PART I

A summary of changes in the operating companies’ electric kilowatt-hour (kWh) distribution sales for the 12-months ended December 31, 2008 as compared to December 31, 2007 on an actual and weather normalized basis (using a 30-year average) is as follows:

Retail electric sales in 2008 were lower than those in 2007.  The 2008 weather normalized decrease of 2.6 percent reflects the fact that our customers are responding to the volatile costs of energy and to the economic conditions of our region and the nation.  We believe customers will continue to respond to these factors and to the recent and ongoing developments in the financial markets resulting in an estimated decline in weather-normalized sales of approximately 1 percent in 2009.  

Changes in electric sales, however, have less of an impact on the earnings of our electric distribution companies than in prior years because non-distribution rate revenues, which represented approximately 76 percent of electric distribution company revenues in 2008, are tracked and reconciled to actual costs.  Non-distribution rate revenues include the energy, stranded cost, retail transmission and federally mandated congestion charges (FMCC) and other components of rates.  For non-distribution rate revenues, the only impact to earnings is from carrying costs on over- or under-recoveries.  With respect to our electric distribution company revenues, about two-thirds of CL&P's and WMECO's revenues and about one-half of PSNH's revenues are recovered through charges that are not dependent on overall sales volumes, such as the customer charge and the demand charge.

Comparable to our sales results in 2008, our uncollectibles expense has also been influenced by the adverse economic conditions of our region. Our write-offs as a percentage of revenues increased in 2008 for all our electric distribution companies. Similar to changes in our retail sales, changes in our uncollectibles expense have less of an impact on earnings of our electric distribution companies than in prior years as a portion of the uncollectibles expense for each of the electric distribution companies is allocated to its respective energy supply rate and recovered as a tracked expense.

THE CONNECTICUT LIGHT AND POWER COMPANY - DISTRIBUTION

CL&P’s distribution segment is primarily engaged in the purchase, delivery and sale of electricity to its residential, commercial and industrial customers.  At December 31, 2008, CL&P furnished retail franchise electric service to approximately 1.2 million customers in 149 cities and towns in Connecticut. CL&P does not own any electric generation facilities.

The following table shows the sources of 2008 electric franchise retail revenues for CL&P based on categories of customers:

Rates

CL&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.

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.  CL&P also has 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 or bonds (RRBs) 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 stranded costs being recovered through securitization, CL&P’s stranded costs included, as of December 31, 2008, ongoing independent power producer costs and costs associated with the ongoing decommissioning of the Maine Yankee, Connecticut Yankee and Yankee Rowe nuclear units.

3

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

A large percentage of CL&P's customers have continued to buy their power from CL&P at Standard Service rates or Supplier of Last Resort Service rates.  However, CL&P has experienced some customer migration to competitive energy suppliers, with the movement concentrated among larger customers.  Because this customer migration is only for energy supply service, there is no impact on the delivery portion of the business or the operating income of CL&P.

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).

On January 28, 2008, the DPUC approved $77.8 million, or 11.7 percent, and $20.1 million, or 2.6 percent, in annual increases in CL&P’s distribution rates, effective February 1, 2008 and February 1, 2009, respectively.  The rate decision included an ROE of 9.4 percent, with CL&P continuing its earnings sharing mechanism, which provides that ratepayers and shareholders share equally in any earnings in excess of its allowed regulatory ROE.  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," in this Annual Report on Form 10-K.

Regulatory Update

On May 2, 2008, the DPUC approved CL&P’s revised metering compliance plan that would meet the DPUC's objective of making time-of-use rates available to CL&P customers. The DPUC decision authorized a pilot program involving the installation of advanced metering infrastructure (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.  CL&P expects to conduct the AMI pilot with approximately 3,000 customers during the summer of 2009.  The estimated incremental cost of the program is expected to be between $10.6 million to $13 million and such costs are authorized to be recovered from customers, initially through CL&P’s FMCC charges.  The non-incremental operating and maintenance expenses are projected to be less than $2 million.

In 2008, pursuant to Connecticut's "Act Concerning Energy Independence," (Energy Independence Act), CL&P signed five contracts and The United Illuminating Company (UI) signed two contracts, each to purchase energy, capacity and renewable energy credits from planned renewable energy plants, including biomass and fuel cell projects, approved by the DPUC, for a total of 109 MW.  CL&P had also signed one contract with a biomass project in 2007 to purchase 15 MW of its output.  Purchases under the contracts are scheduled to begin in 2009 through 2011 and to extend for periods ranging from 15 to 20 years.  As directed by the DPUC, CL&P and UI have also signed a sharing agreement under which they will share the costs and benefits of these contracts, with 80 percent to CL&P and 20 percent to UI.  On January 16, 2009, the DPUC issued a draft decision selecting two additional renewable energy projects for a total of 6 MW with which CL&P or UI will sign similar contracts.  The final decision is scheduled for March 11, 2009.  Additional projects are expected to be selected by the DPUC to achieve a total of 150 MW of additional renewable energy sources in Connecticut.  CL&P's portion of the costs and benefits of these contracts will be paid by or refunded to CL&P's customers.

Also in 2008, CL&P and UI entered into contracts for differences (Peaker CfDs) with developers of three proposed peaking generation units totaling 506 MW of summer peaking capacity, as approved by the DPUC. The Peaker CfDs provide for the payment to the developer of the difference between capacity, forward reserve and energy market revenues and a cost-of-service payment stream for 30 years.  As directed by the DPUC, CL&P and UI will share the net costs and benefits of the Peaker CfDs on a basis of 80 percent and 20 percent, respectively.  CL&P’s portion of the costs and benefits will be paid by or refunded to its customers

In 2008, the DPUC issued final decisions in a docket examining the manner of operation and accuracy of CL&P's electric meters and in a docket investigating CL&P billing errors involving approximately 2,000 customers on time of use rates.  In the metering docket decision, the DPUC did not fine CL&P, but held that possibility open if CL&P fails to meet benchmarks to be established in the docket. The decision in the time-of-use docket disallowed recovery from customers of the incremental costs associated either directly or indirectly with the billing errors.  These incremental costs are not material and have been expensed as incurred.

In prior years, CL&P has submitted to the DPUC its proposed methodology to calculate the variable incentive portion of its Transition Service energy procurement fee, which was effective through 2006 and had requested approval of a pre-tax $5.8 million 2004 incentive fee.  In December 2005, the DPUC issued a draft decision authorizing the $5.8 million incentive fee and CL&P recovered the $5.8 million amount by recording it in 2005 earnings through the CTA reconciliation process.  CL&P has not recorded any amounts in earnings related to the 2005 or 2006 procurement fee.  On January 15, 2009, the DPUC issued a final decision on the 2004 incentive fee that reversed its December 2005 draft decision, and concluded that CL&P was not eligible for the procurement incentive compensation for 2004.  As a result, the $5.8 million pre-tax charge was recorded in CL&P’s 2008 earnings, and an obligation to refund the $5.8 million to customers was established in the CTA reconciliation process as of December 31, 2008.  CL&P filed an appeal of this decision on February 26, 2009.  

For further information on regulatory actions affecting CL&P, see "Regulatory Developments and Rate Matters - Connecticut - CL&P" in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," in this Annual Report on Form 10-K.

4

Sources and Availability of Electric Power Supply

As noted above, CL&P does not own any generation assets and purchases its energy requirements to serve its Standard Service and Supplier of Last Resort Service loads from a variety of competitive sources through periodic requests for proposals (RFPs).  CL&P issues RFPs periodically for periods of up to three years to layer Standard Service full requirements supply contracts in order to mitigate price volatility for its residential and small and medium commercial and industrial customers.  CL&P issues RFPs for Supplier of Last Resort service for larger commercial and industrial customers every three months.  Currently, CL&P has in place contracts with various suppliers through 2010 for Standard Service and to date one tranche has been filled for 2011.  

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE - DISTRIBUTION

PSNH’s distribution segment (which includes its regulated generation) is primarily engaged in the generation, purchase, delivery and sale of electricity to its residential, commercial and industrial customers.  At December 31, 2008, PSNH furnished retail franchise electric service to approximately 493,000 retail customers in 211 cities and towns in New Hampshire.  PSNH also owns and operates approximately 1,200 MW of electricity generation assets.  Approximately 70 MW of those generation assets are hydroelectric units. Included among these generating assets is a 50 MW wood-burning generating unit (Northern Woods Power Project) at its Schiller Station in Portsmouth, New Hampshire, which was converted from a coal-burning unit in December 2006.

The following table shows the sources of 2008 electric franchise retail revenues based on categories of customers:

Rates

PSNH 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.

PSNH’s Energy Service (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 annually with the NHPUC, with a six-month true-up, to ensure timely recovery of its costs.  PSNH defers for future recovery or refund any difference between its ES revenues and the actual costs incurred.

On July 1, 2008, PSNH’s Delivery Service (DS) rates decreased by $0.4 million annually.  This amount consisted of a $3.4 million rate reduction related to the full recovery of a rate differential recoupment and an increase of approximately $3 million per year for a two-year period effective July 1, 2008 to eliminate a negative balance in the major storm cost reserve and restore the intended reserve level of $1 million.

Pursuant to a distribution and transmission rate case settlement agreement between PSNH, the NHPUC staff and the Office of Consumer Advocate, the NHPUC approved PSNH’s petition seeking to establish a Transmission Cost Adjusting Mechanism (TCAM) rate to be reset annually consistent with the rate settlement agreement.  On May 13, 2008, PSNH filed a July 1, 2007 through June 30, 2008 TCAM reconciliation and a projected TCAM rate to be billed effective July 1, 2008 related to July 1, 2008 through June 30, 2009 TCAM costs.

Under New Hampshire law, the Stranded Cost Recovery Charge (SCRC) allows PSNH to recover its stranded costs, including expenses incurred through mandated power contracts and other long-term investments and obligations. PSNH has financed a significant portion of its stranded costs through securitization by issuing RRBs secured by the right to recover these stranded costs from customers over time.  It recovers the costs of these bonds through the SCRC rate.  On an annual basis, PSNH makes an SCRC reconciliation filing with the NHPUC for the previous year.  For further information on PSNH rates, see "Regulatory Developments and Rate Matters" in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," in this Annual Report on Form 10-K.

Under the terms of the order issued by the NHPUC approving PSNH’s 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 avoidances (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 2008 due to its performance and favorable pricing in the Massachusetts and Rhode Island markets for the RECs.  As a result, customers and shareholders will share equally a benefit of about $7.8 million of incremental revenues for 2008.  

Although PSNH's customers are entitled to choose competitive energy suppliers, PSNH has experienced only a small amount of customer migration to date.

5

On December 11, 2008, a major ice storm struck portions of New England, severely damaging PSNH’s distribution systems. This was the most severe ice storm in PSNH’s history.  Of the 440,000 New Hampshire homes and businesses that lost power, 322,000 were served by PSNH.  Restoration operations commenced on December 11, 2008 and were substantially completed by December 25, 2008.  PSNH utilized its own line crews, local contractors, line crews from other NU subsidiaries and numerous other line crews from the eastern United States and Canada.

The operating cost of storm restorations that meet a NHPUC specified criteria are funded through the Major Storm Costs Reserve (MSCR).  Capital costs for any storm work are charged to property, plant and equipment and are recovered through the normal distribution ratemaking process.  As the December 2008 ice storm met the MSCR criteria, $62.7 million of total estimated repair costs of $75 million associated with this storm were charged to the MSCR at December 31, 2008.  PSNH intends to request recovery of these costs as part of its next delivery rate proceeding with the NHPUC.  Out of the remaining total storm costs incurred through December 31, 2008, $6.5 million has been expensed and $5.6 million has been capitalized to plant and equipment.  PSNH expects to recognize an additional $10 million in 2009 when the weather is warmer and additional clean-up and repairs can be performed.  We carry $15 million of storm-related insurance system-wide and to the extent that any insurance proceeds are received, a portion would be allocated to PSNH to reduce the amount of deferred or expensed storm costs.

Regulatory Update

In 2006, New Hampshire enacted a law requiring PSNH to reduce the mercury emissions for its coal fired plants by at least 80 percent (with co-benefits of reduction in sulfur dioxide (SO2) emissions as well).  Wet scrubber technology will be installed at Merrimack Station in Bow New Hampshire no later than July 1, 2013.  Following an August 2008 announcement by PSNH that the cost of this installation would be increasing from the original estimate of $250 million to $457 million, the NHPUC opened an inquiry to determine whether it had authority to assess whether the project is in the public interest.  In September 2008, the NHPUC ruled that its authority is limited to determining at a later time the prudence of the costs incurred in complying with the legislation.  In October 2008, several parties filed motions with the NHPUC requesting a reconsideration of its ruling; these motions were rejected.  On December 11, 2008, several parties involved in the filing of the October 2008 motion for a rehearing filed an appeal with the New Hampshire Supreme Court requesting that the Court overturn the NHPUC finding that it lacked present authority over this matter.  The Supreme Court has indicated that it will hear this appeal, but has not yet issued a schedule for oral arguments.  

In July 2008, New Hampshire passed a law establishing a transmission commission responsible for developing a proposal to expand the electric transmission system in northern New Hampshire to encourage the development of new renewable generation sources.  On December 1, 2008, the transmission commission submitted its progress report, which concluded that New Hampshire should continue to pursue the upgrade of transmission capacity in its northern region to allow development of its native renewable energy resources.  Also, the transmission commission should continue to pursue both local and regional cost allocation issues related to the transmission expansion.  We believe the northern New Hampshire region has the potential for over 500 MW of new renewable resources.  PSNH has included $130 million in its 2009 to 2013 capital plan for transmission upgrades in the region which assumes that these projects are built and a cost allocation solution can be agreed to by relevant parties.

In July 2008, New Hampshire passed a law authorizing rate recovery by electric public utilities of investments made in distributed energy resources up to 5 MW, such as renewable energy generation.  The total investment is limited to resources having a capability equal to 6 percent of a distribution utility’s peak load.  PSNH has not yet included any distributed energy resource investment opportunities in its capital expenditure plans.  

Sources and Availability of Electric Power Supply

During 2008, about 67 percent of PSNH’s load was met through its own generation and long-term power supply rate orders and contracts with third parties.  The remaining 33 percent of PSNH's load was met by short-term (less than one year) purchases and spot purchases in the competitive New England wholesale power market.  PSNH expects to meet its load requirements in 2009 in a similar manner.  

New Hampshire’s "Renewable Energy Act" establishes renewable portfolio standards for electricity sold in the state that require annual increases in the percentage of the electricity sold to retail customers having direct ties to renewable sources.  The renewable sourcing requirements began in 2008 and increase each year to reach 23.8 percent by 2025.  PSNH plans to meet these standards, in part, through the purchase of Renewable Energy Certificates (RECs) from qualified renewable energy resources.  For each MWH of energy produced from a qualifying resource, the producer will receive one REC. Energy suppliers, like PSNH, will purchase these RECs from the producers and will use them to satisfy the RPS requirements.  To the extent that PSNH is unable to purchase sufficient RECs, it will be required to make up the difference between the RECs purchased and its total obligation by making an alternative compliance payment (ACP) for each REC requirement for which PSNH is deficient.  The costs of both the RECs and ACPs do not impact earnings, as these costs are being recovered by PSNH through its ES rates.  For further information, see "Regulatory Developments and Rate Matters - New Hampshire" in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," in this Annual Report on Form 10-K.

6

WESTERN MASSACHUSETTS ELECTRIC COMPANY - DISTRIBUTION

WMECO’s distribution segment is engaged in the purchase, delivery and sale of electricity to residential, commercial and industrial customers.  At December 31, 2008, WMECO furnished retail franchise electric service to approximately 206,000 retail customers in 59 cities and towns in the western third of Massachusetts.  WMECO does not own any electricity generating facilities.  On December 31, 2008, WMECO purchased all of the transmission-related assets of its affiliates, Holyoke Water Power Company (HWP) and Holyoke Power and Electric Company (HP&E) for approximately $4 million.

The following table shows the sources of 2008 electric franchise retail revenues based on categories of customers:

Rates

WMECO is subject to regulation by the Massachusetts Department of Public Utilities (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.

WMECO collects its transmission costs through a transmission adjustment clause, which is adjusted annually, thereby allowing WMECO to recover all of its retail transmission expenses on a timely basis.

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

On January 1, 2008, WMECO’s distribution rates increased by $3 million annually as approved by the Massachusetts DPU in December 2006.  WMECO adjusted its rates to include the distribution increase, new basic service contracts, and changes in several tracking mechanisms.  On December 29 and 30, 2008, the DPU approved WMECO’s proposed rate changes effective January 1, 2009.  The rate changes were made in accordance with WMECO’s various tracking mechanisms.

The major ice storm on December 11, 2008 also impacted parts of Massachusetts, including areas served by WMECO.  As this storm met the storm costs reserve criteria approved in WMECO’s last distribution rate case settlement, $11.3 million of the total $13.8 million estimated repair costs associated with this storm were recognized as a deferred asset at December 31, 2008.  WMECO expects to begin recovery of these costs in its next distribution rate proceeding.  The DPU has opened a formal docket to review storm restoration efforts by the state's utilities.

For further information on WMECO’s rates, see "Regulatory Developments and Rate Matters" in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," in this Annual Report on Form 10-K.

Regulatory Update

On July 16, 2008, the DPU issued a decision in its decoupling generic docket requiring all gas and electric utilities to file full decoupling proposals with their next general rate case.  The decision rejected calls for partial decoupling or decoupling by rate design in favor of full decoupling by rate class.  On September 2, 2008, WMECO notified the DPU that it expects to file its next distribution rate case in mid-2010 to be effective January 1, 2011.  That case will include a proposal to fully decouple distribution revenues from kilowatt-hour sales.

As part of WMECO’s December 2006 rate case settlement agreement approved by the DPU, WMECO became subject to service quality (SQ) metrics that measure safety, reliability and customer service.  Any charges incurred are paid to customers through a method approved by the DPU.  WMECO will likely be required to pay an assessment charge for its 2008 reliability performance against the metrics established for 2008, primarily as a result of significant storm activity.  WMECO has performed at target for other non-storm related reliability metrics.  WMECO will file its 2008 SQ results and assessment calculation with the DPU in March 2009.  In 2008, WMECO recorded an estimated pre-tax charge and a regulatory liability of approximately $1.3 million for this assessment.

7

In July 2008, Massachusetts enacted "The Green Communities Act of 2007."  Aimed at increasing energy efficiency (EE) and the use of renewable resources in the state, the Act contains many provisions important to the state’s utilities.  In addition to adopting RGGI requirements, the Act:

·

Removes the cap on utility expenditures for EE and demand response (DR).  

·

Requires utilities to file three-year EE and DR plans with a newly created Energy Efficiency Council;

·

Requires utilities to sign long-term contracts for renewable resources;

·

Allows each utility to own and operate up to 50 MW of solar generation;

·

Requires utilities to file a plan with the DPU for a smart grid pilot; and

·

Increases penalties for failure to meet service quality standards from 2 percent of transmission and distribution revenues to 2.5 percent.

By April 30, 2009, WMECO is required to prepare a three-year EE and DR investment plan related to the cost of EE and DR programs established by the Act for review by the Energy Efficiency Council and, ultimately, the DPU.  In addition, WMECO filed a program with the DPU on February 11, 2009 providing for a three-phase solar generation program subject to DPU authorization prior to each phase. The initial phase calls for 6 MW of solar generation to be installed at eight host sites in WMECO's service territory upon receipt of DPU approval.  This phase of the project is expected to be completed as early as 2010 at a cost of approximately $42 million.  The second phase includes an additional 9 MW extending through 2012, and the third and final phase could increase total capacity to the 50 MW maximum.  The DPU has six months to issue a decision on WMECO's plan.  WMECO is otherwise precluded from making new generation investments, but has not yet included any solar generation investment opportunities in its capital expenditure plans.  

Sources and Availability of Electric Power Supply

As noted above, WMECO does 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 issues RFPs periodically, consistent with DPU regulations. On May 14, 2008, WMECO entered into an agreement to secure 50 percent of residential, small commercial and industrial, and street lighting loads for the July 1, 2008 through June 30, 2009 period, and on November 3, 2008 WMECO entered into an agreement to secure power for half of its residential, small commercial and industrial, and street lighting loads for the January 1 through December 31, 2009 period.  WMECO will issue an RFP in the second quarter of 2009 to secure the remaining 50 percent of its residential, small commercial and industrial, and street lighting loads for the July 1 through December 31, 2009 period and 50 percent of the load for January 1, 2010 through June 30, 2010.  For its large commercial and industrial customers, WMECO entered into an agreement on November 3, 2008 to secure power for the first quarter of 2009 and an agreement to secure power for the second quarter 2009 on February 10, 2009.  RFPs will be issued quarterly to secure power for the balance of the year.

REGULATED GAS DISTRIBUTION

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) in 2008 was 49.8 billion cubic feet (Bcf) compared with 49.7 Bcf in 2007.  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 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.  The LNG facility is capable of storing the equivalent of 1.2 Bcf of natural gas.

Yankee Gas earned $27.1 million on total gas operating revenues of approximately $577.4 million for 2008. The following table shows the sources of 2008 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 17, "Segment Information," contained within this Annual Report on Form 10-K.

8

A summary of changes in Yankee Gas firm natural gas sales for 2008 as compared to 2007 on an actual and weather normalized basis (using a 30-year average) is as follows:

Firm natural gas sales for 2008 were higher than 2007.  The 2008 results reflect warmer weather in the first quarter, colder weather in the fourth quarter and an increase in industrial sales primarily due to customer-owned gas-fired distributed generation and favorable natural gas prices relative to oil.  We have assumed an increase in weather normalized firm natural gas sales of approximately 2.5 percent in 2009.  Similar to our electric distribution companies, Yankee Gas recovers a significant portion of its distribution revenues (approximately 40 percent) through charges that are not dependent on usage.

Although Yankee Gas is not subject to the FERC's jurisdiction, the FERC has limited oversight with respect to certain reporting and 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.

Yankee Gas recovers its cost of gas supplied to customers through a Purchased Gas Adjustment (PGA) 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.  On June 11, 2008, the DPUC issued a final order pursuant to which Yankee Gas was required to refund to customers approximately $5.8 million in recoveries under its Purchased Gas Adjustment clause.  Yankee Gas results for 2008 reflect an after-tax charge of $3.5 million associated with that decision.

Under a settlement of its distribution rate filing with the Connecticut Office of Consumer Counsel and the DPUC’s Prosecutorial Division, Yankee Gas’s base rate increased, effective July 1, 2007, by $22 million, or 4.2 percent, net of expected pipeline and commodity cost savings resulting primarily from completion of Yankee Gas’s LNG facility, and Yankee Gas was allowed an authorized ROE of 10.1 percent.  Yankee Gas will return to ratepayers 100 percent of all earnings in excess of the allowed 10.1 percent ROE. As a result of the base rate increase, the amount of gas supply costs charged to customers through the PGA decreased.

FORWARD CAPACITY MARKETS

On December 1, 2006, a FERC-approved Forward Capacity Market (FCM) settlement agreement was implemented, and the payment of fixed compensation to generators began.  The second forward capacity auction concluded on December 10, 2008 for the capacity year June 2011 through May 2012.  The bidding reached the established minimum of $3.60 per kilowatt-month with 4,755 MW of excess remaining capacity.  This means the effective price will be $3.12 per kilowatt-month compared to the equivalent first forward capacity auction price of $4.25 per kilowatt-month for the 12-month capacity period ending May 31, 2011 and $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.

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 rules by which they participate in the wholesale markets and acquire transmission services.  Under these arrangements, ISO-NE, a non-profit corporation whose board of directors and staff are independent from all market participants, has served as the Regional Transmission Operator (RTO) of the New England Transmission System since February 1, 2005.  ISO-NE works to ensure the reliability of the system, administers the independent system operator tariff, subject to FERC approval, oversees the efficient and competitive functioning of the regional wholesale power market and determines which costs of our major transmission facilities are regionalized throughout New England.

9

Wholesale Transmission Rates

Wholesale transmission revenues are based on formula rates that are approved by the FERC. Most of our wholesale transmission revenues are collected under ISO-NE’s FERC Electric Tariff No. 3, Transmission, Markets and Services Tariff (Tariff No. 3).  Tariff No. 3 includes the Regional Network Service (RNS) and Local Network Service (LNS) rate schedules, among other things.  The RNS rate, administered by ISO-NE and billed to all New England transmission owners, is reset on June 1st of each year and recovers the revenue requirements associated with transmission facilities that benefit the New England region.  The LNS rate, which we administer, is reset on January 1st and June 1st of each year and recovers the revenue requirements for local transmission facilities and other transmission costs not covered under the RNS rate, including 100 percent of the construction costs of the New England East-West Solutions (NEEWS) projects.  Both the LNS and RNS rates provide for annual true-ups to actual costs.  The LNS rate calculation recovers total transmission revenue requirements 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 March 24, 2008, the FERC issued an order on rehearing confirming its initial order setting the base ROE on transmission projects for the New England transmission owners, including NU’s subsidiaries.  Including a final adjustment, the order provides a base ROE of 11.14 percent for the period beginning November 1, 2006. The order also affirmed FERC’s earlier decision granting a 100 basis point adder for new transmission projects that are built as part of the ISO-NE Regional System Plan and are "completed and on line" by December 31, 2008.  In order to receive incentives for projects completed after December 31, 2008, transmission owners are required to make project-specific incentive requests that meet the nexus requirements under FERC guidelines for new projects. In 2008, we recognized $6 million in transmission segment earnings related to this order.  This order has been appealed to the D.C. Circuit Court of Appeals by various state regulators and consumer advocates.  The court has set a schedule for the briefing to be concluded in the second quarter of 2009, with no date set for argument.

On May 16, 2008, CL&P filed an application with the FERC to receive ROE incentives for its portions of the Middletown-Norwalk project seeking a waiver of the "completed and on line" date of December 31, 2008 to earn the ROE incentives. Alternatively, CL&P asked FERC to find that this project met the nexus test requirements for incentives under FERC’s guidelines for new projects, and also requested an additional 50 basis point adder for advanced technology used in the project.  FERC subsequently granted the waiver request and approved the 100 basis point incentive for the entire Middletown-Norwalk project.  The FERC also found that the project met the nexus test, and granted an additional 50 basis point adder for the advanced technology aspects of the 24-mile underground portion of the project. CL&P completed the project by the end of 2008.  The 50 basis point adder results in a total ROE for the underground portion of the Middletown-Norwalk project of 13.1 percent, which represents the overall ROE limit established by FERC.  Certain state regulators and municipal utilities had sought rehearing which was denied by FERC and Connecticut state regulators have since appealed the order to the D.C. Circuit Court of Appeals.  

On November 17, 2008, the FERC issued an order granting certain incentives and rate amendments to National Grid USA (National Grid) and us, for certain components of the proposed NEEWS projects.  The approved incentives included (1) an ROE of 12.89 percent, which includes an incentive of 125 basis points; (2) inclusion of 100 percent construction work in progress (CWIP) costs in rate base; and (3) full recovery of prudently incurred costs if any portion of NEEWS is abandoned for reasons beyond our or National Grid's control.  Our portion of the components that received these incentives is estimated to cost approximately $1.41 billion of our $1.49 billion share of the total NEEWS projects.  Several parties have sought rehearing of this FERC order on which FERC has not yet acted.

Transmission Projects

In December 2008, we completed the last of our four southwest Connecticut transmission upgrades. The first of those projects, a new 345KV/115KV overhead and underground line between Bethel, Connecticut and Norwalk, Connecticut, was placed in service in October 2006.  The remaining three projects were placed in service in 2008.  The Middletown-Norwalk project, a 69-mile, 345KV/115 KV transmission project from Middletown to Norwalk, Connecticut constructed jointly with UI, was completed in December 2008. CL&P's portion of this project cost approximately $950 million, $100 million lower than our earlier cost estimate.  The 45-mile overhead section of the project entered service on August 28, 2008 and the 24-mile underground section entered service on December 16, 2008.  The Glenbrook Cables project, a two-cable, nine-mile, 115 KV underground transmission project between Norwalk and Stamford, Connecticut entered service on November 11, 2008 at a project cost of approximately $239 million, $16 million higher than previous estimates due to increased construction costs to remove underground obstacles.  The Long Island Replacement Cable project, a 138KV, 11-mile undersea transmission project between Norwalk, Connecticut and Northport-Long Island, New York was completed in September 2008.  CL&P owns 51 percent of the project, with Long Island Power Authority owning the remainder, and CL&P's portion of the project costs is anticipated to be approximately $78 million.

In October 2008, we commenced state regulatory filings for our next series of major transmission projects, NEEWS.  That series of projects involves our construction of new overhead 345 KV lines in Massachusetts and Connecticut as well as associated substation work and 115 KV rebuilds.  One of the projects will connect to a new transmission line that National Grid plans to build in Rhode Island and Massachusetts.  On September 24, 2008, the New England Independent System Operator (ISO-NE) issued its final technical approval of the NEEWS projects which was a precursor to the siting application process.  We estimate that CL&P’s and WMECO’s total capital expenditures for these projects will be $1.49 billion through 2013.  

The first of the NEEWS projects, the Greater Springfield Reliability Project, which involves a 115 KV/345 KV line from Ludlow, Massachusetts to North Bloomfield, Connecticut, is the largest and most complicated project within NEEWS.  This project is expected

10

to cost approximately $714 million if built according to our preferred route and configuration.  CL&P filed its application to build the Connecticut portion of the Greater Springfield Reliability Project with the Connecticut Siting Council (Siting Council) on October 20, 2008 and WMECO filed its application to build its portion of the project with the Massachusetts Energy Facilities Siting Board on October 27, 2008.  The Connecticut Energy Advisory Board is currently reviewing Connecticut-based generation, demand side management and other proposed alternatives to the Greater Springfield Reliability Project, which must be submitted to the Siting Council by March 19, 2009.  The Siting Council has preliminarily set dates for hearings, public comments and site visits on the Connecticut portion of the project in the second quarter of 2009.  If the overall project is approved in 2010 as expected, we currently expect to commence construction in late 2010 and place the project in service in 2013.

Our second major NEEWS project is the Interstate Reliability Project, which is being designed and built in coordination with National Grid.  CL&P's share of this project includes a 40-mile 345 KV line from Lebanon, Connecticut to the Connecticut-Rhode Island border where it would connect with enhancements National Grid is designing.  We expect CL&P's share of this project to cost approximately $250 million.  Municipal consultations concluded in November 2008, and CL&P plans to file siting applications with Connecticut regulators by the third quarter of 2009 with construction beginning as early as late 2010.  We currently expect the project to be placed in service as early as 2012.

The third part of NEEWS is the Central Connecticut Reliability Project, which involves construction of a new line from Bloomfield, Connecticut to Watertown, Connecticut.  This line would provide us with another 345 KV connection to move power across the state of Connecticut.  The timing of this project would be six to twelve months behind the other two projects, and CL&P currently expects to file the siting application in early 2010 with construction beginning in 2011.  The project is currently expected to be placed in service in 2013 at a cost of approximately $315 million.  Included as part of NEEWS are approximately $210 million of associated reliability related expenditures, some of which may be incurred in advance of the three major projects.

During the siting approval process, state regulators may require changes in configuration to address local concerns that could increase construction costs.  Our current design for NEEWS does not contemplate any underground lines. Building any transmission lines underground, particularly 345KV lines, would increase total costs, and our estimate could be increased during the siting approval process.

On December 12, 2008, we submitted jointly with NSTAR, a petition with the FERC requesting a declaratory order that would allow us and NSTAR to enter into a bilateral transmission services agreement with H.Q. Energy Services (U.S.) Inc. (HQUS), a wholly-owned subsidiary of Hydro-Québec.  Under such an agreement, NU and NSTAR subsidiaries would sell to HQUS 1,200 megawatts of firm electric transmission service over a new, participant-funded transmission tie line connecting New England with the Hydro-Québec system in order for HQUS to sell and deliver this same amount of firm electric power from Canadian low-carbon energy resources to New England.  

If FERC issues the declaratory order as we anticipate, NU and NSTAR would subsequently seek approval from FERC of the specific terms and conditions of the transmission arrangement and approvals from state regulators of the terms and conditions of the power purchase arrangements.  NU, NSTAR and HQUS have signed memoranda of understanding to develop this transmission project on an exclusive basis.  This project would provide a competitive source of low-carbon power that is favorable in comparison to current alternatives.  It also would provide for an expansion of New England’s transmission system without raising regional transmission rates.

NU, NSTAR and HQUS have also begun discussions on the specifics of a potential long-term power purchase agreement that would ensure the line is utilized to bring low-carbon power to benefit New England customers.  A FERC order is expected in the first half of 2009, and if the order approves the proposal, then NU and NSTAR plan to negotiate a power purchase agreement with HQUS later in 2009.  The terms of such an agreement would be subject to regulatory approval in several states.

Assuming completion of an acceptable power purchase agreement, and receipt of all necessary state and federal regulatory approvals, we expect this project to be under construction between 2011 and 2014.  Our initial estimate of our portion of the construction funding is approximately $525 million.  HQUS will reimburse NU and NSTAR for the total costs of this project, including an investment return to these companies, over the estimated 40-year operating life of the transmission line.  NU and NSTAR’s intent is to create an agreement that approximates a typical FERC approved cost-of-service rate structure.  The revenue recovery model will ultimately require FERC approval.

Transmission Rate Base

Under our FERC-approved tariff, transmission projects enter rate base once they are placed in commercial operation. Additionally, 100 percent of the NEEWS projects will enter rate base during their construction period.  At the end of 2008, our transmission rate base was approximately $2.4 billion, including approximately $2.0 billion at CL&P, $250 million at PSNH and $80 million at WMECO. We forecast that our total transmission rate base will grow to approximately $5.0 billion by the end of 2013.  This increase in transmission rate base is driven by the need to improve the capacity and reliability of our regulated transmission system.

11

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

The projected rate base amounts reflected above assume that $1.49 billion in transmission projects associated with NEEWS will be completed before the end of 2013 and the transmission line connecting to HQUS is built.  Numerous factors, some of which are beyond our control, may impact the rate base amounts above, including the level and timing of capital expenditures and plant placed in service and regulatory approvals.  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 Results of Operations" contained in this Annual Report on Form 10-K.

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 in 2008, including amounts incurred but not paid, cost of removal, allowance for funds used during construction and the capitalized portions of pension and PBOP expense or income (all of which are non-cash factors in determining rate base), totaled approximately $1.3 billion, almost all of which was expended by the regulated companies.  The capital expenditures of these companies in 2009 are estimated to total approximately $851 million.  Of this amount, approximately $375 million is expected to be expended by CL&P, $310 million by PSNH, $100 million by WMECO and $66 million by Yankee Gas.  This capital budget includes anticipated costs for all committed capital projects (i.e., generation, transmission, distribution, environmental compliance and others) and those reasonably expected to become committed projects in 2009.  We expect to evaluate needs beyond 2009 in light of future developments, such as restructuring, industry consolidation, performance and other events.  Increases 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 approaching 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.

CL&P’s transmission capital expenditures in 2008 totaled approximately $586 million.  The decrease in transmission segment capital expenditures in 2008 as compared with 2007 was primarily due to the early completion of the major southwest Connecticut transmission projects discussed above.  For 2009, CL&P projects transmission capital expenditures of approximately $97 million. During the period 2009 through 2013, CL&P plans to invest approximately $974 million in transmission projects, the majority of which will be for NEEWS.

In addition to its transmission projects, CL&P plans distribution capital expenditures to meet growth requirements and improve the reliability of its distribution system.  In 2008, CL&P's distribution capital expenditures totaled approximately $297 million.  CL&P projects its distribution capital expenditures in 2009 to be approximately $278 million.  CL&P plans to spend approximately $1.59 billion on distribution projects during the period 2009-2013.  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 $2.0 billion at the end of 2008 to approximately $2.5 billion by the end of 2013, and its rate base for distribution assets is projected to increase from approximately $2.0 billion to approximately $3.0 billion over the same period.

In 2008, PSNH's transmission capital expenditures totaled approximately $82 million, its distribution capital expenditures totaled $98 million and its generation capital expenditures totaled $74 million.  For 2009, PSNH projects transmission capital expenditures of approximately $58 million, distribution capital expenditures of approximately $96 million and generation capital expenditures of approximately $156 million.  The increase in generation capital expenditures is mostly due to the expenditures for the Merrimack Clean Air project.  During the period 2009-2013, PSNH plans to spend approximately $1.1 billion on transmission projects, approximately $559 million on distribution projects, and $623 million on generation projects.  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 $250 million at the end of 2008 to approximately $1.2 billion by the end of 2013, and its rate base for distribution and generation assets is projected to increase from approximately $1.0 billion to approximately $2.0 billion over the same period.

In 2008, WMECO's transmission capital expenditures totaled approximately $44.2 million and its distribution capital expenditures totaled approximately $37.8 million.  In 2009, WMECO projects transmission capital expenditures of approximately $70 million and distribution capital expenditures of approximately $30 million.  During the period 2009-2013, WMECO plans to spend approximately $888 million on transmission projects, with the bulk of that amount to be spent on the NEEWS Greater Springfield Reliability Project, and approximately $168 million on distribution projects.  If all of the distribution and transmission projects are built as proposed, WMECO’s rate base for electric transmission is projected to increase to approximately $876 million by the end of 2013 and its rate base for distribution assets is projected to increase from approximately $374 million to approximately $497 million over the same period.

12

In 2008, Yankee Gas’s capital expenditures totaled approximately $44 million.  For 2009, Yankee Gas projects total capital expenditures of approximately $66 million.  During the period 2009-2013, Yankee Gas plans on making approximately $399 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 $685 million at the end of 2008 to approximately $890 million by the end of 2013.

For more information regarding NU and its subsidiaries' construction and capital improvement programs, see "Business Development and Capital Expenditures" under Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained in this Annual Report on Form 10-K.

STATUS OF EXIT FROM COMPETITIVE ENERGY BUSINESSES

Since 2005, we have been in the process of exiting our competitive energy businesses and are now focusing exclusively on our regulated businesses.  At December 31, 2008, our competitive businesses consisted solely of (i) Select Energy’s few remaining wholesale marketing contracts and NGS and its affiliates, which are winding down, and (ii) Boulos, NU Enterprises’ remaining active energy services business.

On May 31, 2008, Select Energy’s remaining wholesale sales contract in the PJM power pool expired.  Select Energy’s wholesale contract with The New York Municipal Power Agency (NYMPA) and related supply contracts expire in 2013.  In addition to the PJM and NYMPA contracts, Select Energy's only other long-term wholesale obligation is a non-derivative contract to operate and purchase the output of a certain generating facility in New England through 2012.

For more information regarding the exit of the competitive businesses, see "NU Enterprises Divestitures" under Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 15, "Restructuring and Impairment Charges and Discontinued Operations," to the consolidated financial statements, contained within this Annual Report on Form 10-K.

FINANCING

We paid dividends on our common shares totaling $129.1 million in 2008, compared to $121 million in 2007, reflecting increases in the quarterly dividend amount that were effective in the third quarters of 2007 and 2008.  On February 10, 2009, the NU Board of Trustees declared a quarterly dividend of $0.2375 per share, payable on March 31, 2009, an increase of $0.10 per share above the previous annualized rate of $0.85 per share.  This dividend reflects the company’s policy, announced in November 2008, of targeting a dividend payout ratio of approximately 50 percent of earnings, with a goal of continuing the policy of increasing the dividend at a rate above industry average and providing an attractive return to shareholders.  NU expects to revisit its dividend levels in the first quarter of each year.

In general, the regulated companies pay approximately 60 percent of their cash earnings to NU parent in the form of common dividends.  In 2008, CL&P, PSNH, WMECO and Yankee Gas paid $106.5 million, $36.4 million, $39.7 million, and $31 million, respectively, in common dividends to NU parent.  In 2008, NU parent contributed $210 million of equity to CL&P, $75.6 million to PSNH, $16.3 million to WMECO, and $20.8 million to Yankee Gas.  

NU parent’s ability to pay common dividends is subject to approval by the Board of Trustees and to NU’s future earnings and cash flow requirements.  It is not regulated under the Federal Power Act, but may be limited by certain state statutes, the leverage restrictions tied to its required ratio of consolidated total debt to total capitalization in its revolving credit agreement, and the ability of its subsidiaries to pay common dividends.  The Federal Power Act does, however, limit the payment of dividends by CL&P, PSNH and WMECO to their respective retained earnings balances unless a higher amount is approved by FERC, and PSNH is required to reserve an additional amount under its FERC hydroelectric license conditions.  In addition, certain state statutes may impose additional limitations on the regulated companies.  CL&P, PSNH, WMECO and Yankee Gas also are parties to a revolving credit agreement that imposes leverage restrictions.

Our total debt, including short-term debt, capitalized lease obligations and prior spent nuclear fuel liabilities, but not including RRBs, was approximately $4.8 billion as of December 31, 2008.

During 2008, the NU companies issued an aggregate of $760 million of long-term debt, as follows:  On May 27, 2008, CL&P issued $300 million of 10-year first and refunding mortgage bonds carrying a coupon rate of 5.65 percent, and PSNH issued $110 million of 10-year first mortgage bonds with a coupon rate of 6.00 percent.  On June 5, 2008, NU parent issued $250 million of five-year senior unsecured notes with a coupon rate of 5.65 percent, and on October 7, 2008, Yankee Gas issued $100 million of 10-year first mortgage bonds at 6.9 percent.  In addition, on February 13, 2009, CL&P issued $250 million of 10-year first mortgage bonds at 5.5 percent.

NU parent has a combined credit line and letter of credit (LOC) facility in a nominal aggregate amount of $500 million, including the lending commitment of Lehman Brothers Commercial Bank, Inc. (LBCB) (as discussed below), which expires on November 6, 2010. At December 31, 2008, NU parent had $304 million of borrowings and $87 million of LOCs issued for the benefit of certain subsidiaries outstanding under that facility.  NU parent had approximately $50 million of borrowing availability on this facility as of February 25, 2009, excluding the remaining unfunded commitment of LBCB.  NU also had approximately $466 million of externally invested cash at February 25, 2009.

13

The regulated companies maintain a joint credit facility in a nominal aggregate amount of $400 million, including the lending commitment of LBCB, which also expires on November 6, 2010.  There were $315 million of short-term borrowings outstanding under that facility at December 31, 2008.  We had approximately $1 million of borrowing availability on this facility as of February 25, 2009, excluding the remaining unfunded commitment of LBCB.  NU also had approximately $466 million of externally invested cash at February 25, 2009.

The lenders under these facilities are:  Bank of America, N.A.; Barclays Bank PLC; BNY Mellon, N.A.; Citigroup Inc.; HSBC Bank USA, N.A.; JPMorgan Chase Bank, N.A.; LBCB; Sumitomo Mitsui Banking Corporation (Sumitomo); Toronto Dominion (Texas) LLC; Union Bank of California, N.A.; Wachovia Bank, N.A.; and Wells Fargo Bank, N.A.  Lehman Brothers Holdings Inc., the parent of LBCB, filed for Chapter 11 bankruptcy protection in September 2008.  LBCB's original aggregate lending commitment under the two facilities was $85 million, of which $30 million was assigned to Sumitomo in late September 2008.   At December 31, 2008, LBCB had advanced approximately $19.2 million under the facilities and had declined to fund the remainder of its commitment.  As a result, when current loans from LBCB are repaid, we will be limited to an aggregate of $845 million of borrowing capacity under our credit facilities, which we believe will provide sufficient operating flexibility to maintain adequate amounts of liquidity.

PSNH has outstanding approximately $407 million of PCRBs, one series of which, in the aggregate principal amount of $89.3 million, bears interest at a rate that is periodically set pursuant to auctions.  Since March 2008, a significant majority of this series of PCRBs has been held by remarketing agents as the result of failed auctions due to general market concerns.  The interest rate on these PCRBs has reset by formula under the applicable documents every 35 days and has been between 0.2 percent and 4 percent since March 2008.  The formula is based on a combination of the ratings on the PCRBs and an index rate, which provides for a current interest rate of 0.3 percent.  We are not obligated to purchase these PCRBs, which mature in 2021, from the remarketing agents.

In addition, CL&P has approximately $423.9 million of PCRBs, one series of which, in the aggregate principal amount of $62 million, had a fixed interest rate for a five-year period that expired on September 30, 2008.  CL&P chose to acquire these PCRBs on October 1, 2008 as a result of poor liquidity in the tax-exempt market.  These PCRBs, which mature in 2031, have not been retired, and CL&P expects to remarket them when conditions in the market improve.

Under their revolving credit facility agreements, each of NU, CL&P, WMECO, PSNH and Yankee Gas must maintain a ratio of consolidated debt to total capitalization of no more than 65 percent.  At December 31, 2008, NU, CL&P, WMECO, PSNH, and Yankee Gas were, and are expected to remain, in compliance with this ratio.

For more information regarding NU and its subsidiaries' financing, see "Note 2, "Short-Term Debt," and Note 11, "Long-Term Debt," to the Consolidated Financial Statements and "Liquidity" under Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" in this Annual Report on Form 10-K.

NUCLEAR DECOMMISSIONING

Genera l

CL&P, PSNH, WMECO and other New England electric utilities are the stockholders of three inactive regional nuclear companies, Connecticut Yankee Atomic Power Company (CYAPC), Maine Yankee Atomic Power Company (MYAPC) and Yankee Atomic Electric Company (YAEC) (the Yankee Companies).  The Yankee Companies have completed the physical decommissioning of their respective facilities and are now engaged in the long-term storage of their spent nuclear fuel. Each Yankee Company collects decommissioning 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 recover these costs from their customers through state regulatory commission-approved retail rates.  The ownership percentages of CL&P, PSNH and WMECO in the Yankee Companies are set forth below:

Our share of the obligations to support the Yankee Companies under FERC-approved rules is the same as the ownership percentages above.

For more information regarding decommissioning and nuclear assets, see "Deferred Contractual Obligations" under Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," in this Annual Report on Form 10-K.

14

OTHER REGULATORY AND ENVIRONMENTAL MATTERS

General

We are regulated in virtually all aspects of our business by various federal and state agencies, including the FERC, the SEC, 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 DPU having jurisdiction over WMECO.

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.  PSNH owns generation assets and plans to spend approximately $457 million to install a wet flue gas desulphurization system at Merrimack Station to reduce mercury emissions of its coal fired plants in compliance with current New Hampshire law.  Compliance with additional increasingly stringent environmental laws and regulations, particularly air and water pollution control requirements, may limit operations or require further 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.  We are in the process of obtaining or renewing all required NPDES or state discharge permits in 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.

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 SO2 and nitrogen oxides (NOX) 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 capped NOX, SO2 and carbon dioxide (CO2) emissions for current compliance beginning in 2007.  In addition, a 2006 New Hampshire law requires PSNH to install a wet flue gas desulphurization system, known as "scrubber" technology, to reduce mercury emissions of its coal fired plants by at least 80 percent (with the co-benefit of reductions in SO2 emissions as well).  Wet scrubber technology will be installed at Merrimack Station in Bow, New Hampshire. PSNH currently anticipates that compliance with this law will cost approximately $457 million.  PSNH began site work for this project in November 2008.  The project is scheduled to be completed by the end of 2012.

In addition, Connecticut, New Hampshire and Massachusetts are each members of the Regional Greenhouse Gas Initiative (RGGI).  RGGI is a cooperative effort by ten northeastern and mid-Atlantic states, to develop a regional program for stabilizing and reducing CO2 emissions from fossil fuel-fired electric generating plants.  It is the first market-based, mandatory cap-and-trade program in the U.S. designed to reduce greenhouse gas emissions.  Each of the participating states has regulations in place to cap and then reduce the amount of CO2 that power plants in their region are allowed to emit. Power sector CO2 emissions are capped at current levels through 2014.  The cap will then be reduced by 2.5 percent in each of the four years 2015 through 2018, for a total reduction of 10 percent.  RGGI is composed of individual CO2 budget trading programs in each of the participating states. Each participating state’s CO2 budget trading program establishes its respective share of the regional cap, and each state will issue CO2 allowances in a number equivalent to its portion of the regional cap.  Each CO2 allowance represents a permit to emit one ton of CO2 in a specific year.  The RGGI states will distribute CO2 allowances primarily through regional auctions.

Because CO2 allowances issued by any participating state will be usable across all state programs, the ten individual state CO2 budget trading programs, in the aggregate, will form one regional compliance market for CO2 emissions.  Initial CO2 allowance auctions were held in 2008 as pre-compliance events to facilitate market price discovery and compliance planning by regulated CO2 emitters.  A regulated power plant must hold CO2 allowances equal to its emissions to demonstrate compliance at the end of a three-year compliance period beginning in 2009.

Connecticut adopted regulations in connection with RGGI in July 2008 which established an auction clearing price threshold of $5 per CO2 allowance, above which all auction proceeds will be rebated to customers.  For proceeds up to the clearing price threshold, 69.5 percent will be directed to the conservation and load management programs managed by the state’s utilities in conjunction with the Energy Conservation Management Board.  Seventy-five percent of the RGGI auction proceeds directed to conservation and load management programs will be allocated to CL&P’s programs.  Because CL&P does not own any generating assets, it is not required to acquire CO2 allowances; however, the costs will likely be included in wholesale rates charged to CL&P in standard offer type contracts.

15

Massachusetts law does not set an auction clearing price threshold for RGGI auctions.  The law requires 80 percent of RGGI auction proceeds to be allocated to utility energy efficiency and demand response programs.  Because WMECO does not own any generation assets, it is not required to acquire any CO2 allowances; however, the costs will likely be included in wholesale rates charged to WMECO in standard offer type contracts.

New Hampshire law sets an auction clearing price threshold of $6 per CO2 allowance in 2009, above which all auction proceeds will be rebated to customers.  Proceeds below the threshold are to be used for demand response and energy efficiency programs.

PSNH anticipates that its generating units will emit between 4 million and 5 million tons of CO2 per year after taking into effect the operation of PSNH’s Northern Woods wood-burning generating plant that, under the RGGI formula, decreased PSNH’s responsibility for reducing fossil-fired CO2 emissions by approximately 425,000 tons per year, or almost ten percent.  New Hampshire legislation provides up to 2.5 million banked CO2 allowances per year for PSNH’s fossil fueled generating plants during the 2009-2011 compliance period.  These banked CO2 allowances will initially comprise approximately one-half of the yearly CO2 allowances required for PSNH’s generating plants to comply with RGGI and such banked allowances will decrease over time.  PSNH expects to satisfy its remaining RGGI requirements by purchasing CO2 allowances at auction or in the secondary market.  The cost of complying with RGGI requirements is recoverable from PSNH customers.

The first regional auction of RGGI CO2 allowances took place on September 25, 2008.  Six states offered allowances for sale.  At the auction, more than 12.5 million CO2 allowances were sold at the clearing price of $3.07 per CO2 allowance.  The auction raised $38.6 million for use by the six RGGI states.  The next regional auction took place on December 17, 2008.  All ten RGGI states participated and more than 31.5 million CO2 allowances were sold at a clearing price of $3.38 per allowance.  The auction raised $106.5 million for use by the ten RGGI states.  For 2009, four quarterly regional auctions are scheduled for March, June, September and December.

Each of the states in which we do business also has renewable portfolio standards (RPS).  New Hampshire’s renewable portfolio standards provision requires increasing percentages of the electricity sold to retail customers in the state, beginning in 2008, to have direct ties to renewable sources, ultimately reaching 23.8 percent by 2025. PSNH is 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.  Connecticut's RPS statutes require that a specific percentage of the generation provided to Connecticut consumers be produced from renewable energy sources such as solar, hydropower, landfill gas, fuel cells and other similar sources.  Beginning with a 4 percent requirement in 2004, the requirement increases each year.  For 2009, the requirement is 12 percent, increasing to 14 percent by 2010, 19.5 percent by 2015 and 27 percent by 2020.  Massachusetts’ RPS program required electricity suppliers to meet a 1 percent renewable energy standard in 2003, which increased to 4 percent for 2009 and has a goal of 15 percent by 2015.

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 emissions than are currently in effect.

Hazardous Materials Regulations

Prior to the last quarter of the 20th century when environmental best practices and laws were implemented, 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, government agencies and private parties can attempt to impose liability on us for such past disposal.  At December 31, 2008, the liability recorded by us for our estimable environmental remediation costs for known sites needing investigation and/or remediation, exclusive of recoveries from insurance or from third parties, was approximately $27.4 million, representing 54 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 or when additional information as to the extent of contamination becomes available.

The most significant liabilities currently relate to future clean up costs at former manufactured gas plant (MGP) 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 $27.4 million, a reserve of approximately $25.4 million has been established to address future investigation and/or remediation costs at MGP sites.  In addition, Holyoke Water Power Company (HWP), a wholly-owned subsidiary of NU, is continuing to evaluate additional potential remediation requirements at a river site in Massachusetts containing tar deposits associated with a MGP, which it sold to Holyoke Gas and Electric (HG&E), a municipal electric utility, in 1902.  HWP and HG&E share responsibility for the site. HWP has already conducted substantial investigative and remediation activities.

The Massachusetts Department of Environmental Protection (MA DEP) issued a letter on April 3, 2008 to HWP and HG&E, providing conditional authorization for additional investigatory and risk characterization activities and providing detailed comments on HWP’s 2007 reports and proposals for further investigations.  MA DEP also indicated that further removal of tar in certain areas was necessary prior to commencing many of the additional studies and evaluation.  HWP has developed and begun to implement plans for

16

additional investigations in conformity with MA DEP’s guidance letter, including estimated costs and schedules.  These matters are subject to ongoing discussions with MA DEP and HG&E and may change from time to time.

There are many outcomes that could affect our estimates and require an increase to the reserve, or range of costs, and a reserve increase would be reflected as a charge to pre-tax earnings.  However, we cannot reasonably estimate the range of additional investigation and remediation costs because they will depend on, among other things, the level and extent of the remaining tar that may be required to be remediated, the extent of HWP’s responsibility and the related scope and timing, all of which are difficult to estimate because of a number of uncertainties at this time.  Further developments may require a material increase to this reserve.

HWP's share of the remediation costs related to this site is not recoverable from customers.

For further information on environmental liabilities, see Note 7B, "Commitments and Contingencies - Environmental Matters" to the Consolidated Financial Statements contained in this Annual Report on Form 10-K.

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, have concluded that the available body of scientific information does not support the conclusion that EMF affects human health.

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, we 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 2036.  As a licensee under the 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.  A new FERC license for PSNH’s Merrimack River Hydroelectric Project, which consists of the Amoskeag, Hooksett and Garvins Falls generating stations, was issued on May 18, 2007.  PSNH's Canaan Hydroelectric Project is currently undergoing relicensing proceedings.  On January 16, 2009, FERC issued a new license for this project.  The new license takes effect upon the July 3, 2009 expiration of its current license.  The water quality certification associated with this new license has been appealed to the Vermont Environmental Court.

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.

17

EMPLOYEES

As of December 31, 2008, we employed a total of 6,189 employees, excluding temporary employees, of which 1,944 were employed by CL&P, 1,268 by PSNH, 366 by WMECO, 417 by Yankee Gas and 2,182 were employed by Northeast Utilities Service Company (NUSCO).  Approximately 2,300 employees of CL&P, PSNH, WMECO, NUSCO and Yankee Gas are covered by 11 union agreements.

INTERNET INFORMATION

Our website address is www.nu.com.  We make available through our website a link to the SEC's IDEA site, at which site NU's, CL&P's, WMECO's and PSNH's Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current 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.

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 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.

The global financial crisis may have impacts on our business and financial condition that we currently cannot predict.

The continued credit crisis and related turmoil in the global financial system may have an impact on our business and our financial condition.  The extreme disruption in the capital markets has limited companies’ ability to access the capital and credit markets to support their operations and refinance debt and has led to higher financing costs compared to recent years. We use short-term debt and the long-term capital markets as a significant source of liquidity and funding for capital requirements not satisfied by our operating cash flow, including construction costs.  The cost of debt financing and the proceeds of equity financing may be materially adversely impacted by these market conditions.  The inability to raise capital on favorable terms could negatively affect our ability to maintain and to expand our businesses.  Our current credit ratings cause us to believe that we will continue to have access to the capital markets. However, events beyond our control, such as the disruption in global capital and credit markets in 2008, may create uncertainty that could increase our cost of capital or impair our ability to access the capital markets.  In addition, certain of NU parent’s subsidiaries rely, in part, on NU parent for access to capital.  Circumstances that limit NU parent’s access to capital could impair its ability to provide those companies with needed capital.  The credit crisis could also have an impact on our lenders or our customers, causing them to fail to meet their obligations to us.  Additionally, the crisis could have a broader impact on business in general in ways that could lead to reduced electricity and gas usage, which could have a negative impact on our revenues.

In addition, the consequences of a prolonged recession may include a lower level of economic activity and uncertainty regarding energy prices.  A lower level of economic activity might result in a decline in energy consumption, which may adversely affect our revenues and future growth.  Current economic conditions may be exacerbated by insufficient financial sector liquidity leading to potential increased unemployment, which may impact customers’ ability to pay bills in a timely manner and increase customer bankruptcies, which may lead to increased bad debt expenses.

Changes in regulatory 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 may 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

18

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.  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 limited 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.

Increases in electric and gas prices, the continued economic slowdown 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 significant increases in energy prices, particularly fossil fuels, as well as by a general economic slowdown.  The impact of these increases has led to increased electricity and natural gas prices for our customers, which, coupled with the continued economic slowdown, 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.  If any such declines were to occur without corresponding adjustments in rates, then our revenues would be reduced and our future growth 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 rights or facilitate competition for construction of large-scale transmission projects, which could adversely affect our earnings.

We have undertaken a substantial transmission capital investment program and expect to invest approximately $3.5 billion in regulated electric transmission infrastructure from 2009 through 2013.

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 and/or legislative policy could 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 by the Transmission Operating 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 after February 1, 2010.  In addition, after that date, other parties, such as state regulators, may seek certain changes to the regional cost allocation, which could have adverse effects on our distribution companies' local rates.  We are working to retain the existing regional cost allocation treatment but cannot predict the actions of the states or utilities in the region.

Changes in regulatory 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 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

19

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 regulatory 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 meet 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.

Judicial or regulatory proceedings or changes in regulatory or legislative policy could jeopardize completion of, or full recovery of costs incurred by PSNH in constructing, the Clean Air Project.

Pursuant to New Hampshire law, PSNH has begun work on the Clean Air Project at its Merrimack Station in Bow, New Hampshire. As a result of an increase in the estimated cost of the project from $250 million to $457 million, several parties have initiated legal proceedings challenging the project.  These proceedings, or new legislation, regulations or judicial or regulatory interpretations of applicable law or regulations could result in the delay or cancelation of this project or add to its cost.  Any delay or cancelation of the project would adversely affect our ability to achieve forecast levels of earnings.  If the project were to be canceled, contract payments and termination costs would be a substantial portion of the contractual commitments entered into by PSNH. As of March 31, 2009, the contractual commitments are expected to total approximately $250 million.  The actual amount of contract termination costs would depend on timing of the cancelation and negotiations with the contractors.  At this time, we cannot predict any legislative or regulatory changes or the outcome of the pending legal proceedings.

In addition, PSNH’s investment in the project after it is completed is subject to prudence review by the NHPUC at the time the project is placed in service.  A prudence disallowance of a material nature could adversely affect PSNH’s cash flows and results of operations. While we believe that all expenditures to date have been prudently incurred, we cannot predict the outcome of any prudency reviews should they occur.  Our projected earnings and growth could be adversely affected were the NHPUC to deny recovery of some or all of PSNH’s investment in the project.

The loss of key personnel or the inability to hire and retain qualified employees could have an adverse effect on our business, financial condition and results of 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, but cannot predict the impact of these plans on our ability to hire and retain key employees.

Grid disturbances, severe weather, or acts of war or terrorism could negatively impact our 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, such as the ice storm that impacted New Hampshire in December 2008, 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.

20

A negative change in NU's credit ratings could require NU parent to post cash collateral and affect our ability to obtain financing.

NU parent’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, 2008, collateral in the form of cash or letters of credit in the amount of $23.2 million to unaffiliated counterparties and cash or letters of credit in the amount of $10 million to two independent system operators.  While our credit facilities are sufficient in amounts that would be adequate to meet collateral calls at that level, our ability to meet any future collateral calls would depend on our liquidity and access to bank lines and the capital markets at such time.

Changes in wholesale electric sales could require Select Energy to acquire or sell additional electricity on unfavorable terms.

Select Energy's remaining wholesale sales contracts provide electricity to full requirements customers, including a municipal electric company.  Select Energy provides a portion of the customer's electricity 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 economic activity and weather.  The varying sales volumes may differ from the supply volumes that Select Energy expected to utilize from electricity purchase contracts.  Differences between actual sales volumes and supply volumes may require Select Energy to purchase additional electricity or sell excess electricity, both of which are subject to market conditions which change due to weather, plant availability, transmission congestion, and input fuel costs.  The purchase of additional electricity at high prices or sale of excess electricity at low prices could negatively impact Select Energy's cost to serve the contracts.

Costs of compliance with environmental regulations may increase and have an adverse effect on our business and results of operations.

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.  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 existing 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.

In addition, global climate change issues have received an increased focus on the federal and 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 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" in this Annual Report on Form 10-K.

We are subject to legal proceedings which could result in large cash obligations.  

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

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

Item 1B.

KV; 34,897 pole miles of overhead and 2,925 conduit bank miles of underground distribution lines; and 536,203 underground and overhead line transformers in service with an aggregate capacity of 36,730,940 kVa.

*Claimed capability represents winter ratings as of December 31, 2008.  The nameplate capacity of the generating plants is approximately 1,200 MW.

Neither CL&P nor WMECO owned any electric generating plants during 2008.

Yankee Gas

At December 31, 2008, 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.  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, Supplier of Last 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 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, would be eligible to purchase the generation plant upon obtaining prior approval from the DPUC and a determination by the DPUC that such purchase is in the public interest.  

PSNH.  The NHPUC, pursuant to statutory 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.  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.  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.  On December 31, 2008, WMECO purchased all of the transmission-related assets of its affiliates, HWP and HP&E, for approximately $4 million.

22

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 DPU (then, the Department of Telecommunications and Energy) was required to define service territories for each distribution company, including WMECO.  The DPU subsequently determined that there were advantages to the exclusivity of service territories and issued a report to the Massachusetts Legislature recommending against, in this regard, any changes to the restructuring legislation.

Holyoke Water and Power Company and Holyoke Power and Electric Company.  HWP, and its wholly owned subsidiary HP&E, are authorized by their charters to conduct their businesses in the territories served by them.  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.  

Prior to December 31, 2008, the two companies had locations in the public highways for their transmission lines.  Such locations were granted pursuant to the laws of Massachusetts by the Massachusetts Department of Public Works 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.  On December 31, 2008, HWP and HP&E sold all of their transmission-related assets to WMECO.

Yankee 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’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’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 facilities on public highways and 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.

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. The trial has been scheduled for April 2009.

3.

Other Legal Proceedings

For further discussion of legal proceedings see the following sections of Item 1, "Business": "Regulated Electric Distribution," "Regulated Gas Operations," and "Regulated Electric Transmission" for information about various state regulatory and rate proceedings, civil lawsuits related thereto, and information about proceedings relating to power, transmission and pricing issues; "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.

2007; President - Transmission Group of NU from January 17, 2005 to December 1, 2005; and President and Chief Operating Officer of CL&P from September 2001 to January 2005.

Shirley M. Payne.  Ms. Payne was elected Vice President - Accounting and Controller of NU effective February 13, 2007, and Vice President - Accounting and Controller of CL&P, PSNH and WMECO effective January 29, 2007.  Previously, Ms. Payne served as Vice President, Corporate Accounting and Tax of TECO Energy, Inc., from July 2000 to January 26, 2007, and Tax Officer of TECO Energy, Inc., from April 1999 to January 26, 2007.

James B. Robb.  Mr. Robb was elected Senior Vice President, Enterprise Planning and Development of NUSCO on September 4, 2007.  Previously, Mr. Robb served as 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; and Senior Vice President, Performance Management, Reliant Resources, Inc. from November 2002 to December 2003.

Charles W. Shivery.  Mr. Shivery was elected Chairman of the Board, President and Chief Executive Officer of NU effective March 29, 2004; Chairman and a Director of CL&P, PSNH and WMECO effective January 19, 2007 and a Director of Northeast Utilities Foundation effective March 3, 2004. Previously, Mr. Shivery served as President (interim) of NU from January 1, 2004 to March 29, 2004; and President - Competitive Group of NU and President and Chief Executive Officer of NU Enterprises, Inc., from June 2002 through December 2003.

There are no family relationships between any executive officer and any Trustee or other executive officer of NU and none of the above executive officers serve as an executive officer pursuant to any agreement or understanding with any other person.  

On May 12, 2008, our Board of Trustees declared a dividend of 21.25 cents per share, payable on September 30, 2008, to shareholders of record as of September 1, 2008.

On April 8, 2008, our Board of Trustees declared a dividend of 20 cents per share, payable on June 30, 2008, to shareholders of record as of June 1, 2008.

On February 12, 2008, our Board of Trustees declared 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 cents per share, payable on June 29, 2007, to shareholders of record as of 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.  

Information with respect to dividend restrictions for 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 "Combined Notes to Consolidated Financial Statements," within this Annual Report on Form 10-K.   

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

During 2008 and 2007, CL&P approved and paid $106.5 million and $79.2 million, respectively, of common stock dividends to NU.

During 2008 and 2007, PSNH approved and paid $36.4 million and $30.7 million, respectively, of common stock dividends to NU.

During 2008 and 2007, WMECO approved and paid $39.7 million and $12.8 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 Annual Report on Form 10-K.  

26