.  A significant percentage of our regulated company equipment is nearing or at the end of its life cycle, such as old and obsolete distribution poles, underground primary cables and substation switchgear.  The failure of our transmission and distributions systems to operate as planned may result in increased capital investments, reduced earnings or unplanned increases in expenses, including higher maintenance costs.  Any such costs which may not be recoverable from our ratepayers would have an adverse effect on our earnings.

VolatilityChanges in Electricregulatory or legislative policy, difficulties in obtaining siting, design or other approvals, global demand for critical resources, or environmental or other concerns, or construction of new generation may delay completion of or displace our transmission projects or adversely affect our ability to recover our investments or result in lower than expected rates of return.

The successful implementation of our transmission construction plans is subject to the risk that new legislation, regulations or judicial or regulatory interpretations of applicable law or regulations could impact our ability to meet our construction schedule and/or require us to incur additional expenses and Gas Prices May Adversely Impact Salesmay adversely affect our ability to achieve forecast levels of revenues.  In addition, difficulties in obtaining required approvals for construction, or increased cost of and difficulty in obtaining critical resources as a result of global or domestic demand for such resources could cause delays in our construction schedule and may adversely affect our ability to achieve forecasted earnings.

The regulatory approval process for our planned transmission projects encompasses an extensive permitting, design and technical approval process.  Various factors could result in increased cost estimates and delayed construction.  These include environmental and community concerns and design and siting issues.  Recoverability of all such investments in rates may be subject to prudence review at the FERC at the time such projects are placed in service.  While we believe that all such expenses have been and will be prudently incurred, we cannot predict the outcome of future reviews should they occur.

In addition, to the extent that new generation facilities are proposed or built to address the region’s energy needs, the need for our planned transmission projects may be delayed or displaced, which could result in reduced transmission capital investments, reduced earnings, and limit future growth prospects.

The currently planned transmission projects are expected to help alleviate identified reliability issues and to help reduce customers' costs.  However, if, due to further regulatory or other delays, the projected in-service date for one or more of these projects is delayed, there may be increased risk of failures in the existing electricity transmission system and supply interruptions or blackouts may occur which could have an adverse effect on our earnings.  

The FERC has followed a policy of providing incentives designed to encourage the construction of new transmission facilities, including higher returns on equity and allowing facilities under construction to be placed in rate base before completion.  Our projected earnings and growth could be adversely affected were FERC to reduce these incentives in the future below the level presently anticipated.

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Increases in electric and gas prices and focus on conservation and self-generation by customers and changes in legislative and regulatory policy may adversely impact our business.

The nation's economy has been affected by the recent significant increases in energy prices, particularly fossil fuels.  The impact of these increases has led to increased electricity and natural gas prices for our customers, which has increased the focus on conservation, energy efficiency and self-generation on the part of customers and on legislative and regulatory policies.  This focus on conservation, energy efficiency and self-generation may result in a decline in electricity and gas sales in our service territories and may result in further declines.  Suchterritories.  If any such declines were to occur without an adjustmentcorresponding adjustments in rates, would reducethen our revenues would be reduced and limitour future growth prospects.  prospects would be limited.

In addition, Connecticut, New Hampshire and Massachusetts have each announced policies aimed at increased energy efficiency and conservation.  In connection with such policies, all three states have opened proceedings to investigate revenue decoupling as a mechanism to align the interests of customers and utilities relative to conservation.  In Connecticut, the DPUC authorized decoupling via a rate design that is intended to recover  proportionately greater distribution revenue through the fixed Customer and Demand charges, and proportionately less distribution revenue through the per kWh charges.  At this time it is uncertain what mechanisms will ultimately be adopted by New Hampshire and Massachusetts and what impact these decoupling mechanisms will have on our companies.

Changes in Regulatory Policy May Adversely Affect Our Transmission Franchise Rightsregulatory policy may adversely affect our transmission franchise rights or Facilitate Competitionfacilitate competition for Constructionconstruction of Large-Scale Transmission Projects, Which Could Adversely Affect Our Earningslarge-scale transmission projects, which could adversely affect our earnings.

Primarily through our subsidiary CL&P, weWe have undertaken a substantial transmission capital investment program and expect to invest approximately $2.5$3 billion in regulated electric transmission infrastructure from 20072008 through 2011.2012.

Although our public utility subsidiaries have exclusive franchise rights for transmission facilities in our service area, the demand for improved transmission reliability could result in changes in federal or state regulatory or legislative policy that could cause us to lose the exclusivity of our franchises or allow other companies to compete with us for transmission construction opportunities.  Such a change in policy could result in reduced transmission capital investments, reduce earnings, and limit future growth prospects.

Changes in Regulatory regulatory and/or Legislative Policy Could Jeopardize Our Full Recovery of Costs Incurred By Our Distribution Companies

Under state law, our utility companies are entitled to charge rates that are sufficient to allow them an opportunity to recover their reasonable operation and capital costs, to attract needed capital and maintain their financial integrity, while also protecting relevant public interests.  Each of these companies prepares and submits periodic rate filings with their respective state regulatory commissions for review and approval.  There is no assurance that these state commissions will approve the recovery of all costs prudently incurred by the utility companies, such as for operation and maintenance, construction, as well as a return on investment on their respective regulated assets.  Increases in these costs, coupled with increases in fuel and energy priceslegislative policy could lead to consumer or regulatory resistance to the timely recovery of such prudently incurred costs, thereby adversely affecting our business and results of operations.

In addition, CL&P and WMECO procure energy for a substantial portion of their customers via requests for proposal on an annual, semi-annual or quarterly basis.  CL&P and WMECO receive approvals of recovery of these contract prices from the DPUC and DTE, respectively.  While both regulators have consistently approved solicitation processes, results and recovery of costs, management cannot predict the outcome of future solicitation efforts or the regulatory proceedings related thereto.  

The energy requirements for PSNH are currently met primarily through PSNH's generation resources or fixed-price forward purchase contracts.  The remaining energy needs are met through spot market or bilateral energy purchases.  Unplanned forced outages of its generating plants could increase the level of energy purchases needed by PSNH and therefore increase the market risk associated with

procuring the necessary amount of energy to meet requirements.  PSNH recovers these costs through its SCRC, subject to a prudence review by the NHPUC.  Management cannot predict the outcome of future regulatory proceedings related to recovery of these costs.  

Changes In Regulatory And/Or Legislative Policy Could Negatively Impact Regional Transmission Cost Allocation Rules.negatively impact regional transmission cost allocation rules.

The existing New England Transmission tariff allocates the costs of transmission investment that provide regional benefits to all customers in New England.  As new investment in regional transmission infrastructure occurs in any one state, there is a sharing of these regional costs across all of New England.  This regional cost allocation is contractually agreed to remain in place until 2010 by the Transmission Operations Agreement signed by all of the New England transmission owning utilities but can be changed with the approval of a majority of the transmission owning utilities thereafter.  PostAfter 2010, certain changes to the terms of the Transmission Operations Agreement could have adverse effects on our distribution companies' local rates.  Management isWe are working to retain the existing regional cost allocation treatment but cannot predict the actions of the states or utilities in the region.

The LossChanges in regulatory or legislative policy could jeopardize our full recovery of Key Personnelcosts incurred by our distribution companies.

Under state law, our utility companies are entitled to charge rates that are sufficient to allow them an opportunity to recover their reasonable operating and capital costs, to attract needed capital and maintain their financial integrity, while also protecting relevant public interests.  Each of these companies prepares and submits periodic rate filings with their respective state regulatory commissions for review and approval.  There is no assurance that these state commissions will approve the recovery of all costs prudently incurred by our regulated companies, such as for operation and maintenance, construction, as well as a return on investment on their respective regulated assets.  Increases in these costs, coupled with increases in fuel and energy prices could lead to consumer or regulatory resistance to the timely recovery of such prudently incurred costs, thereby adversely affecting our cash flows and results of operations.

In addition, CL&P and WMECO procure energy for a substantial portion of their customers via requests for proposal on an annual, semi-annual or quarterly basis.  CL&P and WMECO receive approvals of recovery of these contract prices from the DPUC and DPU, respectively.  While both regulatory agencies have consistently approved solicitation processes, results and recovery of costs, management cannot predict the outcome of future solicitation efforts or the Inabilityregulatory proceedings related thereto.  

The energy requirements for PSNH are currently met primarily through PSNH's generation resources or fixed-price forward purchase contracts.  PSNH’s remaining energy needs are met primarily through spot market or bilateral energy purchases.  Unplanned forced outages of its generating plants could increase the level of energy purchases needed by PSNH and therefore increase the market risk associated with procuring the necessary amount of energy to Hiremeet requirements.  PSNH recovers these costs through its ES rate, subject to a prudence review by the NHPUC.  We cannot predict the outcome of future regulatory proceedings related to recovery of these costs.  

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The loss of key personnel or the inability to hire and Retain Qualified Employees Could Haveretain qualified employees could have an Adverse Effectadverse effect on our Business, Financial Conditionbusiness, financial condition and Resultsresults of Operations.operations.

Our operations depend on the continued efforts of our employees.  Retaining key employees and maintaining the ability to attract new employees are important to both our operational and financial performance.  We cannot guarantee that any member of our management or any key employee at the NU parent or subsidiary level will continue to serve in any capacity for any particular period of time.  In addition, a significant portion of our workforce, including many workers with specialized skills maintaining and servicing the electrical infrastructure, will be eligible to retire over the next five to ten years.  Such highly skilled individuals cannot be quickly replaced due to the technically complex work they perform.  We are developing strategic workforce plans to identify key functions and proactively implement plans to assure a ready and qualified workforce.workforce, but cannot predict the impact of these plans on our ability to hire and retain key employees.

Grid Disturbances, Severe Weather,disturbances, severe weather, or Actsacts of Warwar or Terrorism Could Negatively Impactterrorism could negatively impact our Business.business.

Because our generation and transmission systems are part of an interconnected regional grid, we face the risk of possible loss of business continuity due to a disruption or black-out caused by an event (severe storm, generator or transmission facility outage, or terrorist action) on an interconnected system or the actions of another utility.  In addition, we are subject to the risk that acts of war or terrorism could negatively impact the operation of our system.  Any such disruption could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material adverse impact on our financial condition and results of operations.

Severe weather, such as ice and snow storms, hurricanes and other natural disasters, may cause outages and property damage which may require us to incur additional costs that are generally not insured and that may not be recoverable from customers.  The cost of repairing damage to our operating subsidiaries' facilities and the potential disruption of their operations due to storms, natural disasters or other catastrophic events could be substantial.  The effect of the failure of our facilities to operate as planned would be particularly burdensome during a peak demand period, such as during the hot summer months.  

ChangesA negative change in Regulatory or Legislative Policy May Delay Completion of Our Transmission Projects or Adversely Affect Our AbilityNU's credit ratings could require NU parent to Recover Our Investments or Result in Lower than Expected Rates of Return

The successful implementation of our transmission construction plans is subject to the risk that new legislation, regulations or judicial or regulatory interpretations of applicable law or regulations could impact our ability to meet our construction schedule and/or require us to incur additional expenses,post cash collateral and may adversely affect our ability to achieve forecast levels of revenues.obtain financing.

The regulatory approval process for our planned transmission projects encompasses an extensive permitting, design and technical approval process.  Various factors could result in increased cost estimates and delayed construction.  Recoverability of all such investments in rates may be subject to prudence review at the FERC at the time such projects are placed in service.  While we believe that all such expenses have been and will be prudently incurred, we cannot predict the outcome of future reviews should they occur.

The currently planned transmission projects are expected to help alleviate identified reliability issues in southwest Connecticut and to help reduce customers' costs in all of Connecticut.  However, if, due to further regulatory or other delays, the projected in-service date for one or more of these projects is delayed, there may be increased risk of failures in the existing electricity transmission system in southwestern Connecticut and supply interruptions or blackouts may occur which could have an adverse effect on our earnings.  

FERC has followed a policy of providing incentives designed to encourage the construction of new transmission facilities, including higher returns on equity and allowing facilities under construction to be placed in rate base before completion.  Our projected earnings and growth could be adversely affected were FERC to reduce these incentives in the future below the level presently anticipated.

A Negative Change In NU's Credit Ratings Could Require NU To Post Cash Collateral And Affect our Ability To Obtain Financing

NU'sparent’s senior unsecured debt ratings by Moody's Investors Service, Standard & Poor's, Inc. and Fitch Ratings are currently Baa2, BBB- and BBB, respectively, with stable outlooks.  Were any of these ratings to decline to non-investment grade level, Select Energy could be asked to provide, as of December 31, 2006, approximately $136.8 million of2007, collateral or letters of credit in the amount of $70.4 million to unaffiliated counterparties and $52.4collateral or letters of credit in the amount of $23.4 million to several independent system operators and unaffiliated local distribution companies (LDCs) under agreements largely guaranteed by NU.NU parent.  While NU'sour credit facilities are sufficient in amounts that would be adequate to meet cash calls at that level, our ability to meet any future cash calls would depend on our liquidity and access to bank lines and the capital markets at such time.

We expect to obtain the liquidity needed for our capital programs through bank borrowings, and the issuance of long-term debt at the subsidiary level and debt and equity financing at the NU parent level.  While we are reasonably confident these funds will be available on a timely basis and on reasonable terms, failure to obtain such financing could constrain our ability to finance regulated capital projects.  In addition, any ratings downgrade of our securities or those of our subsidiaries, or any negative impacts on the credit market, generally, could negatively impact the cost or availability of capital.

Changes in Forecasted Wholesale Electric Sales Could Requirewholesale electric sales could require Select Energy to Acquireacquire or Sell Additional Electricitysell additional electricity on Unfavorable Termsunfavorable terms.

Select Energy's remaining wholesale sales contracts are to provide electricity to full requirements customers, who are primarilyincluding a regulated LDCsLDC and a municipal electric companies.  Under the terms of its remaining requirements contracts,company.  Select Energy is required to provideprovides a portion of the customer's electricity requirements at all times.requirements.  The volumes sold under these contracts vary based on the usage of the underlying retail electric customers, and usage is dependent upon factors outside of Select Energy's control, such as unanticipated migration or inflow of customers,economic activity and weather.  As a result, theThe varying sales volumes could be different thanmay differ from the supply volumes that Select Energy expected to utilize from electricity purchase contracts acquired to serve the requirements contracts.  Differences between actual sales volumes and supply volumes couldmay require Select Energy to purchase additional electricity or sell excess electricity, both of which are subject to market cond itionsconditions which change due to weather, plant availability, transmission congestion, and input fuel costs.  The purchase of additional electricity at high prices or sale of excessexc ess electricity at low prices cancould negatively impact Select Energy's cost to serve its remaining wholesale sales customers.the contracts.

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We Are Subject To Litigation Which Could Result In Large Cash Judgmentsare subject to litigation which could result in large cash judgments against usus.

We are engaged in litigation that could result in the imposition of large cash judgments against us.  This litigation includes a civil lawsuit between us and Consolidated Edison, Inc. (Con Edison) and NU relating to the parties'our October 13, 1999 Agreement and Plan of Merger.

We may also be subject to future litigation based on asserted or unasserted claims and cannot predict the outcome of any of these proceedings.  Adverse outcomes in existing or future litigation could result in the imposition of substantial cash damage awards against us.

Further information regarding these legal proceedings, as well as other matters, is set forth in Item 3, "Legal Proceedings."

Costs of Compliancecompliance with Environmental Regulations May Increaseenvironmental regulations may increase and Havehave an Adverse Effectadverse effect on our Businessbusiness and Resultsresults of Operationsoperations.

Our subsidiaries' operations are subject to extensive federal, state and local environmental statutes, rules and regulations which regulate, among other things, air emissions, water discharges and the management of hazardous and solid waste.  In particular, more stringent regulations of carbon dioxide and mercury emissions have been proposed in the various New England states.states in which we operate.  Compliance with these requirements requires us to incur significant costs relating to environmental monitoring, installation of pollution control equipment, emission fees, maintenance and upgrading of facilities, remediation and permitting.  The costs of compliance with theseexisting legal requirements or legal requirements not yet adopted may increase in the future.  An increase in such costs, unless promptly recovered, could have an adverse impact on our business and results of operations, financial position and cash flows.   For further information, see Item 1, "Business - Other Regulatory

In addition, global climate change issues have received an increased focus on the federal and Environmental Matters - Environmental Regulation."state government levels which could potentially lead to additional rules and regulations that impact how we operate our business, both in terms of the power plants we own and operate as well as general utility operations.  Although we would expect that any costs of these rules and regulations would be recovered from ratepayers, the impact of these rules and regulations on energy use by ratepayers and the ultimate impact on our business would be dependent upon the specific rules and regulations adopted and cannot be determined at this time.

Any failure by us to comply with environmental laws and regulations, even if due to factors beyond our control, or reinterpretations of existing requirements, could also increase costs.  Existing environmental laws and regulations may be revised or new laws and regulations seeking to protect the environment may be adopted or become applicable to us.  Revised or additional laws could result in significant additional expense and operating restrictions on our facilities or increased compliance costs which may not be fully recoverable in distribution company rates for regulated generation.  The cost impact of any such legislation would be dependent upon the specific requirements adopted and cannot be determined at this time.  For further information, see Item 1, "Business - Other Regulatory and Environmental Matters - Environmental Regulation."

Item 1B.

Unresolved Staff Comments

NU doesWe do not have any unresolved SEC staff comments.  

Item 2.

Properties

Transmission and Distribution System

At December 31, 2006, the2007, our electric operating subsidiaries of NU owned 196 transmission and 271267 distribution substations that had an aggregate transformer capacity of 27,445,016 kilovoltamperes28,282,150 kilovolt amperes (kVa) and 2,255,7702,253,520 kVa, respectively; 3,091 circuit miles of overhead transmission lines ranging from 69 kilovolt (KV)KV to 345 KV, and 242 cable miles of underground transmission lines ranging from 69 KV to 345 KV; 34,63734,760 pole miles of overhead and 2,7262,817 conduit bank miles of underground distribution lines; and 464,898532,416 underground and overhead line transformers in service with an aggregate capacity of 21,202,61735,810,412 kVa.

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Electric Generating Plants

As of December 31, 2006,2007, PSNH owned the following electric generating plants:  

*Claimed capability represents winter ratings as of December 31, 2006.2007.  The nameplate capacity of the generating plants is approximately 1,200 MW.

Neither CL&P nor WMECO owned any electric generating plants during 2006.2007.

Yankee Gas

At December 31, 2007, Yankee Gas owned 27 gate stations, approximately 270 district regulator stations and 3,200 miles of main gas pipelines.  Yankee Gas also owns a 1.2 Bcf LNG facility in Waterbury, Connecticut as well as propane facilities in Danbury, Kensington and Vernon, Connecticut.

Franchises

CL&P -&P.  Subject to the power of alteration, amendment or repeal by the General Assembly of Connecticut and subject to certain approvals, permits and consents of public authority and others prescribed by statute, CL&P has, subject to certain exceptions not deemed material, valid franchises free from burdensome restrictions to provide electric transmission and distribution services in the respective areas in which it is now supplying such service.

In addition to the right to provide electric transmission and distribution services as set forth above, the franchises of CL&P include, among others, limited rights and powers, as set forth in Title 16 of the Connecticut General Statutes and the special acts of the General Assembly constituting its charter, to manufacture, generate, purchase and/or sell electricity at retail, including to provide standard service, supplierStandard Service, Supplier of last resortLast Resort service and backup service, to sell electricity at wholesale and to erect and maintain certain facilities on public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law. The franchises of CL&P include the power of eminent domain.  Title 16 of the Connecticut General Statutes was amended by Public Act 03-135, "An Act Concerning Revisions to the Electric Restructuring Legislation," to prohibit an electric distribution company from owning or operating generation ass ets.assets.  However, Public Act 05-01, "An Act Concerning Energy Independence," allows CL&P to own up to 200 MW of peaking facilities if the DPUC determines that such facilities will be more cost effective than other options for mitigating FMCCs and LICAP costs.  In addition, Section 83 of Public Act 07-242, "An Act Concerning Electricity and Energy Efficiency" states that if an existing electric generating plant located in Connecticut is offered for sale, then an electric distribution company, such as CL&P, has divested all of itswould be eligible to purchase the generation assetsplant upon obtaining prior approval from the DPUC and a determination by the DPUC that such purchase is now acting as a transmission and distribution company.in the public interest.  

PSNH -PSNH.  The NHPUC, pursuant to statutory requirement,requirements, has issued orders granting PSNH exclusive franchises to distribute electricity in the respective areas in which it is now supplying such service.  

In addition to the right to distribute electricity as set forth above, the franchises of PSNH include, among others, rights and powers to manufacture, generate, purchase, and transmit electricity, to sell electricity at wholesale to other utility companies and municipalities and to erect and maintain certain facilities on certain public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law.  The distribution and transmission franchises of PSNH include the power of eminent domain.  

WMECO -23

WMECO.  WMECO is authorized by its charter to conduct its electric business in the territories served by it, and has locations in the public highways for transmission and distribution lines.  Such locations are granted pursuant to the laws of Massachusetts by the Department of Public Works of Massachusetts or local municipal authorities and are of unlimited duration, but the rights thereby granted are not vested.  Such locations are for specific lines only and for extensions of lines in public highways, furtherhighways.  Further similar locations must be obtained from the Department of Public Works of Massachusetts or the local municipal authorities.  In addition, WMECO has been granted easements for its lines in the Massachusetts Turnpike by the Massachusetts Turnpike Authority and pursuant to state laws, has the power of eminent domain.  

The Massachusetts restructuring legislation defines service territories as those territories actually served on July 1, 1997 and following municipal boundaries to the extent possible.  The restructuring legislation further provides that until terminated by law or otherwise, distribution companies shall have the exclusive obligation to serve all retail customers within their service territories and no other person shall provide distribution service within such service territories without the written consent of such distribution companies. Pursuant to the Massachusetts restructuring legislation, the DTEDPU (then, the Department of Telecommunications and Energy) was required to define service territories for each distribution company, including WMECO.  The DTEDepartment of Telecommunications and Energy subsequently determined that there were advantages to the exclusivity of service territories and issued a report to the Massachusetts Legislature recommending against, in thist his regard, any changes to the restructuring legislation.

HWPHolyoke Water and Power Company and Holyoke Power and Electric Company (HP&E) -Company.  HWP, and its wholly owned subsidiary HP&E, are authorized by their charters to conduct their businesses in the territories served by them.  HWP's electric business is subject to the restriction that sales be made by written contract in amounts of not less than 100 horsepower to purchasers who use the electricity in their own business in the counties of Hampden or Hampshire, Massachusetts and cities and towns in these counties, and customers who occupy property in which HWP has a financial interest, by ownership or purchase money mortgage.  In connection with the sale of certain of HWP's and HP&E's assets to the city of Holyoke Gas and Electric Department (HG&E) effective December 2001, HWP agreed not to distribute electricity at retail in Holyoke and surrounding towns unless other sellers can legally compete with HG&E, and to amend the charters of HWP &and HP&E to reflect that limitation.  

The two companies have locations in the public highways for their transmission and distribution lines.  Such locations are granted pursuant to the laws of Massachusetts by the Massachusetts Department of Public Works of Massachusetts or by local municipal authorities and are of unlimited duration, but the rights thereby granted are not vested.  Such locations are for specific lines only and, for extensions of lines in public highways, further similar locations must be obtained from the Department of Public Works of Massachusetts or the local municipal authorities. HP&E has no retail service territory area and sells electric power exclusively at wholesale.

Yankee Gas -Gas.  Yankee Gas directly and from its predecessors in interest holds valid franchises to sell gas in the areas in which Yankee Gas supplies gas service.  Generally, Yankee Gas holds franchises to serve customers in areas designated by those franchises as well as in most other areas throughout Connecticut so long as those areas are not occupied and served by another gas utility under a valid franchise of its own or are not subject to an exclusive franchise of another gas utility.  Yankee Gas'Gas’s franchises are perpetual but remain subject to the power of alteration, amendment or repeal by the General Assembly of the State of Connecticut, the power of revocation by the DPUC and certain approvals, permits and consents of public authorities and others prescribed by statute.  Generally, Yankee Gas'Gas’s franchises include, among other rights and powers, the right and power to manufacture, generate, purchase, transmit and distribute gas and to erect and maintain certain facilit iesfacilities on public highways and grounds;grounds, and the right of eminent domain, all subject to such consents and approvals of public authorities and others as may be required by law.

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Item 3.

Legal Proceedings

1.

Consolidated Edison, Inc. v. NU - Merger Litigation

On March 5, 2001, Con Edison advised NUus that it was unwilling to close its merger with NUus on the terms set forth in the parties'our 1999 merger agreement (the Merger Agreement).  On March 6, 2001, Con Edison filed suit in federal court in New York City seeking a declaratory judgment that we had suffered a material adverse change, as defined in the Merger Agreement, and that Con Edison was therefore excused from performing its obligations under the merger agreement.  On March 12, 2001, NUwe filed suit against Con Edison seeking damages in excessto recover the merger premium, which totaled over $1 billion, for the benefit of $1 billion.

our shareholders.  On May 11, 2001, Con Edison filed an amended complaint seeking, in addition to the relief in its original complaint, an award of money damages of at least $314 million to compensate it for breachwhat it claims is the portion of contract, fraudulent inducementthe projected synergy savings that would have inured to the benefit of former Con Edison shareholders if the merger had been consum mated and negligent misrepresentation.the estimated savings had been realized.  Con Edison also sought to recover its merger related expenses, which it claims were approximately $32 million.

On October 12, 2005, the United StateStates Court of Appeals for the Second Circuit issued a decision concluding that NUour shareholders had nodid not have the right to sue Con Edison for the merger premium as a result of its alleged breach of the Merger Agreement.  As a result, the Second Circuit did not reach the second issue presented for review which was whether the right to pursue recovery of the $1 billion merger premium belongs to NU shareholders who held shares at the time of the breach or those who hold shares if and when a judgment is rendered against Con Edison.  NU filed for rehearing and suggested an en banc review on October 26, 2005.  By order dated January 3, 2006, NU's request for rehearing was denied. The ruling leavesleft intact the remaining claims between NUus and Con Edison for breach of contract, which include NU'sour claim for recovery

of costs and expenses of approximately $32$27 million, and Con Edison's claim for "at least $314 million" in damages.  NU opted not to seek reviewits alleged synergy damages plus expenses of this ruling by$32 million.  Any award of damages would also include prejudgment interest on the United States Supreme Court.amount of damages awarded from the date of the filing of the claim.

On April 7, 2006, NU filed itsJanuary 31, 2008, the trial judge denied a series of motions by both us and Con Edison that had been pending for more than one year, including our motion for partial summary judgment onan order dismissing Con Edison's synergy damage claim.  NU's motion asserts that NU is entitledclaim and ordered the parties to judgment in its favor with respect to this claim basedbe trial ready on the undisputed material facts and applicable law.  The matter is fully briefed and awaiting a decision.  four days' notice beginning March 21, 2008.

It is not possible to predict either the outcome of this matter or its ultimate effect on NU.us.

2.

Constellation Power Source, Inc. (Constellation) v. Select Energy, Inc.

This case involves a dispute between Select Energy and Constellation over responsibility for socialized congestion charges imposed by ISO-NE prior to the implementation of Standard Market Design (SMD) on March 1, 2003, and responsibility for congestion charges and losses following implementation of SMD.  Constellation filed a complaint in the U.S. District Court for the District of Connecticut against Select Energy claiming that Select Energy was responsible for pre- and post-SMD congestion and losses amounting to approximately $9.7 million.  Select Energy filed a counterclaim seeking to recover the $2.5 million in pre-SMD charges that Constellation had refused to pay.

The case was tried to the Court in August 2006.  On November 14, 2006, the court issued its Memorandum of Decision and found in favor of Select Energy, with respect to its counterclaim for recovery of pre-SMD congestion and losses.  The court also awarded Constellation its "pro rata share of the LMP Differential that Select Energy received from CL&P in connection with the settlement of the FERC proceeding, plus prejudgment interest as provided in the parties' agreement."  Pursuant to an order of the Court, the parties made their respective damages filings with the Court on December 13, 2006.  On January 23, 2007, the Court issued its final decision and order addressing the issue of damages.  The net effect of the Court's ruling is that Select Energy will have to pay Constellation approximately $1.7 million as of the date entered, with interest accruing at a net rate of approximately $500 per day until the judgment is paid.  The parties have re ached a settlement pursuant to which Select Energy agreed to pay Constellation $2 million, thereby ending the litigation.

3.

NRG Bankruptcy

On May 14, 2003, NRG and certain of its affiliates filed for Chapter 11 protection in the United States Bankruptcy Court for the Southern District of New York (Bankruptcy Court).  The filing affects relationships between various NU companies and the NRG companies, as follows:

A. Station Service

NRG has disputed its responsibility to pay for the provision of station service by CL&P to NRG's Connecticut generating plants (approximately $26$28 million, including late charges).  The FERC issued a decision on December 20, 2002 that NRG had agreed that station service from CL&P would be subject to CL&P's applicable retail rates, and that states (i.e., the DPUC) have jurisdiction over the delivery of power to end users even where power is not delivered via distribution facilities.  NRG refused CL&P's subsequent demand for payment, and on April 3, 2003, CL&P petitioned the DPUC for a declaratory order enforcing the FERC's December 20, 2002 decision.  Prior to the issuance of a decision by the DPUC, NRG filed a petition under Chapter 11 of the U.S. Bankruptcy Code, staying any further action by the DPUC.

On September 18, 2003, the Bankruptcy Court approved the parties' stipulation to submit the station service issue to arbitration for a determination of liability and damages which will fix CL&P's claim in bankruptcy.  The parties are currently pursuing arbitration of the issues in dispute with hearing dates scheduled for the fall of 2007.  On December 17, 2003, the DPUC issued a decision in CL&P's rate case that addressed the issue that CL&P had first raised to the DPUC in its April 3, 2003 filing.  The DPUC affirmatively stated that CL&P hashad been appropriately administering its station service rates. Subsequently, however, in unrelated proceedings,On January 8, 2008, CL&P and NRG filed a confidential proposed settlement with the FERCDPUC, which would settle the competing claims.  On January 28, 2008, the DPUC issued a series of orders with conflicting policy direction,final decision in CL&P’s rate case proceeding in which call into question its December 20, 2002it also approved the confidential settlement between CL&P and NRG.  CL&P and NRG order (See Dominion Nuclear litigation below).signed the settlement agreement, which did not, and is not expected to, have a material adverse effect on CL&P, in February 2008.  

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B. Yankee Gas

On October 9, 2002, NRG informed Yankee Gas that its affiliate, Meriden Gas Turbines, LLC (MGT), was permanently shutting down or abandoning its Meriden power plant project, and requested that Yankee Gas cease its construction activities and begin an orderly wind down of its work relating to the project.  Based on NRG's statement that it expected that Yankee Gas would draw on a $16 million letter of credit (LOC), Yankee Gas drew down the full amount of the LOC.  On November 12, 2002, MGT filed suit against Yankee Gas in Meriden Superior Court, claiming that Yankee Gas breached the agreement with MGT (MGT Agreement), and seeking a declaratory ruling from the court that Yankee Gas wrongfully drew down the $16 million LOC.  In April 2003, Yankee Gas filed its answer to MGT's complaint and asserted a counterclaim to recover its losses arising out of MGT's termination of the MGT Agreement. The parties

subsequently reached a settlement in principle of their claims; however, MGT has since requested the court to place the case back on the trial calendar.  Yankee Gas filedand NRG signed a motionconfidential settlement agreement which settle d the competing claims in February 2008.  The settlement did not, and is not expected to enforce the settlement and the parties are again engaged in court-ordered settlement discussions.  No trial date is currently scheduledhave a material adverse effect on Yankee Gas.  

C. Congestion Charges

On August 5, 2002, CL&P withheld the past due congestion charges from its payment to NRG pursuant to contractual provisions allowing the withholding of disputed sums.  CL&P continued to withhold congestion charges from its monthly payments to NRG, through March 1, 2003, and at present is withholding approximately $28 million.  On November 28, 2001, CL&P filed a complaint against NRG in Connecticut Superior Court alleging breach of contract arising from the failure of NRG to pay approximately $29.6 million of socialized congestion charges.  The case was removed to U.S. District Court for the District of Connecticut.  NRG filed a counterclaim seeking recovery of all amounts CL&P has withheld.  Discovery is complete andThe court granted CL&P's motion for summary judgment is pending.  No trial date is currently scheduled.and entered judgment in CL&P’s favor on all counts on July 25, 2007.

4.

CYAPC/FERC Proceeding

On July 1, 2004, CYAPC filed with the FERC to increase its decommissioning collections from $16.7 million per year (in 2000 dollars) to $93 million per year (in 2003 dollars) for the six-year period beginning January 1, 2005.  The 2003 estimate projects an increase of $395.6 million in 2003 dollars and a total cost to complete decommissioning of $831.3 million in 2003 dollars.  

On August 30, 2004, the FERC issued an order accepting the CYAPC rate filing, suspending collections for five months and establishing hearing procedures.

The FERC administrative law judge conducted hearings on the reasonableness of the decommissioning rates in the spring of 2005.  The DPUC argued that CYAPC's actions were imprudent and recommended a disallowance in the range of approximately $225 to $234 million.  The FERC trial staff argued that CYAPC should have used a lower gross domestic product (GDP) escalation rate in calculating the level of decommissioning charges and that use of such rate would reduce charges by $36 million.  In post trial briefs, the FERC trial staff also claimed that CYAPC's actions were imprudent and increases in decommissioning charges should be disallowed.

In an initial decision rendered on November 22, 2005, the FERC trial judge found no imprudence on CYAPC's part, and thus there was no basis for a rate disallowance.  However, the trial judge agreed with the FERC trial staff's lower GDP escalator for calculating the decommissioning rate increase.

On November 16, 2006, FERC approved a settlement among CYAPC, the DPUC, the OCC, the Maine Public Utilities Commission and the Maine Public Advocate that disposes of the pending decommissioning litigation at FERC and at the D.C. Circuit.  The settlement also resolves the dispute over the incentive mechanism contained in the 2000 settlement between the parties, the disposition of the net proceeds from CY's settlement with Bechtel, CY's recovery of the costs of completing decommissioning, and CY's payment of dividends and return of equity capital to its shareholders.

Under the terms of the settlement, the parties have agreed to a revised decommissioning estimate of $642.9 million (in 2006 dollars), taking into account actual spending through 2005 and the current estimate for completing decommissioning and long-term storage of spent fuel, a GDP escalator of 2.5% for costs incurred post 2006, and a 10% contingency factor for all decommissioning costs.

NU's electric operating subsidiaries collectively own 49.0 % of CYAPC, as follows: CL&P - 34.5 %, PSNH - 5.0 %and WMECO - 9.5%.

5.

YAEC– Decommissioning

On November 23, 2005, YAEC filed a request with FERC to revise the level of its decommissioning collections, based on an increased cost estimate.  A 2003 settlement had provided for annual charges of $55.6 million through 2005 and $14 million from 2006 through 2010, with certain adjustments.  YAEC's proposal is to increase 2006 collections to $54.9 million and increase 2007 through 2010 collections to $23.5 million.  YAEC has asked FERC for an effective date of February 1, 2006.  On January 31, 2006, FERC accepted the rate increase with a February 1, 2006 effective date, subject to refund, and set the case for settlement proceedings.

On May 1, 2006, YAEC filed with FERC a proposed settlement with the Connecticut DPUC, the Massachusetts Attorney General and the Vermont Department of Public Service.  The settlement reduces decommissioning charges to YAEC's wholesale utility customers by, among other items, revising the decommissioning estimate, including contingency and projected escalation, extending the collection period for charges through December 2014, reduces certain expenses, reconciling certain decontamination and dismantlement expenses, and adjusting charges based on the decommissioning trust fund's actual investment earnings.  The settlement proposes a new estimate of decommissioning charges of $212.6 million, reflecting a $28.2 million reduction compared to the 2005 decommissioning cost of estimate.

The settlement became effective upon FERC's approval in December, 2006, but did not affect the level of 2006 charges.  Charges from 2007 through 2014 will drop to approximately $11.7 million per year, subject to certain adjustments.

NU's electric operating subsidiaries collectively own 38.5 % of YAEC, as follows: CL&P - 24.5%, PSNH - 7.0 % and WMECO – 7.0%.

6.3.

Yankee Companies v. U.S. Department of Energy

A. Spent Nuclear Fuel Litigation

YAEC, MYAPC, and CYAPCThe Yankee Companies commenced litigation in 1998 against the DOEUnited States Department of Energy (DOE) charging that the federal government breached contracts it entered into with each company in 1983 under the Nuclear Waste Policy Act of 1982 to begin removing spent nuclear fuel from the respective nuclear plants no later than January 31, 1998 in return for payments by each company into the Nuclear Waste Fund.  The funds for those payments were collected from regional electric customers.  The Yankee Companies initially claimed damages for incremental spent nuclear fuel storage, security, construction and other costs through 2010.

In a ruling released on October 4, 2006, the Court of Federal Claims held that the DOE was liable for damages to CYAPC for $34.2 million through 2001, YAEC for $32.9 million through 2001 and MYAPC for $75.8 million through 2002.  The Yankee Companies had claimed actual damages for the same period as follows: CYAPC: $37.7 million; YAEC: $60.8 million; and MYAPC: $78.1 million.  The refund to CL&P, PSNH and WMECO of any damages that may be recovered from the DOE is established in the Yankee Companies' FERC-approved rate settlement agreement, although implementation will be subject to final determination of FERC. CL&P, PSNH and WMECO expect to pass any recovery onto itstheir customers, therefore, no earnings areimpact is expected to result.

The Court of Federal Claims, following precedent set in another case, did not award  In December 2006, the Yankee Companies future damages covering the period beyond the 2001/2002 damages award dates.  The Yankee Companies believe they will have the opportunity in future lawsuits to seek recovery of actual damages incurred in the years following 2001/2002.  The DOE appealed the decision, and the Yankee Companies filed cross-appeals. The appeal is expected to be argued in 2008 with a decision from the Court of Appeals to follow.  The application of any damages which are ultimately recovered to benefit customers is established in the Yankee Companies' FERC-approved rate settlement agreements, although implementation will be subject to the final determination of the FERC.

B. Uranium Enrichment Litigation

In 2001, Northeast Utilities Service Company (NUSCO) asserted claims against the DOE in theThe Court of Federal Claims, for overcharges for purchasesfollowing precedent set in another case, did not award the Yankee Companies future damages covering the period beyond the 2001/2002 damages award dates.  In December 2007, the Yankee Companies filed a second round of uranium enrichment separative work units (SWUs) for CYAPC's nuclear unit andlawsuits against the nuclear units located at Millstone Power StationDOE seeking recovery of actual damages incurred in Waterford, Connecticut between 1986 and 1993 (D&D Claims).  The NUSCO case was stayed by the Court of Federal Claims while other D&D Claims cases were being litigated.  Beginning in 2005, NUSCO joined a number of other utilities in a consortium in an attempt to negotiate a settlement agreement with the DOE.  In late-2006, a settlement was reached between the consortium and the DOE.  The distribution of proceeds under the settlement agreement totals approximately $0.8 million for CYAPC and approximately $1.4 million related to the Millstone units.  This distribution is based on the total number of SWUs purchased for CYAPC's unit and the Millstone units during the applicable peri od covered by the litigation.  We believe it is likely that the net proceeds from the settlement will be credited to ratepayers.  CL&P, PSNH and WMECO collectively own 49% of CYAPC.  Prior to March 31, 2001, CL&P, PSNH and WMECO collectively owned 100% of Millstone 1 and 2 and 68.02 % of Millstone 3.years following 2001/2002.  

7.

Enron Bankruptcy Claim

CL&P filed a proof of claim in the sum of $42.9 million against Enron Power Marketing, Inc. (EPMI) in the U. S. Bankruptcy Court for the Southern District of New York.  The claim is for damages resulting from the rejection of the December 22, 2000 electricity purchase agreement between EPMI and CL&P, which was related to an agreement the Connecticut Resource Recovery Authority had entered into with Enron.  EPMI, through the Enron bankruptcy estate, objected to the CL&P claim, CL&P filed a response, and litigation ensued in the bankruptcy court.  CL&P and Enron have now agreed to settle the matter by agreeing that the CL&P's claim will have a face value of $19.75 million.  CL&P cannot estimate what percentage of the claim will be paid once the agreement is approved, but the proceeds from the liquidation of the claim will be credited to ratepayers.  The settlement requires DPUC and bankruptcy court approval and the parties anticipate th at a motion to approve the settlement will be filed in the second quarter of 2007.

8.4.

Connecticut MGP Cost Recovery

On August 5, 2004, Yankee Gas and CL&P (NU Companies) demanded contribution from UGI Utilities, Inc. (UGI) of Pennsylvania for past and future remediation costs related to historic MGP operations on thirteen sites currently or formerly owned by the NU Companies (Yankee Gas is responsible for ten of the sites, CL&P for two of the sites, and both companies share responsibility for one site) in a number of different locations throughout the State of Connecticut.  The NU Companies alleged that UGI controlled operations of the

plants at various times throughout the period 1883 to 1941, when UGI was forced to divest its interests.  Investigations and remediation costsexpenditures at the sites to date total over $20 million, against reserves, and projected potential remediation costs for all sites--basedsites, based on litigation modeling assumptions--couldassumptions, could total as much as $228$232 million.  At this point, we are unable to estimate the potential costs are not estimable and probable from an accounting standpoint.associated with this matter.

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In September 2006, the NU Companies filed a complaint against UGI in the U.S. District Court for the District of Connecticut seeking a fair and equitable contribution for the actual and anticipated remediation costs related to the former MGP operations.  On November 6, UGI answered the complaint, denying the material allegations asserted against it.  The caseDiscovery is now in the discovery phase.scheduled through July 2008.

9.

5.

Dominion Nuclear-Station Service

On July 24, 2006, Dominion Nuclear Connecticut, Inc. (DNCI) filed a complaint at FERC, claiming that, because as of December 1, 2005, DNCI sought to "self-supply" its station service power through the ISO-NE settlement system rather than from CL&P as a Transitional Standard Service retail customer, it is not required to buy retail delivery service for that power.  On August 14, 2006, CL&P answered the complaint, supported by the Connecticut DPUC, OCC and the AG.  

On September 22, 2006, FERC issued an order finding that CL&P is not authorized to impose local distribution charges for station power delivery service on DNCI, and directed CL&P to cease charging DNCI retroactive to December 1, 2005.  Since that date, DNCI has withheld approximately $1.7 million (including interest).  CL&P sought rehearing and clarification on October 23, 2006.  (See "NRG Bankruptcy - Station Service" under entry 3 of this Item 3On May 27, 2007 FERC denied CL&P’s rehearing and clarification request stating that CL&P is not authorized to charge Dominion local distribution charges to deliver station service to Millstone through transmission lines.  On January 28, 2008, the DPUC issued a final decision in CL&P’s rate case proceeding, which essentially reimburses CL&P for a contrasting view taken by the DPUC).its net station service receivable for Dominion.

10.6.

Other Legal Proceedings

The following sections of Item 1, "Business" discuss additional legal proceedings: See "Regulated Electric Distribution," "Regulated Electric Transmission,Gas Operations," and "Regulated Gas Operations"Electric Transmission" for information about various state restructuring and rate proceedings, civil lawsuits related thereto, and information about proceedings relating to power, transmission and pricing issues;  "Status of Nuclear"Nuclear Decommissioning" for information related to high-level nuclear waste; and "Other Regulatory and Environmental Matters" for information about proceedings involving surface water and air quality requirements, toxic substances and hazardous waste, EMF, licensing of hydroelectric projects, and other matters.  In addition, see Item 1A, "Risk Factors" for general information about several significant risks.

EXECUTIVE OFFICERS OFExecutive Officers of the Registrant

This information is provided by NU in reliance on General Instruction G of Form 10-K.

          Name          

Age

Business Experience During Past 5 Years

Gregory B. Butler

4950

Senior Vice President and General Counsel of NU since December 1, 2005 and of CL&P, PSNH and WMECO, subsidiaries of NU, since March 9, 2006, and a Director of Northeast Utilities Foundation, Inc. since December 1, 2002; previously Senior Vice President, Secretary and General Counsel of NU from August 31, 2003 to December 1, 2005; Vice President, Secretary and General Counsel of NU from May 1, 2001 through August 30, 2003.

Lawrence E. De SimonePeter J. Clarke

5946

Retired asVice President of Shared Services of NUSCO, a subsidiary of NU, since January 1, 2007; previously served as President-Competitive Group2008, and performs policy-making functions for NU. Previously Vice President - Customer Operations of NUCL&P and President of NU Enterprises, Inc.,Yankee Gas Services Company from October 25, 2004July 1, 2006 to December 31, 2006 and Chairman, President and Chief Executive Officer of Select Energy, Inc. from February 1, 2005 to December 31, 2006; previously Executive2007; Vice President - Regulated BusinessCustomer Operations and ServicesRelations of PPL CorporationCL&P from January 1, 200417, 2005 to August 31, 2004; Executive Vice PresidentJune 30, 2006; and Director - SupplySystem Projects of PPL CorporationCL&P from October 2001March 11, 2002 to December 31, 2003.January 16, 2005.

Cheryl W. Grisé (*)

5455

Executive Vice President of NU sincefrom December 1, 2005;2005 to July 1, 2007; Chief Executive Officer of CL&P, PSNH and WMECO from September 10, 2002 to January 15, 2007, a Director of CL&P from May 1, 2001 to January 15, 2007, of PSNH from May 14, 2001 to January 15, 2007 and of WMECO from June 2001 to January 15, 2007, and a Director of Northeast Utilities Foundation, Inc. since September 23, 1998;2007; previously President - Utility Group of NU from May 2001 to December 1, 2005.

27

Jean M. LaVecchia

56

Vice President - Human Resources of NUSCO, a subsidiary of NU, since June 30, 2005, and performs policy-making functions for NU; also a Director of Northeast Utilities Foundation since January 30, 2007.  Previously Vice President - Human Resources and Environmental Services from May 1, 2001 to June 30, 2005.  Performs policy-making functions for NU.

David R. McHale

4647

Senior Vice President and Chief Financial Officer of NU, CL&P, PSNH and WMECO since January 1, 2005 and a Director of PSNH and WMECO since January 1, 2005 and CL&P since January 15, 2007;2007 and a Director of Northeast Utilities Foundation since January 1, 2005; previously Vice President and Treasurer of NU, WMECO and PSNH from July 1998 to December 31, 2004.

Leon J. Olivier

5859

Executive Vice President - Operations of NU since February 13, 2007; Chief Executive Officer of CL&P, PSNH and WMECO since January 15, 2007; Director of PSNH and WMECO since January 17, 2005 and a Director of CL&P since September 2001.2001; Previously Executive Vice President of NU from December 1, 2005 to February 13, 2007; President - Transmission Group of NU from January 17, 2005 to December 1, 2005; President and Chief Operating Officer of CL&P from September 2001 to January 2005.

Shirley M. Payne

5556

Vice President - Accounting and Controller of NU since February 13, 2007, and of CL&P, PSNH and WMECO since January 29, 2007.  Previously Vice President, Corporate Accounting and Tax of TECO Energy, Inc. from July 2000 to January 26, 2007 and Tax Officer of Tampa Electric CompanyTECO Energy, Inc. from April 1999 to January 26, 2007.  

James B. Robb

47

Senior Vice President, Enterprise Planning and Development of NUSCO since September 4, 2007, and performs policy-making functions for NU. Previously Managing Director, Russell Reynolds Associates from December 2006 to August 2007; Entrepreneur in Residence, Mohr Davidow Ventures from March 2006 to November 2006; Senior Vice President, Retail Marketing, Reliant Energy, Inc. from December 2003 to December 2006; Senior Vice President, Performance Management,  Reliant Resources, Inc. from November 2002 to December 2003.  

Charles W. Shivery

6162

Chairman of the Board, President and Chief Executive Officer of NU since March 29, 2004; Chairman and a Director of CL&P, PSNH and WMECO since January 19, 2007.2007 and a Director of Northeast Utilities Foundation since March 3, 2004. Previously, President (interim) of NU from January 1, 2004 to March 29, 2004 and a Director of Northeast Utilities Foundation since March 3, 2004; previously President - Competitive Group of NU and President and Chief Executive Officer of NU Enterprises, Inc., from June 2002 through December 2003.  

 (*)

Mrs. Grisé is a DirectorNone of MetLife, Inc. and Dana Corporation.the above Executive Officers serves as an Executive Officer pursuant to any agreement or understanding with any other person.

Item 4.

Submission Of Matters To a Vote of Security Holders

No event that would be described in response to this item occurred with respect to NUus or CL&P.

The information called for by Item 4 is omitted for PSNH and WMECO pursuant to Instruction I (2)(c) to Form 10-K (Omission of Information by Certain Wholly OwnedWholly-Owned Subsidiaries.)

28

Part II

Item 5.

Market for The Registrants' Common Equity and Related Stockholder Matters

NU.  TheOur common shares of NU are listed on the New York Stock Exchange.  The ticker symbol is "NU," although it is frequently presented as "Noeast Util" and/or "NE Util" in various financial publications.  The high and low closing sales prices for the past two years, by quarters, are shown below.

There were no purchases made by or on behalf of NUour company or any "affiliated purchaser" (as defined in Rule 10b-18(a)(3) under the Securities Exchange Act of 1934), of common stock during the fourth quarter of the year ended December 31, 2006.2007.  Information with respect to the performance of NU'sour common shares is contained in the "Share Performance Chart" from the Proxy Statementour 2007 Annual Report to be dated March 20, 2007,Shareholders, which information is incorporated herein by reference.  

As of January 31, 2007,2008, there were 50,84947,891 common shareholders of NUour company on record.  As of the same date, there were a total of 175,453,290175,969,591 common shares issued, including 1,483,5611,110,400 unallocated Employee Stock Ownership Plan (ESOP) shares held in the ESOP trust.

On February 13, 2007, the NU12, 2008, our Board of Trustees approved the paymentdeclared a dividend of 20 cents per share, payable on March 31, 2008, to shareholders of record as of March 1, 2008.  

On November 13, 2007, our Board of Trustees declared a dividend of 20 cents per share, payable on December 31, 2007, to shareholders of record as of December 1, 2007.

On May 7, 2007, our Board of Trustees declared a dividend of 20 cents per share, payable on September 28, 2007, to shareholders of record as of September 1, 2007.

On April 10, 2007, our Board of Trustees declared a dividend of 18.75 centcents per share, payable on June 29, 2007, to shareholders of record on June 1, 2007.

On February 13, 2007, our Board of Trustees declared a dividend of 18.75 cents per share, payable on March 31, 2007, to shareholders of record as of March 1, 2007.  

On November 13, 2006, the NUour Board of Trustees approved the paymentdeclared a dividend of 18.75 centcents per share, dividend, payable on December 30, 2006, to shareholders of record as of December 1, 2006.

On May 9, 2006, the NUour Board of Trustees approved the paymentdeclared a dividend of 18.75 centcents per share, dividend, payable on September 29, 2006, to shareholders of record as of September 1, 2006.

On April 11, 2006, the NUour Board of Trustees approved the paymentdeclared a dividend of 17.5 centcents per share, dividend, payable on June 30, 2006, to shareholders of record on June 1, 2006.

On February 14, 2006, the NUour Board of Trustees approved the paymentdeclared a dividend of 17.5 centcents per share, dividend, payable on March 31, 2006, to shareholders of record as of March 1, 2006.  

On October 11, 2005, the NU Board of Trustees approved the payment of 17.5 cent per share dividend, payable on December 30, 2005 to shareholders of record as of December 1, 2005.

On May 10, 2005, the NU Board of Trustees approved the payment of 17.5 cent per share dividend, payable on September 30, 2005 to shareholders of record as of September 1, 2005.

On April 12, 2005, the NU Board of Trustees approved the payment of 16.25 cent per share dividend, payable on June 30, 2005 to shareholders of record as of June 1, 2005.

On January 31, 2005, the NU Board of Trustees approved the payment of 16.25 cent per share dividend, payable on March 31, 2005 to shareholders of record as of March 1, 2005.

Information with respect to dividend restrictions for NU,us, CL&P, PSNH, and WMECO is contained in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" under the caption "Liquidity" and in the "Notes to Consolidated Financial

29

Statements," within our company’s and each company's 2006respective 2007 Annual ReportReports to Shareholders, which information is incorporated herein by reference.

CL&P, PSNH and WMECO.  There is no established public trading market for the common stock of CL&P, PSNH and WMECO.  The common stock of CL&P, PSNH and WMECO is held solely by NU.

During 20062007 and 2005,2006, CL&P approved and paid $63.7$79.2 million and $53.8$63.7 million, respectively, of common stock dividends to NU.

During 20062007 and 2005,2006, PSNH approved and paid $41.7$30.7 million and $42.4$41.7 million, respectively, of common stock dividends to NU.

During 20062007 and 2005,2006, WMECO approved and paid $7.9$12.8 million and $7.7$7.9 million, respectively, of common stock dividends to NU.

For information regarding securities authorized for issuance under equity compensation plans, see Item 12, "Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters," included in this reportAnnual Report on Form 10-K.  

Item 6.

Selected Financial Data

NU.  Reference is made to information under the heading "Selected Consolidated Financial Data" contained within NU's 2006our 2007 Annual Report to Shareholders, which information is incorporated herein by reference.

CL&P.  Reference is made to information under the heading "Selected Consolidated Financial Data" contained within CL&P's 20062007 Annual Report, which information is incorporated herein by reference.  

PSNH.  Reference is made to information under the heading "Selected Consolidated Financial Data" contained within PSNH's 20062007 Annual Report, which information is incorporated herein by reference.

WMECO.  Reference is made to information under the heading "Selected Consolidated Financial Data" contained within WMECO's 20062007 Annual Report, which information is incorporated herein by reference.

Item 7.

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

NU.  Reference is made to information under the heading "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained within NU's 2006our 2007 Annual Report to Shareholders, which information is incorporated herein by reference.

CL&P.  Reference is made to information under the heading "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained within CL&P's 20062007 Annual Report, which information is incorporated herein by reference.

PSNH.  With respect to PSNH's results of operations, reference is made to information under the heading "Results of Operations" contained within PSNH's 20062007 Annual Report, which information is incorporated herein by reference.  

WMECO.  With respect to WMECO's results of operations, reference is made to information under the heading "Results of Operations" contained within WMECO's 20062007 Annual Report, which information is incorporated herein by reference.  

Item 7A.

Quantitative and Qualitative Disclosures about Market Risk

Market Risk Information

The merchant energy businessSelect Energy utilizes the sensitivity analysis methodology to disclose quantitative information for its commodity price risks (including where applicable capacity and ancillary components).  Sensitivity analysis provides a presentation of the potential loss of future earnings, fair values or cash flows from market risk-sensitive instruments over a selected time period due to one or more hypothetical changes in commodity price components, or other similar price changes.  Under sensitivity analysis, the fair value of the portfolio is a function of the underlying commodity components, contract prices and market prices represented by each derivative contract. For swaps, forward contracts and options, fair value reflects management'sour best estimates considering over-the-counter quotations, time value and volatility factors of the underlying commitments.  Exchange-traded futures and options are recorded at fair value based on closing exchange prices.  As the NU Enterprises'Enterp rises' businesses are exited, the risks associated with commodity prices are expected to be reduced.

NU Enterprises - Wholesale Portfolio:  When conducting sensitivity analyses of the change in the fair value of Select Energy's wholesale portfolio, which includes a non-derivative power purchase contract, which would result from a hypothetical change in the future market

30

price of electricity, the fair values of the contracts are determined from models that take into consideration estimated future market prices of electricity, the volatility of the market prices in each period, as well as the time value factors of the underlying commitments.

A hypothetical change in the fair value of the wholesale portfolio was determined assuming a 10 percent10% change in forward market prices.  At December 31, 2006,2007, Select Energy has calculated the market price resulting from a 10 percent10% change in forward market prices of those contracts.  A 10 percent10% increase in prices for all products would have resulted in a pre-tax increase in fair value of $0.9 million and a 10% decrease in prices for all products would have resulted in a pre-tax decrease in fair value of $1.2 million and a 10 percent decrease in prices for all products would not have resulted in a change in fair value.$1.3 million.  A 10 percent10% increase in energy prices would have resulted in a $9.4$6.8 million pre-tax decrease, and a 10 percent10% decrease in energy prices would have resulted in an $8.2a $6.4 million pre-tax increase.  A 10 percent10% increase/(decrease) in capacity prices would have resulted in a $2.3$2.2 million pre-tax increase/(decrease).  A 10 percent10% increase/(decrease) in ancillary prices would have resulted in a 5.9$5.5 million pre-tax increase/(decrease).  

The impact of a change in electricity and natural gas prices on Select Energy's wholesale transactions at December 31, 20062007 are not necessarily representative of the results that will be realized.  These transactions are accounted for at fair value, and changes in market prices impact earnings.

NU Enterprises - Generation Portfolio:  In conjunction with the sale of the competitive generation business on November 1, 2006, the generation portfolio was divested or otherwise closed out by December 31, 2006.  

Other Risk Management Activities

Interest Rate Risk Management:  NU manages itsWe manage our interest rate risk exposure in accordance with itsour written policies and procedures by maintaining a mix of fixed and variable rate long-term debt.  At December 31, 2006,2007, approximately 89 percent (80 percent including90% (83% if we include the long-term debt subject to the fixed-to-floating interest rate swap ofas variable rate long-term debt) of NU'sour long-term debt, including fees and interest due for spent nuclear fuel disposal costs, is at a fixed interest rate.  The remaining long-term debt is variable-rateat variable interest rates and is subject to interest rate risk that could result in earnings volatility.  Assuming a one percentage point increase in NU'sour variable interest rates, including the rate on long-term debt subject to the fixed-to-floating interest rate swap, annual interest expense would have increased by $3.2$3.7 million.  At December 31, 2006,2007, NU parent maintained a fixed-to-floating interest rate swap to manage the interest rate risk associated with its $263 million of fixed-r atefixed-rate long-term debt.

Credit Risk Management:  Credit risk relates to the risk of loss that NUwe would incur as a result of non-performance by counterparties pursuant to the terms of itsour contractual obligations.  NU servesWe serve a wide variety of customers and suppliers that include IPPs, industrial companies, gas and electric utilities, oil and gas producers, financial institutions, and other energy marketers.  Margin accounts exist within this diverse group, and NU realizeswe realize interest receipts and payments related to balances outstanding in these margin accounts.  This wide customer and supplier mix generates a need for a variety of contractual structures, products and terms which, in turn, requires NUrequire us to manage the portfolio of market risk inherent in those transactions in a manner consistent with the parameters established by NU'sour risk management process.

Credit risks and market risks at NU Enterprises are monitored regularly by a Risk Oversight Council.  The Risk Oversight Council is generally comprised of individuals from outside of the business linesmanagement of these activities that create or actively manage these risk exposures and functions to ensure compliance with NU'sour stated risk management policies.  

NU tracksWe track and re-balancesre-balance the risk in itsour portfolio in accordance with fair value and other risk management methodologies that utilize forward price curves in the energy markets to estimate the size and probability of future potential exposure.

NYMEXThe New York Mercantile Exchange (NYMEX) traded futures and option contracts cleared off the NYMEX exchange are ultimately guaranteed by NYMEX to Select Energy.  Select Energy has established written credit policies with regard to its counterparties to minimize overall credit risk on all types of transactions.  These policies require an evaluation of potential counterparties' financial condition (including credit ratings), collateral requirements under certain circumstances (including cash in advance, LOCs,letters of credit, and parent guarantees), and the use of standardized agreements, which allow for the netting of positive and negative exposures associated with a single counterparty.  This evaluation results in establishing credit limits prior to Select Energy entering into energy contracts.  The appropriateness of these limits is subject to continuing review.  Concentrations among these counterparties may impact Select Energy's overall exposure to credit risk, either positively or negatively, in that the coun terpartiescounterparties may be similarly affected by changes to economic, regulatory or other conditions.

At December 31, 2006, and 2005, Select Energy maintained collateral balances from counterparties of $0.2 million and $28.9 million, respectively.$0.1 million.  These amounts are included in counterparty depositscurrent liabilities - other on the accompanying condensed consolidated balance sheets.sheet.  There were no such balances at December 31, 2007.  Select Energy also has collateral balances deposited with counterparties of $48.5$18.9 million and $103.8$48.5 million at December 31, 20062007 and 2005,2006, respectively.

The Utility Group hasOur regulated companies have a lower level of credit risk related to providing regulated electric and gas distribution service than NU Enterprises.  However, the Utility Groupour regulated companies are subject to credit risk from certain long-term or high-volume supply contracts with

31

energy marketing companies.  The Utility Group managesOur regulated companies manage the credit risk with these counterparties in accordance with established credit risk practices and maintainsmaintain an oversight group that monitors contracting risks, including credit risk.

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

Additional quantitative and qualitative disclosures about market risk are set forth in Part II, Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," included in this combined report on Form 10-K.contained within our 2007 Annual Report to Shareholders, which information is incorporated herein by reference.

Item 8.

Financial Statements and Supplementary Data

NU.  Reference is made to information under the headings "Report of Independent Registered Public Accounting Firm," "Consolidated Balance Sheets," "Consolidated Statements of Income/(Loss)," "Consolidated Statements of Comprehensive Income/(Loss)," "Consolidated Statements of Shareholders' Equity," "Consolidated Statements of Cash Flows," "Consolidated Statements of Capitalization," "Notes to Consolidated Financial Statements," and "Consolidated Statements of Quarterly Financial Data" contained within NU's 2006our 2007 Annual Report to Shareholders, which information is incorporated herein by reference.

CL&P.  Reference is made to information under the headings "Report of Independent Registered Public Accounting Firm," "Consolidated Balance Sheets," "Consolidated Statements of Income," "Consolidated Statements of Comprehensive Income," "Consolidated Statements of Common Stockholder's Equity," "Consolidated Statements of Cash Flows," "Notes to Consolidated Financial Statements," and "Consolidated Quarterly Financial Data" contained within CL&P's 20062007 Annual Report, which information is incorporated herein by reference.

PSNH.  Reference is made to information under the headings "Report of Independent Registered Public Accounting Firm," "Consolidated Balance Sheets," "Consolidated Statements of Income," "Consolidated Statements of Comprehensive Income," "Consolidated Statements of Common Stockholder's Equity," "Consolidated Statements of Cash Flows," "Notes to Consolidated Financial Statements," and "Consolidated Quarterly Financial Data" contained within PSNH's 20062007 Annual Report, which information is incorporated herein by reference.

WMECO.  Reference is made to information under the headings "Report of Independent Registered Public Accounting Firm," "Consolidated Balance Sheets," "Consolidated Statements of Income," "Consolidated Statements of Comprehensive Income," "Consolidated Statements of Common Stockholder's Equity," "Consolidated Statements of Cash Flows," "Notes to Consolidated Financial Statements," and "Consolidated Quarterly Financial Data" contained within WMECO's 20062007 Annual Report, which information is incorporated herein by reference.  

Item 9.

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

No events that would be described in response to this item have occurred with respect to NU,us, CL&P, PSNH or WMECO.

Item 9A.

Controls and Procedures

Management isWe are responsible for the preparation, integrity, and fair presentation of the accompanying consolidated financial statements of Northeast Utilities and subsidiaries (NU) and of other sections of this annual report.  TheseAnnual Report on Form 10-K.  NU’s internal controls over financial statements, whichreporting were audited by Deloitte & Touche LLP, have been prepared in conformity with accounting principles generally accepted in the United States of America using estimates and judgments, where required, and giving consideration to materiality.LLP.

Management isWe are responsible for establishing and maintaining adequate internal controls over financial reporting.  The Company'sOur internal control framework and processes have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  There are inherent limitations of internal controls over financial reporting that could allow material misstatements due to error or fraud to occur and not be prevented or detected on a timely basis by employees during the normal course of business.  Additionally, internal controls over financial reporting may become inadequate in the future due to changes in the business environment.  Under the supervision and with the participation of management, including our principal executive officer and principal financial officer, NUwe conducted an evaluation of the effectiveness of intern alinternal controls over financial reporting based on criteria established inInternal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  Based on this evaluation under the framework in COSO, managementwe concluded that our internal controls over financial reporting were effective as of December 31, 2006.2007.

Deloitte & Touche LLP has issued an attestation report on management's assessment of internal controls over financial reporting.32

NU,We, as well as CL&P, PSNH and WMECO, undertook separate evaluations of the design and operation of theirour disclosure controls and procedures to determine whether theywe are effective in ensuring that the disclosure of required information is made timely and in accordance with the Exchange Act and the rules and forms of the SEC.  This evaluation was made under theour supervision and with theour participation, of management, including the companies'our principal executive officers and principal financial officer, as of the end of the period covered by this Annual Report on Form 10-K.  TheOur principal executive officers and principal financial officer have concluded, based on their review, that the companies'our disclosure controls and procedures are effective to ensure that information required to be disclosed by the companiesus in our reports that it fileswe file under the Exchange Act i) is recorded, processed, summarized, and reported within the time periods specified in SEC rules and for msforms and ii) is accumulated and communicated to ou r management, including theour principal executive officers and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

There have been no changes in internal controls over financial reporting for NU,us, CL&P, PSNH and PSNHWMECO during the quarter ended December 31, 20062007 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.  There was a material change in WMECO's internal controls over financial reporting in the fourth quarter due to enhancements made to WMECO's controls related to supplier load/usage reporting to ISO New England.  WMECO reports to ISO New England the suppliers' hourly loads/usage aggregated for customers on competitive supply or WMECO's default service.

Item 9B.

Other Information

No information is required to be disclosed under this item at December 31, 2006,2007, as this information has been previously disclosed in applicable reports on Form 8-K during the fourth quarter of 2006.2007.

33

Part III

Item 10.  Directors, and Executive Officers and Corporate Governance

The information in Item 10 is provided as of February 13, 200726, 2008 except where otherwise indicated.

Certain information required by this Item 10 is omitted for PSNH and WMECO pursuant to Instruction I(2)(c) to Form 10-K, Omission of Information by Certain Wholly Owned Subsidiaries.

NU and CL&P

In addition to the information provided below concerning the executive officers of NU, incorporated herein by reference is the information contained in the sections captioned "Election of Trustees," "Board Committees"Governance of Northeast Utilities" and Responsibilities,"the related subsections, "Selection of Trustees," and "Section 16(a) Beneficial Ownership Reporting Compliance" of the definitive proxy statement for solicitation of proxies by NU's Board of Trustees, expected to be dated March 20, 2007,31, 2008, which will be filed with the CommissionSEC pursuant to Rule 14a-6 under the Securities Exchange Act of 1934.

         Name          

Positions  Held 

Gregory B. Butler

SVP, GC

Lawrence E. De Simone (1)

P

Cheryl W. Grisé (2)

EVP

David R. McHale

SVP, CFO

Leon J. Olivier (3)

EVP

Charles W. Shivery (4)

CHB, P, CEO, T

Shirley M. Payne (5)

VP, CONT

CL&P

         Name          

Positions  Held 

Gregory B. Butler

SVP, GC

Cheryl W. Grisé (2)

OTH

David R. McHale

SVP, CFO

Raymond P. Necci

P, COO, D

Leon J. Olivier (3)

CEO, D

Charles W. Shivery (4)

C, D

Shirley M. Payne (5)

VP, CONT

PSNH

         Name          

Positions  Held 

Gregory B. Butler

SVP, GC

Cheryl W. Grisé (2)

OTH

Gary A. Long

P, COO, D

David R. McHale  

SVP, CFO, D

Leon J. Olivier (3)

CEO, D

Charles W. Shivery (4)

C, D

Shirley M. Payne (5)

VP, CONT

WMECO

        Name          

Positions  Held 

Gregory B. Butler

SVP, GC

Cheryl W. Grisé (2)

OTH

David R. McHale

SVP, CFO, D

Leon J. Olivier (3)

CEO, D

Rodney O. Powell

P, COO, D

Charles W. Shivery (4)

C, D

Shirley M. Payne (5)

VP, CONT

(1)

Served as President-Competitive GroupThe names and ages of the executive officers of NU until January 1, 2007, when he retired.

(2)

Serves as Executive Vice President of NU.  Resigned as Chief Executive Officer and Directorthe executive officers and Directors of CL&P, PSNH and WMECO effective January 15, 2007.

(3)

Serves as Executive Vice President - Operationsthe positions they hold, held, or have been elected to (as of  NU.  Elected Chief Executive Officer of CL&P, PSNHFebruary 26, 2008), and WMECO effective January 15, 2007.

(4)

Serves as Chairman oftheir business experience during the Board, President and Chief Executive Officer and a Trustee of NU.  Elected Chairman and a Director of CL&P, PSNH and WMECO effective January 19, 2007.

(5)

Became an executive officer of NU upon election as Vice President-Accounting and Controller, effective February 13, 2007.  Became an executive officer of CL&P, PSNH and WMECO upon election as Vice President-Accounting and Controller, effective January 29, 2007.  

          Name          

Age

Office and Business Experience During Past 5Five Years

Gregory B. Butler

4950

Senior Vice President and General Counsel of NU since December 1, 2005 and of CL&P, PSNH and WMECO since March 9, 2006, and a2006. Director of Northeast Utilities Foundation, Inc. since December 1, 2002; previously2002. Previously, Senior Vice President, Secretary and General Counsel of NU from August 31, 2003 to December 1, 2005;2005, and Vice President, Secretary and General Counsel of NU from May 1, 2001 through August 30, 2003.

Lawrence E. De SimonePeter J. Clarke

5946

Retired asVice President of Shared Services of NUSCO, a subsidiary of NU, since January 1, 2007; previously served as President-Competitive Group of2008, and performs policy-making functions for NU and CL&P.  Previously, Vice President - Customer Operations of NU Enterprises, Inc.,CL&P and Yankee Gas from October 25, 2004July 1, 2006 to December 31, 2006 and Chairman, President and Chief Executive Officer of Select Energy, Inc. from February 1, 2005 to December 31, 2006; previously Executive2007; Vice President - Regulated BusinessCustomer Operations and ServicesRelations of PPL CorporationCL&P from January 1, 200417, 2005 to August 31, 2004; Executive Vice PresidentJune 30, 2006; and Director - SupplySystem Projects of PPL CorporationCL&P from October 2001March 11, 2002 to December 31, 2003.January 16, 2005.

Cheryl W. Grisé (*)

5455

Executive Vice President of NU sincefrom December 1, 2005;2005 toJuly 1, 2007;Chief Executive Officerof CL&P from September 10, 2002 to January 15, 2007.  Previously Chief Executive Officer of CL&P, PSNH and WMECO from September 10, 2002 to January 15, 2007, a Director of CL&P from May 1, 2001 to January 15, 2007, of PSNH from May 14, 2001 to January 15, 2007 and of WMECO from June 2001 to January 15, 2007, and a Director of Northeast Utilities Foundation, Inc. since September 23, 1998;2007; previously President - Utility Group of NU from May 2001 to December 1, 2005.

Gary A. Long (**)Jean M. LaVecchia

5556

Vice President - Human Resources of NUSCO, a subsidiary of NU, since June 30, 2005, and Chief Operating Officerperforms policy-making functions for NU and CL&P; also a Director of PSNHNortheast Utilities Foundation since JulyJanuary 30, 2007.  Previously Vice President - Human Resources and Environmental Services from May 1, 2000.2001 to June 30, 2005.

David R. McHale

4647

Senior Vice President and Chief Financial Officer of NU, CL&P, PSNH and WMECO since January 1, 2005 and a2005. Director of PSNH and WMECO since January 1, 2005 and CL&P since January 15, 2007; previously2007. Director of Northeast Utilities Foundation since January 1, 2005.  Previously Vice President and Treasurer of NU, WMECO and PSNH from July 1998 to December 31, 2004.

Raymond P. NecciNecci*

5556

President and Chief Operating Officer and a Director of CL&P and Yankee Gas since January 17, 2005. Director of Northeast Utilities Foundation since April 1, 2006.  Previously, Vice President - Utility Group Services of NUSCO from January 1, 2002 to January 16, 2005.

34

Leon J. Olivier

5859

Executive Vice President-Operations of NU since February 13, 2007;2007, and Chief Executive Officer of CL&P, PSNH and WMECO since January 15, 2007;2007. Director of PSNH and WMECO since January 17, 2005 and a Director of CL&P since September 2001.2001; also a Director of Northeast Utilities Foundation since April 1, 2006.  Previously, Executive Vice President of NU from December 1, 2005 to February 13, 2007; President - Transmission Group of NU from January 17, 2005 to December 1, 2005;2005, and President and Chief Operating Officer of CL&P from September 2001 to January 2005.

Shirley M. Payne

5556

Vice President - Accounting and Controller of NU since February 13, 2007, and of CL&P, PSNH and WMECO since January 29, 2007.  Previously, Vice President, Corporate Accounting and Tax of TECO Energy, Inc. from July 2000 to January 26, 2007 and Tax Officer of Tampa Electric CompanyTECO Energy, Inc. from April 1999 to January 26, 2007.  

Rodney O. PowellJames B. Robb

5447

President and Chief Operating Officer and a Director of WMECO since January 1, 2005.  PreviouslySenior Vice President, - Customer Relations ofEnterprise Planning and Development, NUSCO since September 4, 2007, and performs policy-making functions for NU and CL&P&P. Previously, Managing Director, Russell Reynolds Associates from January 1,December 2006 to August 2007; Entrepreneur in Residence, Mohr Davidow Ventures from March 2006 to November 2006; Senior Vice President, Retail Marketing, Reliant Energy, Inc. from December 2003 to December 2006; Senior Vice President, Performance Management,  Reliant Resources, Inc. from November 2002 to December 31, 2004.2003.

Charles W. Shivery

6162

Chairman of the Board, President and Chief Executive Officer of NU since March 29, 2004;2004 and Chairman and a Director of CL&P, PSNH and WMECO since January 19, 2007.  Also a Director of Northeast Utilities Foundation since March 3, 2004. Previously, President (interim) of NU from January 1, 2004 to March 29, 2004 and a Director of Northeast Utilities Foundation since March 3, 2004; previously President -– Competitive Group of NU and President and Chief Executive Officer of NU Enterprises, Inc., from June 2002 through December 2003.  

 (*)

Mrs. Grisé is a Director* Executive Officer of MetLife, Inc. and Dana Corporation.

 (**)

Mr. Long is a Director of Citizens Bank-NH.CL&P only.

There are no family relationships between any director or executive officer and any other director or executive officer of NU and CL&P PSNHand none of the above Executive Officers or WMECO.Directors serves as an Executive Officer or Director pursuant to any agreement or understanding with any other person. Our Executive Officers hold the offices set forth opposite their names until the next annual meeting of the Board of Trustees, in the case of NU, and the Board of Directors, in the case of CL&P, and until their successors have been elected and qualified.  

NU, CL&P PSNH, WMECOobtains audit services from the independent registered public accounting firm engaged by the Audit Committee of NU's Board of Trustees.  CL&P does not have its own audit committee or, accordingly, an audit committee financial expert.

CODE OF ETHICS AND STANDARDS OF BUSINESS CONDUCT

Each of the registrantsNU, CL&P, PSNH and WMECO has adopted a Code of Ethics for Senior Financial Officers (Chief Executive Officer, Chief Financial Officer and Controller) and a Standards of Business Conduct which is applicable to all Directors, officers, employees, contractors and agents of NU, CL&P, PSNH and WMECO.  The Code of Ethics and the Standards of Business Conduct have both been posted on Northeast Utilities'the NU web site and are available at http://www.nu.com/investors/corporate_gov/default.asp on the Internet. Information pertainingAny amendments to amendments andor waivers from the Code of Ethics and Standards of Business Conduct will be posted at this site.on the website.  Any such amendment or waiver would require the prior consent of the Board of Directors or an applicable committee thereof.

Printed copies of the Code of Ethics and the Standards of Business Conduct are also available to any shareholder without charge upon written request mailed to:

Ms. Kerry J. KuhlmanO. Kay Comendul

Vice President andAssistant Secretary

Northeast Utilities Service Company

P.O. Box 270

Hartford, CT  06141