CONNECTICUT LIGHT & POWER CO - Annual Report: 2009 (Form 10-K)

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

FORM 10-K

[X]	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE      SECURITIES EXCHANGE ACT OF 1934
	For the Fiscal Year Ended December 31, 2009
	OR
[  ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE      SECURITIES EXCHANGE ACT OF 1934
	For the transition period from ____________ to ____________

Commission File Number	Registrant; State of Incorporation; Address; and Telephone Number	I.R.S. Employer Identification No.
1-5324	NORTHEAST UTILITIES (a Massachusetts voluntary association) One Federal Street Building 111-4 Springfield, Massachusetts 01105 Telephone:  (413) 785-5871	04-2147929
0-00404	THE CONNECTICUT LIGHT AND POWER COMPANY (a Connecticut corporation) 107 Selden Street Berlin, Connecticut 06037-1616 Telephone:  (860) 665-5000	06-0303850
1-6392	PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE (a New Hampshire corporation) Energy Park 780 North Commercial Street Manchester, New Hampshire 03101-1134 Telephone:  (603) 669-4000	02-0181050
0-7624	WESTERN MASSACHUSETTS ELECTRIC COMPANY (a Massachusetts corporation) One Federal Street Building 111-4 Springfield, Massachusetts 01105 Telephone:  (413) 785-5871	04-1961130

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act:

	$1.90	Series	of 1947
	$2.00	Series	of 1947
	$2.04	Series	of 1949
	$2.20	Series	of 1949
	3.90%	Series	of 1949
	$2.06	Series E	of 1954
	$2.09	Series F	of 1955
	4.50%	Series	of 1956
	4.96%	Series	of 1958
	4.50%	Series	of 1963
	5.28%	Series	of 1967
	$3.24	Series G	of 1968
	6.56%	Series	of 1968

Public Service Company of New Hampshire and Western Massachusetts Electric Company meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and are therefore filing this Form 10-K with the reduced disclosure format specified in General Instruction I(2) to Form 10-K.  

Indicate by check mark if the registrants are well-known seasoned issuers, as defined in Rule 405 of the Securities Act.

	Yes	No
	ü

Indicate by check mark if the registrants are not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

	Yes	No
		ü

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

	Yes	No
	ü

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrants' knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  [ü]

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

	Large Accelerated Filer		Accelerated Filer		Non-accelerated Filer
Northeast Utilities	ü
The Connecticut Light and Power Company					ü
Public Service Company of New Hampshire					ü
Western Massachusetts Electric Company					ü

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

	Yes	No
Northeast Utilities		ü
The Connecticut Light and Power Company		ü
Public Service Company of New Hampshire		ü
Western Massachusetts Electric Company		ü

The aggregate market value of Northeast Utilities’ Common Shares, $5.00 par value, held by non-affiliates, computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of Northeast Utilities’ most recently completed second fiscal quarter (June 30, 2009) was $3,909,588,738 based on a closing sales price of $22.31 per share for the 175,239,298 common shares outstanding on June 30, 2009.  Northeast Utilities holds all of the 6,035,205 shares, 301 shares, and 434,653 shares of the outstanding common stock of The Connecticut Light and Power Company, Public Service Company of New Hampshire and Western Massachusetts Electric Company, respectively.

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

Company - Class of Stock	Outstanding as of January 31, 2010
Northeast Utilities Common shares, $5.00 par value	175,692,984 shares
The Connecticut Light and Power Company Common stock, $10.00 par value	6,035,205 shares
Public Service Company of New Hampshire Common stock, $1.00 par value	301 shares
Western Massachusetts Electric Company Common stock, $25.00 par value	434,653 shares

Documents Incorporated by Reference:

Description				Part of Form 10-K into Which Document is Incorporated
Portions of the Northeast Utilities Proxy Statement expected to be dated April 1, 2010				Part III

GLOSSARY OF TERMS

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

CURRENT OR FORMER NU COMPANIES, SEGMENTS OR INVESTMENTS

Boulos	E. S. Boulos Company
CL&P	The Connecticut Light and Power Company
HWP	HWP Company, formerly Holyoke Water Power Company
NAESCO	North Atlantic Energy Service Corporation
NGC	Northeast Generation Company
NGS	Northeast Generation Services Company and subsidiaries
NU or the Company	Northeast Utilities and subsidiaries
NU Enterprises	NU Enterprises, Inc. is the parent company of Select Energy, Boulos, NGS, and SECI.  For further information, see Note 17, "Segment Information," to the Consolidated Financial Statements.
NUSCO	Northeast Utilities Service Company
NU parent and other companies	NU parent and other companies is comprised of NU parent, NUSCO, and other subsidiaries, including HWP, The Rocky River Realty Company (a real estate subsidiary), Mode 1 Communications, Inc. (telecommunications) and the non-energy-related subsidiaries of Yankee (Yankee Energy Services Company and Yankee Energy Financial Services Company).
PSNH	Public Service Company of New Hampshire
Regulated companies	NU's regulated companies, comprised of the electric distribution and transmission segments of CL&P, PSNH and WMECO, the generation segment of PSNH, and Yankee Gas, a natural gas local distribution company.  For further information, see Note 17, "Segment Information," to the Consolidated Financial Statements.
SECI	Select Energy Contracting, Inc.
Select Energy	Select Energy, Inc.
SESI	Select Energy Services, Inc.
WMECO	Western Massachusetts Electric Company
Yankee	Yankee Energy System, Inc.
Yankee Gas	Yankee Gas Services Company

REGULATORS

CDEP	Connecticut Department of Environmental Protection
DOE	United States Department of Energy
DPU	Massachusetts Department of Public Utilities
DPUC	Connecticut Department of Public Utilities
FERC	Federal Energy Regulatory Commission
NHPUC	New Hampshire Public Utilities Commission
SEC	Securities and Exchange Commission

i

OTHER

ii

NORTHEAST UTILITIES

THE CONNECTICUT LIGHT AND POWER COMPANY

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE

WESTERN MASSACHUSETTS ELECTRIC COMPANY

2009 Form 10-K Annual Report
Table of Contents

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NORTHEAST UTILITIES

THE CONNECTICUT LIGHT AND POWER COMPANY

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE

WESTERN MASSACHUSETTS ELECTRIC COMPANY

SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES

LITIGATION REFORM ACT OF 1995

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

From time to time we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, assumptions of future events, financial performance or growth and other statements that are not historical facts.  These statements are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995.  You can generally identify our forward-looking statements through the use of words or phrases such as "estimate," "expect," "anticipate," "intend," "plan," "project," "believe," "forecast," "should," "could," and other similar expressions.  Forward-looking statements are based on the current expectations, estimates, assumptions or projections of management and are not guarantees of future performance.  These expectations, estimates, assumptions or projections may vary materially from actual results.  Accordingly, any such statements are qualified in their entirety by reference to, and are accompanied by, the following important factors that could cause our actual results to differ materially from those contained in our forward-looking statements, including, but not limited to:

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actions or inaction by local, state and federal regulatory bodies

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changes in business and economic conditions, including their impact on interest rates, bad debt expense, and demand for our products and services

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changes in weather patterns

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changes in laws, regulations or regulatory policy

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changes in levels and timing of capital expenditures

·

disruptions in the capital markets or other events that make our access to necessary capital more difficult or costly

·

developments in legal or public policy doctrines

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technological developments

·

changes in accounting standards and financial reporting regulations

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fluctuations in the value of our remaining competitive electricity positions

·

actions of rating agencies, and

·

other presently unknown or unforeseen factors.  

Other risk factors are detailed in our reports filed with the Securities and Exchange Commission (SEC) and updated from time to time, and we encourage you to consult such disclosures.

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

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NORTHEAST UTILITIES

THE CONNECTICUT LIGHT AND POWER COMPANY

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE

WESTERN MASSACHUSETTS ELECTRIC COMPANY

PART I

Item 1.

Business

NU, headquartered in Hartford, Connecticut, is a public utility holding company subject to regulation by the Federal Energy Regulatory Commission (FERC) under the Public Utility Holding Company Act of 2005. We are engaged primarily in the energy delivery business through the following wholly-owned utility subsidiaries:

●

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

●

Public Service Company of New Hampshire (PSNH), a regulated electric utility which serves residential, commercial and industrial customers in parts of New Hampshire and continues to own generation assets used to serve customers;

●

Western Massachusetts Electric Company (WMECO), a regulated electric utility which serves residential, commercial and industrial customers in parts of western Massachusetts; and

●

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

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

NU also owns certain unregulated businesses through its wholly-owned subsidiary, NU Enterprises, Inc. (NU Enterprises).  We have exited most of these businesses. As of December 31, 2009, NU Enterprises’ remaining business consisted of (i) Select Energy Inc.’s few remaining energy wholesale marketing contracts, and (ii) NU Enterprises’ remaining electrical contracting business.

Although NU, CL&P, PSNH and WMECO each report their financial results separately, we also include information in this report on a segment, or line-of-business basis.  The regulated companies include three business segments: the electric distribution segment (which includes PSNH’s regulated generation activities), the natural gas distribution segment, and the electric transmission segment. The regulated companies’ segment of our business represented approximately 98 percent of our total earnings of $330 million for 2009, with electric distribution (including PSNH’s generation activities) representing approximately 41.9 percent, electric transmission representing approximately 49.8 percent, and natural gas distribution representing approximately 6.4 percent.  The remaining two percent of our 2009 earnings come from our competitive businesses, which are being wound down.  See "Overview - Competitive Businesses" in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, in this Annual Report on Form 10-K.

For information regarding each of NU’s segments, see Note 17, "Segment Information," to the Consolidated Financial Statements in this Annual Report on Form 10-K.

REGULATED ELECTRIC DISTRIBUTION

General

NU’s distribution segment is made up of the distribution businesses of CL&P, PSNH and WMECO, which are primarily engaged in the distribution of electricity in Connecticut, New Hampshire and western Massachusetts, respectively, plus PSNH’s regulated electric generation business.  The following table shows the sources of 2009 electric franchise retail revenues for NU’s electric distribution companies, collectively, based on categories of customers:

	Sources of Revenue		Total Operating Companies
	Residential		58%
	Commercial		34%
	Industrial		7%
	Other		1%
	Total		100%

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A summary of changes in the regulated companies’ retail electric gigawatt-hour (GWh) sales for 2009 as compared to 2008 on an actual and weather normalized basis (using a 30-year average) is as follows:

		Electric
		CL&P				PSNH				WMECO				Total
		Percentage Decrease		Weather Normalized Percentage Increase/ (Decrease)		Percentage Decrease		Weather Normalized Percentage Increase/ (Decrease)		Percentage Increase/ (Decrease)		Weather Normalized Percentage Increase/ (Decrease)		Percentage Decrease		Weather Normalized Percentage Increase/ (Decrease)
Residential		(0.7)%		1.5 %		(0.2)%		0.6 %		(1.6)%		0.2 %		(0.7)%		1.2 %
Commercial		(2.9)%		(1.4)%		(1.5)%		(0.7)%		(4.8)%		(3.4)%		(2.8)%		(1.5)%
Industrial		(17.6)%		(16.6)%		(8.2)%		(7.1)%		(11.7)%		(10.9)%		(14.1)%		(13.1)%
Other		(2.5)%		(2.5)%		(3.2)%		(3.2)%		12.7 %		12.7 %		(1.6)%		(1.6)%
Total		(3.8)%		(2.1)%		(2.2)%		(1.4)%		(4.8)%		(3.4)%		(3.5)%		(2.1)%

Retail electric sales in 2009 were lower than 2008 and were significantly impacted by the weather and economic conditions.  The spring and summer months in 2009 were significantly cooler than normal and when compared to 2008, the amount of cooling degree days, a unit of measurement used to relate a day's temperature to the energy demands of air conditioning, was approximately 23 percent lower in Connecticut and Western Massachusetts and approximately 22 percent lower in New Hampshire.  The negative trend in our sales continues to be most prevalent in the industrial class where many customers have been negatively impacted by the weak economic conditions of our region and nation.  We believe the reduction in industrial sales is primarily driven by a reduced number of shifts and days of operations.  Commercial sales and residential sales in 2009 were also lower than 2008, although residential sales increased by 1.2 percent over 2008 on a weather-normalized basis.  In 2010, we expect economic conditions to continue to affect our customers, and we estimate our retail electric sales across all three states will be approximately 1 percent lower than 2009 on a weather-normalized basis.

Recovery of our distribution revenues, however, is not wholly dependent on sales and it varies between customer classes.  About two-thirds of CL&P’s and WMECO’s distribution revenues and about one-half of PSNH’s distribution revenue are recovered through charges, such as the customer charge and demand charge, that are not dependent on overall sales volumes.  As compared to other customer classes, a greater portion of residential revenues is recovered through volumetric charges.  In contrast to residential rates, a greater portion of commercial and industrial revenues is recovered through fixed charges not dependent on volume.  Distribution rates for certain large businesses are structured so that we recover 100 percent of the distribution revenues through non-volumetric charges. In this regard, rate design has significantly mitigated the impact of declining commercial and industrial sales on distribution revenues and earnings.

Our expense related to uncollectible receivable balances (our uncollectibles expense) for all of our regulated companies is influenced by the weak economic conditions of our region, which continue to have a negative effect on our customers.  Fluctuations in our uncollectibles expense are mitigated, however, from an earnings perspective because a portion of the total uncollectibles expense for each of the electric distribution companies is allocated to the respective company’s energy supply rate and recovered through its tariffs. Additionally, for CL&P and Yankee Gas, write-offs of uncollectible receivable balances attributable to qualified customers under financial or medical duress (or hardship customers) are fully recovered through their respective tariffs.  In 2009, our total uncollectibles expense was approximately $21 million higher than 2008 and approximately $19 million of the increase impacted our 2009 earnings. The majority of the $19 million increase was incurred by Yankee Gas and CL&P.  In 2010, we expect the uncollectibles expense that impacts earnings to be approximately $12 million lower than it was in 2009 and approximately $10 million of the $12 million improvement is expected to be recognized by Yankee Gas.  The anticipated decrease in 2010 uncollectibles expense is based on continued account receivable collection efforts, a decline in overall Yankee Gas revenues as a result of lower natural gas prices, and an expectation that the economic conditions will begin to improve.

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.  As of December 31, 2009, 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.  CL&P has contracts with two Independent Power Producers (IPPs) to purchase electricity monthly in amounts aggregating approximately 1.5 million MWh per year through March 2015 under one of these contracts and 0.1 million MWh per year through December 2020 under the second contract. CL&P sells the output of these contracts in the spot market operated by the New England Independent System Operator (ISO-NE).

The following table shows the sources of 2009 electric franchise retail revenues for CL&P based on categories of customers:

	CL&P
	Residential		62%
	Commercial		32%
	Industrial		5%
	Other		1%
	Total		100%

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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), systems benefits charge (SBC) and other charges that are assessed on all customers.

The CTA is a charge assessed to recover stranded costs associated with electric restructuring as well as various IPP contracts.  The SBC recovers costs associated with various hardship and low income programs as well as payments to municipalities to compensate them for losses in property tax revenue due to decreases in the value of electric generating facilities resulting directly from electric restructuring.  The CTA and SBC are annually reconciled to true up to actual costs.

Under state law, all of CL&P's customers are entitled to choose their energy suppliers while CL&P remains 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 the cost to customers through a combined "Generation Service Charge" (GSC) and "Bypassable Federally Mandated Congestion Charge" (BFMCC) on customers' bills.  The combined GSC and BFMCC charges for both types of service recover all of the costs of procuring energy from CL&P's wholesale suppliers and are adjusted periodically and reconciled semi-annually in accordance with the directives of the DPUC.

Although more CL&P customers chose competitive energy suppliers in 2009, CL&P continues to supply approximately 50 percent of its customer load at Standard Service rates or Supplier of Last Resort Service rates while the other 50 percent of its customer load has migrated to competitive energy suppliers. The majority of this load migration is from large 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.

Distribution Rates:  CL&P implemented new distribution rates in 2009 to reflect the DPUC's 2008 rate decision allowing a $20.1 million annualized increase in distribution rates, effective February 1, 2009.  

On January 8, 2010, CL&P filed an application with the DPUC to raise distribution rates by $133.4 million, effective July 1, 2010, and by an additional $44.2 million, effective July 1, 2011.  Among other items, CL&P is seeking an increase in its authorized return on equity (ROE) from the current 9.4 percent to 10.5 percent.  CL&P proposed that the first year’s increase be deferred until January 1, 2011 and that the projected $67 million of deferred revenue from the second half of 2010 be recovered from CL&P customers between January 1, 2011 and June 30, 2012.  If approved by the DPUC, the application would require an annualized $210 million increase in distribution rates to take effect on January 1, 2011.  However, CL&P believes that as a result of the decline in stranded cost recoveries due to the final amortization of CL&P’s rate reduction bonds in December 2010, CL&P’s CTA will decline by approximately $230 million on an annualized basis on January 1, 2011, more than offsetting the impact of the distribution rate increase.  A DPUC decision in the case is expected in mid-2010.

CL&P has a transmission adjustment clause as part of its rates, which reconciles on a semi-annual basis the transmission revenues billed to customers against the transmission costs of acquiring such services, thereby recovering all of its transmission expenses on a timely basis.  (See "Regulated Electric Transmission" in this Item 1, Business in this Annual Report on Form 10-K).

For further information on CL&P rates and regulatory actions affecting CL&P, 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.

On December 1, 2009, CL&P filed with the DPUC the results of a three-month dynamic pricing smart meter pilot program that involved nearly 3,000 customers (1,500 residential and 1,500 commercial and industrial (C&I) customers).  CL&P plans to file a smart metering and dynamic pricing plan with the DPUC by March 31, 2010.  The total cost of the pilot program was approximately $13 million and is being recovered through CL&P FMCC rates.  

 

Sources and Availability of Electric Power Supply

As noted above, CL&P does not own any generation assets and purchases energy 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 load 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 contracts in place with various suppliers for all of its Standard Service loads and Supplier of Last Resort Service loads through 2010 and for approximately 60 percent of expected load for 2011 and 20 percent of expected load in 2012.  

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.  As of December 31, 2009, PSNH furnished retail franchise electric service to approximately 490,000 retail customers in 211 cities and towns in New Hampshire.  PSNH also owns and operates approximately 1,200 MW of electricity generation assets.  Included in those generation assets is a 50 MW wood-burning generating

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unit (Northern Wood Power Project) at its Schiller Station in Portsmouth, New Hampshire and approximately 70 MW of hydroelectric generating units.  PSNH also has contracts with certain IPPs, the output of which it uses to serve its customer load or sell into the market.

The following table shows the sources of 2009 electric franchise retail revenues based on categories of customers:

	PSNH
	Residential		49%
	Commercial		39%
	Industrial		11%
	Other		1%
	Total		100%

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 of 9.81 percent on its generation assets.  PSNH defers for future recovery or refund any difference between its ES revenues and the actual costs incurred.

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 files with the NHPUC an ES/SCRC reconciliation filing for the preceding year.  The difference between ES/SCRC revenues and ES/SCRC costs are included in the ES/SCRC rate calculation and refunded to/recovered from customers in the subsequent period approved by the NHPUC.  The NHPUC’s last order, issued in December 2009, had no material impact on PSNH.

The Transmission Cost Adjustment Mechanism (TCAM) allows PSNH to recover on a fully reconciling basis its transmission related costs.  The TCAM is adjusted July 1 of each year.

Distribution Rates:  In April 2009, PSNH filed an application with the NHPUC seeking a temporary increase of $36.4 million in distribution rates on an annualized basis, effective August 1, 2009, and on June 30, 2009, PSNH filed an application requesting a permanent increase of approximately $51 million on an annualized basis to be effective on August 1, 2009, and another $17 million effective July 1, 2010.  The application also requested a regulatory ROE of 10.5 percent.  On July 31, 2009, the NHPUC approved a settlement agreement on a temporary rate increase of $25.6 million effective August 1, 2009.  PSNH expects a decision on the permanent rate application in mid-2010.  Any differences between temporary and permanent rates will be reconciled back to August 1, 2009.  

For further information on PSNH’s rates and regulatory actions affecting it, 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, a wood-burning unit which replaced one of the three 50 MW coal-fired boiler units at the 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, production tax credits, and avoided CO₂ allowance costs under regulations pursuant to the Regional Greenhouse Gas Initiative (RGGI).  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.  Revenue sources exceeded stipulated levels in 2009 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 $13 million of incremental revenues for 2009.  

 

PSNH's customers are entitled to choose competitive energy suppliers, with PSNH providing default energy service under its ES rate for those customers who do not elect to use a third party supplier.  Prior to 2009, PSNH experienced only a minimal amount of customer migration.  However, PSNH’s customer migration levels increased significantly in 2009 as energy costs decreased from their historic high levels.  Third party energy suppliers with more pricing flexibility were able to offer electricity supply at lower prices than PSNH.  At December 31, 2009, approximately 28.1 percent of PSNH’s customers, mostly large commercial and industrial customers, had switched to other energy suppliers.  The increased level of migration has caused an increase in the ES rate, as fixed costs must be spread over lower sales volume and a smaller group of customers.  The customers that did not switch to a third party supplier, predominately residential and small commercial/industrial customers, are now paying a larger proportion of these fixed costs.

PSNH cannot predict if the upward pressure on ES rates will continue into the future, as future customer migration levels, which are dependent on market prices and supplier alternatives, are uncertain.  If future market prices once more exceed the ES rate level, some or all of these customers on third party supply may migrate back to PSNH.  

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PSNH is constructing its Clean Air Project, a sulfur dioxide and mercury scrubber at its Merrimack coal-fired generation station, currently expected to cost $457 million.  The project is expected to be under budget and completed in mid-2012.  PSNH will recover all related costs through its ES rates.  PSNH has spent approximately $146.8 million on the project to date, of which $119.3 million was capitalized in 2009.  Construction of the project was approximately 34 percent complete as of December 31, 2009.

Sources and Availability of Electric Power Supply

During 2009, about 67.7 percent of PSNH’s load was met through its own generation, long-term power supply provided pursuant to orders of the NHPUC, and contracts with third parties.  The remaining 32.3 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 2010 in a similar manner.  

New Hampshire’s "Electric Renewable Portfolio Standard Act" establishes renewable portfolio standards (RPS) for electricity sold in the state and requires 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.  For each MWh of energy produced from a qualifying resource, the producer will receive one REC. Energy suppliers, like PSNH, purchase RECs from these producers and use them to satisfy the RPS requirements.  PSNH also owns renewable sources and uses internally generated RECs in meeting its RPS obligations.  To the extent that PSNH is unable to purchase sufficient RECs, it makes 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 recovered by PSNH through its ES rates.  For further information, 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.

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, 2009, WMECO furnished retail franchise electric service to approximately 205,000 retail customers in 59 cities and towns in the western third of Massachusetts.  WMECO does not own any electricity generating facilities.  WMECO has contracts with two IPPs, the output of which WMECO sells into the market.

The following table shows the sources of 2009 electric franchise retail revenues based on categories of customers:

	WMECO
	Residential		58%
	Commercial		32%
	Industrial		9%
	Other		1%
	Total		100%

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, acquisition of 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 WMECO remains 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 recovers certain costs through various tracking mechanisms in its retail rates, including transmission costs and prudently incurred stranded costs (a portion of which have been financed through securitization by issuing RRBs) with periodic true-up adjustments.  The last such adjustment, effective January 1, 2010, resulted in a 3.7 percent increase in customer rates.

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-hours (KWh) sales in compliance with the DPU’s July 16, 2008 decision in a generic decoupling docket.  We expect a decision from the DPU by the end of 2010.

For further information on WMECO’s rates and regulatory actions affecting WMECO, 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.

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WMECO is subject to service quality (SQ) metrics that measure safety, reliability and customer service.  Any charges incurred for failure to meet such metrics are paid by WMECO to customers through a method approved by the DPU.  WMECO will likely be required to pay an assessment charge for its 2009 reliability performance, primarily as a result of a power outage impacting WMECO’s Springfield underground service territory in 2009. WMECO has performed at target for other non-storm related reliability metrics.  WMECO will file its 2009 SQ results and assessment calculation with the DPU in March 2010.  

On October 16, 2009, WMECO filed its proposal for a dynamic pricing smart meter pilot program with the DPU.  The program proposes to involve 1,750 customers in WMECO's service region for a term of six months beginning in April 2011.  The total cost of the project is estimated to be $7 million, which would be recovered through rates WMECO would charge to customers.  A decision is expected from the DPU in the first half of 2010.  

On August 12, 2009, the DPU approved a stipulation agreement between WMECO and the AG concerning WMECO's proposal, under the Massachusetts Green Communities Act (GCA), to install 6 MW of solar energy generation in its service territory at an estimated cost of $41 million.  Under the agreement, no more than 3 MW will be commissioned in any one year between 2010 and 2012, the ROE on these assets will be a fully-tracking 9 percent, and the benefits of renewable energy and tax credits will be used to reduce the impact on customer bills.  WMECO will need to file an additional application with the DPU if it seeks to develop more than the initial 6 MW under the GCA, which allows for electric utility ownership of up to 50 MW of solar energy generating facilities.  

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.

REGULATED GAS DISTRIBUTION – YANKEE GAS SERVICES COMPANY

Yankee Gas operates the largest natural gas distribution system in Connecticut as measured by number of customers (approximately 205,000), and size of service territory (2,187 square miles).  Total throughput (sales and transportation) in 2009 was 52.5 billion cubic feet (Bcf) compared with 49.8 Bcf in 2008.  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.  Yankee Gas also owns a 1.2 Bcf Liquefied Natural Gas (LNG) facility in Waterbury, Connecticut which enables the company to buy natural gas in periods of low demand, store it and use it during peak demand periods when prices are typically higher.

The following table shows the sources of 2009 and 2008 total gas operating revenues based on categories of customers:

			Yankee Gas
			2009		2008
	Residential		48%		45%
	Commercial		31%		29%
	Industrial		18%		23%
	Other		3%		3%
	Total		100%		100%

Yankee Gas earned $21 million in 2009 compared to $27.1 million in 2008.  The 2009 results were lower than 2008 due primarily to higher operating costs, partially offset by higher revenues attributable to a 6.9 percent increase in firm natural gas sales.  For more information regarding Yankee Gas financial results, see Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, and Item 8, Financial Statements and Supplementary Data, which includes Note 17, "Segment Information," contained within this Annual Report on Form 10-K.

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A summary of firm natural gas sales in million cubic feet for Yankee Gas for 2009 and 2008 and the percentage changes in 2009 as compared to 2008 on an actual and weather normalized basis (using a 30-year average) is as follows:

		Firm Natural Gas Sales (mcf)
		2009		2008		Percent Increase		Weather Normalized Percentage (Decrease)/Increase
Residential		13,562		13,467		0.7%		(1.8)%
Commercial		14,063		12,939		8.7%		6.3 %
Industrial		14,825		13,311		11.3%		10.7 %
Total		42.450		39,717		6.9%		5.0 %

Actual and weather normalized firm natural gas sales in 2009 were higher than 2008.  The 2009 results for the commercial and industrial classes have benefitted substantially from the addition of new gas-fired distributed generation in Yankee Gas' service region during the last twelve to fifteen months.  Yankee Gas recovers almost half of its total distribution revenues through non-usage charges, and thus, similar to our electric distribution companies, changes in sales have less of an impact on revenues.  In 2010, we estimate our total weather normalized firm natural gas sales will be essentially the same as 2009.

On January 6, 2010, the DPUC issued a decision approving Yankee Gas' request to sell its four remaining propane plants that were used to supply gas during peak periods.  As a result, in order to meet future supply needs during peak periods, Yankee Gas has initiated a project to construct 16 miles of main gas pipeline between Waterbury, Connecticut and Wallingford, Connecticut and an expansion of the Yankee Gas LNG facility’s vaporization output (collectively, the WWL Project), which together are estimated to cost approximately $67 million.  The WWL Project will connect the LNG storage facility, which is located in Waterbury, Connecticut and is capable of storing the equivalent of 1.2 Bcf of natural gas, to areas with growing demand.  We expect to begin construction on this project in the second quarter of 2010 and complete it by the end of 2011.

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.

Under a settlement of its distribution rate filing with the Connecticut Office of Consumer Counsel and the DPUC’s Prosecutorial Division in 2007, Yankee Gas’ 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’ LNG facility, and Yankee Gas was allowed an authorized regulatory ROE of 10.1 percent.  Yankee Gas is required to return to customers 100 percent of all earnings in excess of the allowed 10.1 percent regulatory ROE.  It has not been necessary for Yankee Gas to return any earnings to customers as its regulatory ROE was 6.6 percent in 2009 and 8.3 percent in 2008. Yankee Gas is considering filing a rate case for new rates with the DPUC.

Sources and Availability of Natural Gas Supply

The DPUC requires that Yankee Gas meet the needs of its firm customers under all weather conditions. Specifically, Yankee Gas must structure its portfolio to meet customer needs under a design day scenario (defined as the coldest day in 30 years) and under a design year scenario (defined as the average of the four coldest years in the last 30 years). Yankee Gas’ LNG facility enables Yankee Gas to buy natural gas in periods of low demand, store it and use it during peak demand periods when prices are typically higher. Yankee Gas’ on-system stored LNG and underground storage supplies help to meet consumption needs during the coldest days of winter.  Yankee Gas obtains its interstate supplies from the three interstate pipelines that currently serve Connecticut: the Algonquin, Tennessee and Iroquois Pipelines.  Yankee Gas has long-term firm contracts for capacity on TransCanada Pipelines Limited pipeline, Vector Pipeline, L.P., Tennessee Gas Pipeline, Algonquin Pipeline, and Texas Eastern Transmission, L.P. pipelines.  Yankee Gas considers such transportation arrangements adequate for its needs.

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 shared by consumers throughout New England.

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Wholesale Transmission Rates

Wholesale transmission revenues are based on formula rates that are approved by the FERC.  A significant portion of our transmission revenues comes from ISO-NE charges to the distribution segments of CL&P, PSNH and WMECO which 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 Schedule 21 - NU rate schedules to recover costs of transmission and other transmission-related services. The RNS rate, administered by ISO-NE and billed to all New England transmission users, including CL&P, PSNH, and WMECO's transmission businesses, is reset on June 1^st of each year and recovers the revenue requirements associated with transmission facilities that benefit the entire New England region.  The Schedule 21 - NU rate, administered by NU, is reset on January 1^st and June 1^st of each year and recovers the revenue requirements for local transmission facilities and other transmission costs not recovered under the RNS rate, including 100 percent of the construction work in progress (CWIP) that is included in rate base on the New England East-West Solutions (NEEWS) projects.  The Schedule 21 - NU rate calculation recovers total transmission revenue requirements net of revenues received from other sources (i.e., RNS, rentals, etc.), thereby ensuring that NU recovers all regional and local revenue requirements as prescribed in Tariff No. 3.  Both the RNS and Schedule 21 - NU rates provide for annual true-ups to actual costs.  The financial impacts of differences between actual and projected costs are deferred for future recovery from or refunded to customers.

FERC ROE Decision

Pursuant to a series of orders issued in 2008, FERC set the base ROE for New England transmission projects at 11.14 percent and provided for certain incentives which could increase the ROE to 13.1 percent.  As a result CL&P earns between 12.64 percent and 13.1 percent on its major transmission projects completed by the end of 2008.  Certain state regulators and municipal utilities had sought rehearing which was denied by FERC.  Connecticut state regulators appealed the order to the D.C. Circuit Court of Appeals which appeal was denied on January 29, 2010.  

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; (2) inclusion of 100 percent CWIP costs in rate base; and (3) full recovery of prudently incurred costs if any portion of NEEWS is abandoned for reasons beyond our 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

NEEWS

In October 2008, CL&P and WMECO made state siting filings with the Connecticut Siting Council (CSC) in Connecticut and the Energy Facilities Siting Board (EFSB) in Massachusetts, respectively, for the first and largest component of our New England East-West Solutions (NEEWS) project, the Greater Springfield Reliability Project (GSRP).  In October 2009, ISO-NE affirmed the need and need date for GSRP.  In Connecticut, hearings have been completed and final briefs were filed in mid-January 2010 with the CSC.  We believe a final decision may be received from the CSC as early as March 2010.  In Massachusetts, hearings were completed in mid-February 2010 with final briefs expected to be filed in the spring.  We expect to receive a final decision from the EFSB in the third quarter of 2010.  GSRP, which involves the construction of a 115 kilovolt (KV)/345 KV line from Ludlow, Massachusetts to Bloomfield, Connecticut, is the largest and most complicated project within NEEWS and is expected to cost approximately $714 million if built according to our preferred route configuration.  Following decisions from the state siting boards, we expect to commence construction in late 2010 and to 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 USA.  CL&P's share of this project includes an approximately 40-mile 345 KV line from Lebanon, Connecticut to the Connecticut-Rhode Island border where it would connect with enhancements National Grid USA is designing.  We estimate CL&P's share of the costs of this project will be approximately $250 million.  Municipal consultations concluded in November 2008, and CL&P plans to file its siting application with Connecticut regulators later in 2010, following the completion of ISO-NE’s reassessment of the need date and issuance of its regional system plan.  We currently expect the project to be placed in service in 2014.

The third major 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 Interstate Reliability Project.  This project is currently expected to cost approximately $315 million.

ISO-NE is currently performing an evaluation of all projects in its regional system plan, including the Interstate Reliability Project and the Central Connecticut Reliability Project, and assessing the presently estimated need dates for these projects.  We expect ISO-NE’s view on need dates for the second and third major NEEWS projects to be updated in the next version of the regional system plan, which we expect to see as a draft during the third quarter of 2010.

Included as part of NEEWS are approximately $211 million of associated reliability related expenditures for projects, over $50 million of which are moving forward through the siting and construction phases and are expected to be completed in advance of the three major projects.

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We estimate that CL&P's and WMECO's total capital expenditures for NEEWS will be $1.49 billion.  Our current capital expenditure and rate base forecasts assume that all NEEWS projects are completed by the end of 2014.  However, the timing and amount of our projected annual capital spending could be affected if receipt of siting approvals is delayed or if the need dates for these projects change through ISO-NE's regional system planning process.  During the siting approval process, state regulators may require changes in configuration (including placing some lines underground) to address local concerns that could increase construction costs.  Our current design for NEEWS does not contemplate any underground lines.  Building any lines underground, particularly 345 KV lines, would increase total costs of the project beyond our current projections.

HQ Tie Line Project

NU and NSTAR, a major Massachusetts utility that serves the greater Boston area, are jointly planning a new, participant-funded, high voltage direct current transmission line from New Hampshire to Canada (HQ tie line project) where it will interconnect with a transmission line being planned by Hydro-Québec (HQ), a large Canadian utility.  Under the proposed arrangement, NU and NSTAR would sell to HQ 1,200 MW of firm electric transmission service over the HQ tie line project in order for HQ to sell and deliver this same amount of firm electric power from Canadian low-carbon energy resources to New England.  FERC granted approval of the HQ tie line project structure in May 2009.

We have made significant progress in the design of the HQ tie line project and reached conceptual agreement in the development of Transmission Services Agreement (TSA) with HQ.  There are several routing options still under technical review and we expect to resolve them by the end of the first half of 2010.  We anticipate that we will be filing the TSA with FERC, which will regulate the tariff charges under the TSA, and the project design with ISO-NE for technical review by mid-2010.  In addition, there are a number of state and Federal permits that will be required to site the HQ tie line project and we anticipate filing those applications in 2010 as well.  Though contingent on timely siting approvals, we currently expect to begin construction of the line in 2012 and have power flowing in 2015 (which coincides with HQ’s planned completion of several new hydro-electric facilities).  We estimate NU's share of this project to be $675 million.

In addition, we have started to negotiate a long term power purchase agreement with HQ for power flows over the HQ tie line project.  Our intention is to create a power purchase agreement structure that could be offered to other load serving entities in addition to NU and NSTAR.  Power purchase agreement terms will be subject to state regulatory approvals and critical to winning state policy maker support for the HQ tie line project.  We anticipate these agreements to be filed in 2010 as well.

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 2009, our transmission rate base was approximately $2.6 billion, including approximately $2.1 billion at CL&P, $315 million at PSNH and $183 million at WMECO.  We forecast that our total transmission rate base will grow to approximately $4.67 billion by the end of 2014.  This increase in transmission rate base is driven by the need to improve the capacity and reliability of our regulated transmission system and the construction of the HQ tie line project.

Based on the 2009 actual and 2010 through 2014 projected capital expenditures, our 2009 actual and 2010 through 2014 projected transmission rate base as of December 31 of each year are as follows:

		As of December 31,
(Millions of Dollars)		2009			2010			2011			2012			2013			2014
CL&P transmission		$	2,099		$	2,105		$	2,134		$	2,318		$	2,545		$	2,563
PSNH transmission			315			335			433			530			608			584
WMECO transmission			183			240			429			665			889			851
HQ tie line Project			-			-			-			-			-			675
Total transmission		$	2,597		$	2,680		$	2,996		$	3,513		$	4,042		$	4,673

The projected rate base amounts reflected above assume our projected capital expenditures occur as planned, including capital expenditures of $1.49 billion for CL&P and WMECO in the NEEWS program.  Capital expenditures could vary from the projected amounts for the companies and periods above.  The continuation of weak economic conditions in the Northeast could impact the timing of our major transmission projects.  Most of these capital investment projections, including those for the HQ tie line project, assume timely regulatory approval, which in some cases requires extensive review.  Delays in or denials of those approvals could reduce the levels of expenditures and associated rate base projections.  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 our existing electric generation, transmission and distribution systems and our natural gas distribution system. Our consolidated capital expenditures in 2009, including amounts incurred but not paid, cost of removal, allowance for funds used during construction and the capitalized portion of pension expense or income (all of which are non-cash factors in determining rate base), totaled approximately $969.2

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million, almost all of which ($916.5 million) was expended by the regulated companies. The capital expenditures of these companies in 2010 are estimated to total approximately $1.09 billion. Of this amount, approximately $441 million is expected to be expended by CL&P, $355 million by PSNH, $119 million by WMECO and $112 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 2010.  We expect to evaluate needs beyond 2010 in light of future developments, such as restructuring, industry consolidation, performance and other events.  Increases in proposed distribution capital expenditures stem 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 energy 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 are beyond their useful lives, such as old distribution poles, underground primary cables and substation switchgear.  Replacement of this equipment is extremely costly.

CL&P’s transmission capital expenditures in 2009 totaled approximately $163 million compared to $586.3 million in 2008.  The decrease in transmission segment capital expenditures in 2009 as compared with 2008 was primarily due to the completion in 2008 of the major southwest Connecticut transmission projects discussed above.  For 2010, CL&P projects transmission capital expenditures of approximately $136 million.  During the period 2010 through 2014, CL&P plans to invest approximately $1.06 billion 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 2009, CL&P's distribution capital expenditures totaled approximately $283 million.  CL&P projects its distribution capital expenditures in 2010 to be approximately $305 million. CL&P plans to spend approximately $1.55 billion on distribution projects during the period 2010 through 2014.  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 $2.1 billion at the end of 2009 to approximately $2.56 billion by the end of 2014, and its rate base for distribution assets is projected to increase from approximately $2.1 billion to approximately $2.91 billion over the same period.

In 2009, PSNH's transmission capital expenditures totaled approximately $61.1 million, its distribution capital expenditures totaled $98.8 million and its generation capital expenditures totaled $145 million.  For 2010, PSNH projects transmission capital expenditures of approximately $55 million, distribution capital expenditures of approximately $113 million and generation capital expenditures of approximately $187 million.  The increase in generation capital expenditures is mostly due to the expenditures for the Merrimack Clean Air Project.  During the period 2010 through 2014, PSNH plans to spend approximately $376 million on transmission projects, approximately $594 million on distribution projects, and $480 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 $315 million at the end of 2009 to approximately $584 million by the end of 2014, and its rate base for distribution and generation assets is projected to increase from approximately $1.18 billion to approximately $2.0 billion over the same period.

In 2009, WMECO's transmission capital expenditures totaled approximately $67.7 million and its distribution capital expenditures totaled approximately $37.7 million.  In 2010, WMECO projects transmission capital expenditures of approximately $66 million, distribution capital expenditures of approximately $33 million and $20 million on solar generation.  During the period 2010 through 2014, WMECO plans to spend approximately $812 million on transmission projects, with the bulk of that amount to be spent on the NEEWS Greater Springfield Reliability Project, approximately $179 million on distribution projects and $41 million on solar generation. If all of the generation, distribution and transmission projects are built as proposed, WMECO’s rate base for electric transmission is projected to increase from approximately $183 million at the end of 2009 to approximately $851 million by the end of 2014 and its rate base for distribution and generation assets is projected to increase from approximately $412 million to approximately $486 million over the same period.

In 2009, Yankee Gas capital expenditures totaled approximately $59.6 million. For 2010, Yankee Gas projects total capital expenditures of approximately $112 million. During the period 2010 through 2014, Yankee Gas plans on making approximately $461 million of capital expenditures, including approximately $62.7 million on the WWL Project and the expansion of the Yankee Gas LNG plant's vaporization output. If all of Yankee Gas projects are built as proposed, Yankee Gas investment in its regulated assets is projected to increase from approximately $691 million at the end of 2009 to approximately $974 million by the end of 2014.

Projected Capital Expenditures:  A summary of the capital expenditures for the regulated companies' transmission and the distribution and generation segments, by company, for 2009, and projections for 2010 through 2014, including our corporate service companies' capital expenditures on behalf of the regulated companies, is as follows:

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		Year
(Millions of Dollars)		2009			2010			2011			2012		2013				2014			2010-2014 Totals
CL&P transmission		$	163		$	136		$	203		$	281		$	286		$	155		$	1,061
PSNH transmission			61			55			118			107			74			22			376
WMECO transmission			68			66			256			328			156			6			812
HQ tie line Project			-			16			49			90			236			282			673
Subtotal transmission		$	292		$	273		$	626		$	806		$	752		$	465		$	2,922
CL&P distribution			283			305			313			306			305			317			1,546
PSNH distribution			99			113			111			115			121			134			594
WMECO distribution			38			33			39			36			35			36			179
Subtotal electric distribution		$	420		$	451		$	463		$	457		$	461		$	487		$	2,319
PSNH generation			145			187			117			82			68			26			480
WMECO generation			-			20			14			7			-			-			41
Subtotal generation		$	145		$	207		$	131		$	89		$	68		$	26		$	521
Yankee Gas distribution			60			112			104			80			82			83			461
Corporate service companies			52			48			25			22			25			14			134
Totals		$	969		$	1,091		$	1,349		$	1,454		$	1,388		$	1,075		$	6,357

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 COMPETITIVE ENERGY BUSINESSES

Since 2005, we have been in the process of exiting our competitive energy businesses and are now focusing predominantly on our regulated businesses.  At December 31, 2009, our competitive businesses consisted of (i) Select Energy’s few remaining wholesale energy marketing contracts, and NGS and its affiliates, which are winding down, and (ii) Boulos, NU Enterprises’ remaining active electrical contracting business.

Select Energy’s wholesale energy contract with The New York Municipal Power Agency (NYMPA) and related energy supply contracts expire in 2013.  In addition to the NYMPA contract, Select Energy's only other long-term wholesale obligation is a contract to operate and purchase the output of a generating facility in New England through mid-2012.

For more information regarding our exit from competitive businesses, see "NU Enterprises Divestitures" under Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, and Note 1B, "Summary of Significant Accounting Policies – Presentation," to the Consolidated Financial Statements, in this Annual Report on Form 10-K.

FINANCING

We paid common dividends of $162.4 million in 2009, compared with $129.1 million in 2008.  The increase is the result of increases of 6.3 percent and 11.8 percent in our common dividend rate that took effect in the third quarter of 2008 and in the first quarter of 2009, respectively, and a higher number of shares outstanding in the second, third and fourth quarters of 2009.  On February 9, 2010, our Board of Trustees declared a common dividend of $0.25625 per share, ($1.025 on an annual basis) payable on March 31, 2010 to shareholders of record as of March 1, 2010 representing an increase of approximately 7.9 percent over the 2009 dividend rate.

We target paying out approximately 50 percent of consolidated earnings in the form of common dividends.  Our ability to pay common dividends is subject to approval by our Board of Trustees and our future earnings and cash flow requirements and may be limited by certain state statutes, the leverage restrictions in our revolving credit agreement and the ability of our subsidiaries to pay common dividends to NU.  The Federal Power Act limits 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 of retained earnings under its FERC hydroelectric license conditions.  Relevant state statutes may impose additional limitations on the payment of dividends by the regulated companies.  CL&P, PSNH, WMECO and Yankee Gas also are parties to a revolving credit agreement that imposes leverage restrictions.

In general, the regulated companies pay approximately 60 percent of their earnings to NU parent in the form of common dividends.  In 2009, CL&P, PSNH, WMECO, and Yankee Gas paid $113.8 million, $40.8 million, $18.2 million, and $19.1 million, respectively, in common dividends to NU parent.  In 2009, NU parent made equity contributions of $147.6 million, $68.9 million, $0.9 million and $2.7 million to CL&P, PSNH, WMECO and Yankee Gas, respectively.   

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During 2009, the NU companies issued an aggregate of $462 million of debt, as follows:  

·

CL&P issued $250 million of first mortgage bonds on February 13, 2009 with an interest rate of 5.5 percent and maturity date of February 1, 2019.

·

CL&P remarketed $62 million of Pollution Control Revenue Bonds on April 2, 2009 which it had repurchased and had been holding since 2008.  The bonds carry a coupon of 5.25 percent and are subject to a mandatory tender for purchase on April 1, 2010, at which time they will be remarketed.

·

PSNH issued $150 million of first mortgage bonds on December 14, 2009 with an interest rate of 4.5 percent and a maturity date of December 1, 2019.

As a result of Lehman Brothers Commercial Bank, Inc. (LBCB) refusing to continue to fund its commitment of approximately $56 million under our credit facilities in 2008 described below, our aggregate borrowing capacity under our credit facilities was reduced from $900 million to $844 million.  This borrowing capacity, when combined with our access to other funding sources, provides us with adequate liquidity.  

NU parent has a credit facility in a nominal aggregate amount of $500 million, $482.3 million excluding the commitment of LBCB, which expires on November 6, 2010.  As of December 31, 2009, NU parent had $41 million of letters of credit (LOCs) issued for the benefit of certain subsidiaries (primarily PSNH) and $100.3 million of borrowings outstanding under this facility.  The weighted-average interest rate on these short-term borrowings as of December 31, 2009 was 0.63 percent, which is based on a variable rate plus an applicable margin based on NU parent's credit ratings.    

The regulated companies maintain a joint credit facility in a nominal aggregate amount of $400 million, $361.8 million excluding the commitment of LBCB, which also expires on November 6, 2010.  There were no borrowings outstanding under this facility as of December 31, 2009.   

Our credit facilities and bond indentures require that NU parent and certain of its subsidiaries, including CL&P, PSNH and WMECO, comply with certain financial and non-financial covenants as are customarily included in such agreements, including maintaining a ratio of consolidated debt to total capitalization of no more than 65 percent.  All such companies currently are, and expect to remain in compliance with these covenants.    

While we expect to renew our credit facilities in November, 2010, costs associated with the new facilities are likely to be higher than those associated with the existing credit facilities due to market conditions.

We are planning long-term debt issuances in 2010 aggregating approximately $145 million with $95 million being issued by WMECO and $50 million being issued by Yankee Gas.  The proceeds from these financings will be used primarily to repay short-term borrowings and fund our capital programs.  On January 22, 2010, the DPUC approved WMECO’s application to issue and sell up to $150 million of senior secured or unsecured long-term debt.

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

General

CL&P, PSNH, WMECO and other New England electric utilities are stockholders in three inactive regional nuclear generation 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 generation 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 CL&P, PSNH and WMECO and several other New England utilities.  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:

		CL&P		PSNH		WMECO		Total
CYAPC		34.5%		5.0%		9.5%		49.0%
MYAPC		12.0%		5.0%		3.0%		20.0%
YAEC		24.5%		7.0%		7.0%		38.5%

Our share of the obligations to support the Yankee Companies under FERC-approved contracts 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.

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OTHER REGULATORY AND ENVIRONMENTAL MATTERS

General

We are regulated in virtually all aspects of our business by various federal and state agencies, including the 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, which has jurisdiction over CL&P and Yankee Gas, the NHPUC, which has jurisdiction over PSNH, and the DPU, which has 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 approximately 1,200 MW of generation assets in New Hampshire and is spending approximately $457 million to install a wet flue gas desulphurization system at Merrimack Station (Clean Air Project) to reduce its mercury and sulfur dioxide emissions.  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.  The need to comply 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 Federal Clean Air Act Amendments of 1990 (CAAA), as well as New Hampshire law, impose stringent requirements on emissions of sulfur dioxide (SO₂) and nitrogen oxides (NO_X) for the purpose of controlling acid rain and ground level ozone. In addition, the CAAA address the control of toxic air pollutants.  Installation of continuous emissions monitors and expanded permitting provisions also are included.

In New Hampshire, the Multiple Pollutant Reduction Program capped NO_X, SO₂and carbon dioxide (CO₂) emissions 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).  The Clean Air Project addresses this requirement.  PSNH began site work for this project in November 2008, which is scheduled to be completed by mid-2012.

 

In addition, Connecticut, New Hampshire and Massachusetts are each members of the RGGI, 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.  Because CO₂ allowances issued by any participating state will be usable across all ten RGGI state programs, the individual state CO₂ trading programs, in the aggregate, will form one regional compliance market for CO₂ emissions.  A regulated power plant must hold CO₂ allowances equal to its emissions to demonstrate compliance at the end of a three-year compliance period that began in 2009.

Because neither CL&P nor WMECO own any generating assets, neither is required to acquire CO₂ allowances; however, the CO₂ allowance costs borne by generators which provide energy supply to CL&P and WMECO will likely be included in wholesale rates charged to them, which costs will be recoverable from customers.

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 Wood Power Project.  Under the RGGI formula, this Project 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 through 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.  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.

Each of the states in which we do business also has RPS requirements, which generally require fixed percentages of energy supply to come from renewable energy sources such as solar, hydropower, landfill gas, fuel cells and other similar sources.  New Hampshire’s RPS provision requires increasing percentages of the electricity PSNH sells to its retail customers to have direct ties to renewable sources, beginning in 2008 at 4 percent and ultimately reaching 23.8 percent by 2025.  We expect that the additional costs incurred to meet this requirement will be recovered through PSNH’s energy service rates.  Connecticut's RPS statutes require that a specific

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percentage of the energy provided to Connecticut consumers be produced from renewable energy sources.  Beginning with a 4 percent requirement in 2004, the requirement increases each year.  For 2009, the requirement was 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.  Any costs incurred in complying with RPS would be passed on to customers through rates.

In addition, many states and environmental groups have challenged certain of the federal laws and regulations relating to air emissions as not being sufficiently strict.  As a result, it is possible that state and federal regulations could be developed that will impose more stringent limitations on emissions than are currently in effect.

Hazardous Materials Regulations

Prior to the last quarter of the 20^th 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.  We 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, 2009, the liability recorded by us for our reasonably estimable and probable environmental remediation costs for known sites needing investigation and/or remediation, exclusive of recoveries from insurance or from third parties, was approximately $26 million, representing 57 sites.  These costs could be significantly higher if remediation becomes 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 $26 million, a reserve of approximately $24.1 million has been established to address future investigation and/or remediation costs at MGP sites.

HWP Company (HWP), formerly known as Holyoke Water Power Company, 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 an MGP site which it sold to Holyoke Gas and Electric (HG&E), a municipal electric utility, in 1902.  HWP is at least partially responsible for this site and 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, which share responsibility for the site, 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 HWP commencing many of the additional studies and evaluation.  This letter represents guidance from the MA DEP, rather than mandates.  HWP has developed and implemented site characterization studies to further delineate tar deposits 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.

HWP first established a reserve for this site in 1994.  The cumulative expense recorded to this reserve through December 31, 2009 was approximately $17 million, of which $15.9 million had been spent, leaving approximately $1.1 million in the reserve as of December 31, 2009.  At this time, we believe that the $1.1 million remaining in the reserve is at the low end of a range of probable and estimable costs of approximately $1.1 million to $1.8 million and will be sufficient for HWP to evaluate the results of the additional tar delineation and site characterization studies, evaluate its approach to this matter and conduct certain soft tar remediation.  There are many outcomes that could affect our estimates and require an increase to the reserve for HWP’s costs on this matter, 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, the extent of remediation required by the DEP 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 7A, "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.

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We have closely monitored research and government policy developments for many years and will continue to do so.  In accordance with recommendations of various regulatory bodies and public health organizations, 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.

Global Climate Change and Greenhouse Gas Emission Issues

Global climate change and greenhouse gas emission issues have received an increased focus from state governments and the federal government, particularly in the last year.  The U.S. Environmental Protection Agency (EPA) has initiated a rulemaking addressing greenhouse gas emissions and, on December 7, 2009, issued a finding that concluded that greenhouse gas emissions are "air pollution" and endanger public health and welfare and should be regulated.  The largest source of greenhouse gas emissions in the U.S. is the electricity generating sector.

We are continually evaluating the risks presented by climate change concerns and issues.  Such concerns could potentially lead to additional rules and regulations that impact how we operate our business, both in terms of the generating facilities we own and operate as well as general utility operations.  (See "Air Quality Requirements" in this section for information concerning RGGI)  These could include federal “cap and trade” laws, or regulations requiring additional capital expenditures at our generating facilities.  In addition, such rules or regulations could potentially impact the prices we pay for goods and services provided by companies directly affected by such rules or regulations.  We would expect that any costs of these rules and regulations would be recovered from customers, but such costs could impact energy use by our customers.  

Global climate change could potentially impact weather patterns such as increasing the frequency and severity of storms or altering temperatures.  These changes could affect our facilities and infrastructure and could also impact energy usage by our customers.  

FERC Hydroelectric Project Licensing

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 a current claimed capability representing winter rates of approximately 71 MW, eight of which are licensed by the FERC under long-term licenses that expire on varying dates from 2017 through 2047.  As a licensee under the Federal Power Act (FPA), PSNH and its 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.

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.

EMPLOYEES

As of December 31, 2009, we employed a total of 6,078 employees, excluding temporary employees, of which 1,870 were employed by CL&P, 1,250 by PSNH, 348 by WMECO, 425 by Yankee Gas and 2,185 were employed by Northeast Utilities Service Company (NUSCO).  Approximately 2,231 employees of CL&P, PSNH, WMECO, NUSCO and Yankee Gas are members of the International Brotherhood of Electrical Workers and The United Steelworkers and 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 EDGAR website (http://www.sec.gov/edgar/searchedgar/companysearch.html), 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, 56 Prospect Street, Hartford, CT 06103.

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Item 1A.

Risk Factors

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

The actions of regulators can significantly affect our earnings, liquidity and business activities.

The rates that our regulated companies charge their respective retail and wholesale customers are determined by their state utility commissions and by FERC.  These commissions also regulate the companies’ accounting, operations, the issuance of certain securities and certain other matters.  FERC also regulates their transmission of electric energy, the sale of electric energy at wholesale, accounting, issuance of certain securities and certain matters.  The commissions’ policies and regulatory actions could have a material impact on the regulated companies’ financial position, results of operations and liquidity.

Our transmission and distribution systems may not operate as expected, and could require unplanned expenditures which could adversely affect our earnings and cash flows.

The ability to manage the operations of 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 high percentage of our regulated company equipment, such as distribution poles, underground primary cables and substation switchgear is old or obsolete, or nearing or at the end of its life cycle.  The failure of our transmission and distributions systems to operate as planned may result in increased capital investments, reduced earnings or unplanned increases in operation and maintenance costs.  Such costs which are not recoverable from our customers would have an adverse effect on our earnings.

Limits on our access to capital may adversely impact our ability to execute our business plan.

We use short-term debt and the long-term capital markets as a significant source of liquidity and funding for capital requirements not obtained from our operating cash flow.  If access to these sources of liquidity becomes constrained, our ability to implement our business strategy could be adversely affected.  Events beyond our control, such as the disruption in global capital and credit markets in 2008, or a downgrade of our credit ratings, could increase our cost of borrowing and cost of capital or restrict our ability to access the capital markets and negatively affect our ability to maintain and to expand our businesses.

Our counterparties may not meet their obligations to us.

We are exposed to the risk that counterparties to various arrangements who owe us money, or contracted to supply us with energy, coal, or other commodities or services, will not be able to perform their obligations or, with respect to our credit facilities, fail to honor their commitments.  Should the counterparties to commodity arrangements fail to perform their obligations, we might be forced to replace the underlying commitment at higher market prices.  Should any more lenders under our credit facilities fail to perform, the level of borrowing capacity under those arrangements could decrease.  In such an event, our results of operations, financial position, or liquidity could be adversely affected.

Changes in regulatory or legislative policy and/or regulatory decisions, difficulties in obtaining siting, design or other approvals, global demand for critical resources, environmental or other concerns, or construction of new generation may delay completion of or displace our planned 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 could be affected by new legislation, regulations or judicial or regulatory interpretations of applicable law or regulations or regulatory decisions, delays in obtaining approvals or difficulty in obtaining critical resources required for construction.  Any of such events could cause delays in our construction schedule adversely affecting 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, our planned transmission projects may be delayed or displaced, which could result in reduced transmission capital investments, reduced earnings, and limited future growth prospects.

Many of our 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

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

Energy consumption is significantly impacted by the general level of economic activity and cost of energy supply. Economic downturns such as the one which began in 2008, or periods of high energy supply costs typically lead to reductions in energy consumption and increased 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.  A period of prolonged economic weakness could impact customers’ ability to pay bills in a timely manner and increase customer bankruptcies, which may lead to increased bad debt expenses or other adverse effects on our results of operations, cash flows or financial position.

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 investigated 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 fixed charges, and proportionately less distribution revenue through usage-based charges.  In New Hampshire, the NHPUC conducted a decoupling docket and determined that utilities were free to propose decoupling in the context of a rate case and demonstrate the effect decoupling would have on its risk profile and ROE.  In Massachusetts, the DPU conducted a generic decoupling docket and as a result required each utility to include rate decoupling in its next rate case.  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 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 their regional costs across New England.  This regional cost allocation is set forth in the Transmission Operating Agreement signed by all of the New England transmission owning utilities.  However, effective February 1, 2010, this agreement can be modified with the approval of a majority of the transmission owning utilities and FERC.  In addition, 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.  However, the current cost allocation is presumed reasonable, and those other parties seeking change would have to show that the allocation is no longer just and reasonable and demonstrate to FERC why such changes are necessary.  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 or unfavorable outcomes in regulatory proceedings could jeopardize our full and/or timely recovery of costs incurred by our regulated companies.

Under state law, our utility companies are entitled to charge rates that are sufficient to allow them an opportunity to recover their reasonable operating and capital costs, to attract needed capital and maintain their financial integrity, while also protecting relevant public interests.  Each of these companies prepares and submits periodic rate filings with their respective state regulatory commissions for review and approval.  There is no assurance that these state commissions will approve the recovery of all costs prudently incurred by our regulated companies, such as for construction, operation and maintenance, 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’ needs 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 the 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 and fixed-price forward purchase contracts.  PSNH’s remaining energy needs are met primarily through spot market 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.

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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 is building 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 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 forecasted levels of earnings.  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 have developed 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, including cyber-terrorism could negatively impact the operation of our system.  Any such disruption could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material adverse impact on our financial condition and results of operations.

Severe weather, such as ice and snow storms, hurricanes and other natural disasters, may cause outages and property damage which may require us to incur additional costs that 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.

Market performance or changes in assumptions could require us to make significant contributions to our pension and other post-employment benefit plans.

We provide a defined benefit pension plan and other post-retirement benefits for a substantial number of employees, former employees and retirees.  The measurement of our expected future pension obligations, costs and liabilities is highly dependent on a variety of assumptions, most of which relate to factors beyond our control.  These assumptions include investment returns, interest rates, health care cost trends, benefit improvements, salary increases and the demographics of plan participants.  If our assumptions prove to be inaccurate, our future costs could increase significantly.  In addition, various factors, including underperformance of plan investments, could increase the amount of contributions required to fund our pension plan in the future.  Large funding requirements, when combined with the financing requirements of our construction program, could impact the timing and amount of future equity and debt financings and would negatively affect our financial position, cash flows and results of operations.  

Costs of compliance with environmental regulations, including climate change legislation, 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 govern, 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 our results of operations, financial position and cash flows.

In addition, global climate change issues have received an increased focus from federal and state governments, 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

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and operate as well as general utility operations.  Although we would expect that any costs of these rules and regulations would be recovered from customers, their impact on energy use by customers and the ultimate impact on our business would be dependent upon the specific rules and regulations adopted and cannot be determined at this time.  The impact of these additional costs to customers could lead to a further reduction in energy consumption resulting in a decline in electricity and gas sales in our service territories, which would have an adverse impact on our business and results of operations, financial position and cash flows.

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.  The cost impact of any such laws, rules or regulations 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" in this Annual Report on Form 10-K.

As a holding company with no revenue-generating operations, NU parent is dependent on dividends from its subsidiaries, primarily the regulated companies, its bank facility, and its ability to access the long-term debt and equity capital markets.

NU parent is a holding company and as such, has no revenue-generating operations of its own.  Its ability to meet its financial obligations associated with the debt service obligations on its debt and to pay dividends on its common shares is primarily dependent on the earnings and cash flows of its operating subsidiaries, primarily the regulated companies; the ability of its subsidiaries to pay dividends or to repay funds due NU parent; and/or NU parent’s ability to access its credit facility or the long-term debt and equity capital markets.  Prior to funding NU parent, the regulated companies have financial obligations that must be satisfied, including among others, their respective debt service, preferred dividends (in the case of CL&P) and obligations to trade creditors.  Additionally, the regulated companies could retain their free cash flow to fund their capital expenditures in lieu of receiving equity contributions from NU parent.  Should the regulated companies not be able to pay dividends or repay funds due to NU parent or if NU parent cannot access its bank facilities or the long-term debt and equity capital markets, NU parent’s ability to pay interest and dividends would be restricted.

Item 1B.

Unresolved Staff Comments

We do not have any unresolved SEC staff comments.  

Item 2.

Properties

Transmission and Distribution System

As of December 31, 2009, our electric operating subsidiaries owned 31 transmission and 432 distribution substations that had an aggregate transformer capacity of 4,462,000 kilovolt amperes (kVa) and 29,811,000 kVa, respectively; 3,098 circuit miles of overhead transmission lines ranging from 69 KV to 345 KV, and 433 cable miles of underground transmission lines ranging from 69 KV to 345 KV; 34,935 pole miles of overhead and 2,999 conduit bank miles of underground distribution lines; and 538,032 underground and overhead line transformers in service with an aggregate capacity of 36,968,352 kVa.

Electric Generating Plants

As of December 31, 2009, PSNH owned the following electric generating plants:  

Type of Plant	Number of Units	Year Installed	Claimed Capability* (megawatts)
Total - Fossil-Steam Plants	(5 units)	1952-74		932
Total - Hydro-Conventional	(20 units)	1901-83		71
Total – Biomass – Steam Plant	(1 unit)	1954		46
Total - Internal Combustion	(5 units)	1968-70		103
Total PSNH Generating Plant	(31 units)			1,152

*

Claimed capability represents winter ratings as of December 31, 2009.  The combined nameplate capacity of the generating plants is approximately 1,200 MW.

Neither CL&P nor WMECO owned any electric generating plants during 2009.

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Yankee Gas

As of December 31, 2009, Yankee Gas owned 28 active gate stations, approximately 200 district regulator stations and 3,200 miles of gas main pipelines.  Yankee Gas also owns a 1.2 Bcf LNG facility in Waterbury, Connecticut as well as a propane facility in Kensington, 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.  

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.

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’ 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’ 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.

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Item 3.

Legal Proceedings

1.

Yankee Companies v. U.S. Department of Energy

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

In 2006, the Court of Federal Claims held that the DOE was liable for damages to CYAPC for $34.2 million through 2001, YAEC for $32.9 million through 2001 and MYAPC for $75.8 million through 2002.  In December 2006, the DOE appealed the decision and the Yankee Companies filed cross-appeals.  The Court of Appeals disagreed with the trial court’s method of calculation of the amount of the DOE’s liability, among other things, and vacated the decision of the Court of Federal Claims and remanded the case to make new findings consistent with its decision.  The application of any damages which are ultimately recovered to benefit customers is established in the Yankee Companies' FERC-approved rate settlement agreements, although implementation will be subject to the final determination of the FERC.

In December 2007, the Yankee Companies filed a second round of lawsuits against the DOE seeking recovery of actual damages incurred in the years following 2001 and 2002.

2.

Connecticut MGP Cost Recovery

In September 2006, CL&P and Yankee Gas (the NU Companies) filed a complaint against UGI Utilities, Inc. (UGI) in the U.S. District Court for the District of Connecticut seeking past and future remediation costs related to historic manufactured gas plant (MGP) operations on thirteen sites currently or formerly owned by the NU Companies (Yankee Gas is responsible for ten of the sites, CL&P for two of the sites, and both companies share responsibility for one site) in a number of different locations throughout the State of Connecticut.  The NU Companies allege that UGI controlled operations of the plants at various times throughout the period 1883 to 1941, when UGI was forced to divest its interests.  Investigations and remediation expenditures at the sites to date total over $20 million, and projected potential remediation costs for all sites, based on litigation modeling assumptions, could total as much as $232 million.  A trial was held in April 2009.

On May 22, 2009, the court granted judgment in favor of the NU Companies with respect to the Waterbury-North site, and granted judgment in favor of UGI with respect to the remaining sites.  On June 19, 2009, the NU Companies filed a Notice of Appeal with respect to the court’s decision.  Any recovery resulting from the case (following the appeal) would flow back to the NU Companies’ customers, and the NU companies would continue to seek recovery as appropriate of remediation and other associated costs with regard to the sites for which no recovery from UGI will be forthcoming.  

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.

EXECUTIVE OFFICERS OF THE REGISTRANT

The following table sets forth the executive officers of NU as of February 25, 2010.  All of the Company’s officers serve terms of one year and until their successors are elected and qualified:

Name		Age		Title
Jay S. Buth*		40		Vice President – Accounting and Controller.
Gregory B. Butler		52		Senior Vice President and General Counsel.
Jean M. LaVecchia**		58		Vice President - Human Resources of Northeast Utilities Service Company (NUSCO), a subsidiary of NU.
David R. McHale		49		Executive Vice President and Chief Financial Officer of NU.
Leon J. Olivier		61		Executive Vice President and Chief Operating Officer of NU.
James B. Robb**		49		Senior Vice President, Enterprise Planning and Development of NUSCO.
Charles W. Shivery		64		Chairman of the Board, President and Chief Executive Officer of NU.

*

Mr. Buth was elected Vice President – Accounting and Controller, effective June 9, 2009.

**

Deemed executive officer of NU pursuant to Rule 3b-7 under the Securities Exchange Act of 1934.

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Jay S. Buth.  Mr. Buth became Vice President – Accounting and Controller of NU, CL&P, PSNH and WMECO, effective June 9, 2009.  Previously, Mr. Buth served as Controller, and Vice President and Controller at NJR Service Corporation, a subsidiary of New Jersey Resources Corporation, a gas utility holding company, from June 2006 to January 2009.  He also served as Director - Finance at Allegheny Energy, Inc. from May 2004 to May 2006.

Gregory B. Butler.  Mr. Butler became Senior Vice President and General Counsel of NU effective December 1, 2005, and of CL&P, PSNH and WMECO, subsidiaries of NU, effective March 9, 2006, and was elected a Director of CL&P, PSNH and WMECO April 22, 2009 and a Director of Northeast Utilities Foundation, Inc. effective December 1, 2002.  Previously Mr. Butler served as Senior Vice President, Secretary and General Counsel of NU from August 31, 2003 to December 1, 2005 and Vice President, Secretary and General Counsel of NU from May 1, 2001 through August 30, 2003.

Jean M. LaVecchia.  Ms. LaVecchia was elected Vice President - Human Resources of NUSCO, effective January 1, 2005 and was elected a Director of CL&P, PSNH and WMECO April 22, 2009 and a Director of Northeast Utilities Foundation, Inc. effective January 30, 2007.  Previously Ms. LaVecchia served as Vice President - Human Resources and Environmental Services from May 1, 2001 to December 31, 2004.

David R. McHale.  Mr. McHale was elected Executive Vice President and Chief Financial Officer of NU, CL&P, WMECO and PSNH, effective January 1, 2009, elected a Director of PSNH and WMECO, effective January 1, 2005, of CL&P effective January 15, 2007 and of Northeast Utilities Foundation, Inc. effective January 1, 2005.  Previously, Mr. McHale served as Senior Vice President and Chief Financial Officer of NU, CL&P, PSNH and WMECO from January 1, 2005 to December 31, 2008 and Vice President and Treasurer of NU, WMECO and PSNH from July 1998 to December 31, 2004.

Leon J. Olivier.  Mr. Olivier was elected Executive Vice President and Chief Operating Officer of NU effective May 13, 2008; He also has served as Chief Executive Officer of CL&P, PSNH and WMECO since January 15, 2007; a Director of PSNH and WMECO since January 17, 2005 and a Director of CL&P since September 2001.  Previously, Mr. Olivier served as Executive Vice President - Operations of NU from February 13, 2007 to May 12, 2008; Executive Vice President of NU from December 1, 2005 to February 13, 2007; President - Transmission Group of NU from January 17, 2005 to December 1, 2005; and President and Chief Operating Officer of CL&P from September 2001 to January 2005.

James B. Robb.  Mr. Robb was elected Senior Vice President, Enterprise Planning and Development of NUSCO on September 4, 2007 and was elected a Director of CL&P, PSNH and WMECO April 22, 2009.  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.

Item 4.

[RESERVED]

PART II

Item 5.

Market for the Registrants' Common Equity and Related Stockholder Matters

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

Year		Quarter		High			Low
2009		First		$	25.05		$	19.45
		Second			22.40			19.99
		Third			24.72			21.38
		Fourth			26.33			22.54
2008		First		$	31.15		$	24.01
		Second			27.74			25.12
		Third			28.03			24.52
		Fourth			25.97			19.15

There were no purchases made by or on behalf of our company or any "affiliated purchaser" (as defined in Rule 10b-18(a)(3) under the Securities Exchange Act of 1934), of common stock during the fourth quarter of the year ended December 31, 2009.  

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As of January 31, 2010, there were 42,273 common shareholders of our company on record.  As of the same date, there were a total of 195,503,401 common shares issued, including 102,281 unallocated Employee Stock Ownership Plan (ESOP) shares held in the ESOP trust.

Pursuant to NU parent's Shareholder Rights Plan (the "Plan"), NU parent distributed to shareholders of record as of May 7, 1999, a dividend in the form of one common share purchase right (a "Right") for each common share owned by the shareholder.  The Rights and the Plan expired at the end of the 10-year term on February 23, 2009.  

On February 9, 2010, our Board of Trustees declared a dividend of 25.625 cents per share, payable on March 31, 2010 to shareholders of record as of March 1, 2010.

On October 13, 2009, our Board of Trustees declared a dividend of 23.75 cents per share, payable on December 31, 2009 to shareholders of record as of December 1, 2009.

On July 14, 2009, our Board of Trustees declared a dividend of 23.75 cents per share, payable on September 30, 2009 to shareholders of record as of September 1, 2009.

On April 14, 2009, our Board of Trustees declared a dividend of 23.75 cents per share, payable on June 30, 2009 to shareholders of record as of June 1, 2009.

On February 10, 2009, our Board of Trustees declared a dividend of 23.75 cents per share, payable on March 31, 2009 to shareholders of record as of March 1, 2009.  

On October 14, 2008, our Board of Trustees declared a dividend of 21.25 cents per share, payable on December 31, 2008 to shareholders of record as of December 1, 2008.

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.  

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 2009 and 2008, CL&P approved and paid $113.8 million and $106.5 million, respectively, of common stock dividends to NU.

During 2009 and 2008, PSNH approved and paid $40.8 million and $36.4 million, respectively, of common stock dividends to NU.

During 2009 and 2008, WMECO approved and paid $18.2 million and $39.7 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 Stockholder Matters, included in this Annual Report on Form 10-K.  

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Item 6.  

Selected Consolidated Financial Data

NU Selected Consolidated Financial Data (Unaudited)

(a)

Includes portions due within one year, but excludes RRBs.

(b)

Market price information reflects closing prices as reflected by the New York Stock Exchange.

(c)

Common Shareholder's Equity adjusted for goodwill and intangibles divided by total common shares outstanding.  

(d)

Net Income divided by the average change in Common Shareholder's Equity.  

(e)

The closing market price divided by the book value per share.  

See the Combined Notes to the Consolidated Financial Statements for a description of any accounting changes materially affecting the comparability of the information reflected in the table above.

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(a)

Includes portions due within one year, but excludes RRBs.

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Item 7.

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

The following discussion and analysis should be read in conjunction with our consolidated financial statements and related combined notes included in this Annual Report on Form 10-K.  References in this Annual Report to "NU," the “Company,” "we," "us" and "our" refer to Northeast Utilities and its consolidated subsidiaries.  All per share amounts are reported on a fully diluted basis.  

The only common equity securities that are publicly traded are common shares of NU.  The earnings and earnings per share (EPS) of each business discussed below do not represent a direct legal interest in the assets and liabilities allocated to such business but rather represent a direct interest in our assets and liabilities as a whole.  EPS by business is a financial measure not recognized under accounting principles generally accepted in the United States of America (GAAP) that is calculated by dividing the net income or loss attributable to controlling interest of each business by the weighted average fully diluted NU common shares outstanding for the period.  We use this non-GAAP financial measure to evaluate earnings results and to provide details of earnings results and guidance by business.  We believe that this measurement is useful to investors to evaluate the actual and projected financial performance and contribution of our businesses.  This non-GAAP financial measure should not be considered as an alternative to our consolidated fully diluted EPS determined in accordance with GAAP as an indicator of operating performance.

The discussion below also includes non-GAAP financial measures referencing our 2008 earnings and EPS excluding a significant charge resulting from the settlement of litigation.  We use these non-GAAP financial measures to more fully compare and explain the 2009, 2008 and 2007 results without including the impact of this settlement.  Due to the nature and significance of the litigation settlement charge to Net income, management believes that this non-GAAP presentation is more representative of our performance and provides additional and useful information to readers of this report in analyzing historical and future performance.  These non-GAAP financial measures should not be considered as alternatives to reported Net income attributable to controlling interest or EPS determined in accordance with GAAP as indicators of operating performance.

Reconciliations of the above non-GAAP financial measures to the most directly comparable GAAP measures of consolidated fully diluted EPS and Net income attributable to controlling interest are included under "Financial Condition and Business Analysis-Overview-Consolidated" and "Financial Condition and Business Analysis-Future Outlook" in Management's Discussion and Analysis, herein.   

Financial Condition and Business Analysis

Executive Summary

The following items in this executive summary are explained in more detail in this Annual Report:

Results, Strategy and Outlook:

·

We earned $330 million, or $1.91 per share, in 2009, compared with $260.8 million, or $1.67 per share, in 2008.  Excluding the after-tax charge of $29.8 million, or $0.19 per share, for the settlement of litigation, we earned $290.6 million, or $1.86 per share, in 2008.  The increase in 2009 results was due primarily to a $34.4 million increase in earnings from our regulated distribution and transmission segments.  The EPS for 2009 reflected the issuance of approximately 19 million common shares on March 20, 2009.

·

Our regulated companies, which consist of The Connecticut Light and Power Company (CL&P), Public Service Company of New Hampshire (PSNH), Western Massachusetts Electric Company (WMECO), and Yankee Gas Services Company (Yankee Gas), earned $323.5 million, or $1.87 per share, in 2009, compared with $289.1 million, or $1.85 per share, in 2008.  

·

Earnings at the distribution segments of our regulated companies (which also include Yankee Gas and the generation business of PSNH) totaled $159.2 million in 2009, compared with $150.8 million in 2008.  Earnings at the transmission segments of our regulated companies totaled $164.3 million in 2009, compared with $138.3 million in 2008.  The increase in distribution segment results was due primarily to lower operating costs as a result of cost management efforts, lower storm costs, distribution rate increases at CL&P and PSNH, higher generation-related earnings and the absence of a $3.5 million after-tax charge recorded in 2008 that related to the refund of the 2004 procurement incentive fee.  The higher transmission segment results were due to an increased investment in transmission infrastructure after the completion of major projects in 2008.

·

Our competitive businesses, which are held by NU Enterprises, Inc. (NU Enterprises), earned $15.8 million, or $0.09 per share, in 2009, compared with $13.1 million, or $0.08 per share, in 2008.  The after-tax mark-to-market gain on wholesale marketing contracts increased by $2.7 million from $1.1 million in 2008 to $3.8 million in 2009.  The 2008 mark-to-market included a net after-tax charge of $3.2 million due to the implementation of fair value measurement accounting guidance.

·

NU parent and other companies recorded net expenses of $9.3 million, or $0.05 per share, in 2009, compared with net expenses of $41.4 million, or $0.26 per share, in 2008.  Results for 2008 included the after-tax charge of $29.8 million, or $0.19 per share, associated with the settlement of litigation.

·

We project consolidated 2010 earnings of between $1.80 per share and $2.00 per share, including distribution segment earnings of between $0.95 per share and $1.05 per share, transmission segment earnings of between $0.90 per share and $0.95 per share, competitive business earnings of between zero and $0.05 per share, and net expenses at NU parent and other companies of approximately $0.05 per share.  PSNH filed a distribution rate case in June 2009 and CL&P filed a distribution rate case in

27

January 2010.  There are uncertainties over the outcomes of these distribution rate cases, both of which are expected to conclude in mid-2010.  WMECO intends to file a distribution rate case in mid-2010 with an expected decision by the end of 2010 and a distribution rate case filing for Yankee Gas is also under consideration, neither of which are included in the 2010 projections.  

·

We paid common dividends of $162.4 million in 2009, compared with $129.1 million in 2008.  The increase is the result of 6.3 percent and 11.8 percent increases that took effect in the third quarter of 2008 and the first quarter of 2009, respectively, and a higher number of shares outstanding in the second, third and fourth quarters of 2009.

·

We project that we will achieve a compound average annual EPS growth rate for the five-year period from 2010 to 2014 of between 6 percent and 9 percent, using 2009 EPS of $1.91 as the base level.

·

Regulated company capital expenditures are expected to total approximately $6.4 billion from 2010 through 2014, which would enable our total rate base to grow at a compound average annual growth rate of 9.5 percent from approximately $7 billion at the end of 2009 to $11.1 billion at the end of 2014.  This projection assumes the projects we have included in our five-year plan are built according to our schedule and on budget.  Significant projects included in the plan are the CL&P and WMECO New England East-West Solutions (NEEWS) project, the PSNH Clean Air Project, the Hydro-Québec (HQ) tie line project, and the Yankee Gas Waterbury to Wallingford Pipeline Project.

Legal, Regulatory and Other Items:

·

On May 22, 2009, the Federal Energy Regulatory Commission (FERC) granted approval of the structure of a proposed project between NU, NSTAR, a Massachusetts utility company that serves the greater Boston area, and HQ, a large Canadian utility, involving a high voltage direct current (HVDC) transmission line from New Hampshire to Canada (HQ tie line project) to deliver and sell 1,200 megawatts (MW) of low-carbon energy in New England.  

·

On June 30, 2009, PSNH filed an application with the New Hampshire Public Utilities Commission (NHPUC) requesting a permanent increase in distribution rates of approximately $51 million on an annualized basis to be effective August 1, 2009, and another $17 million to be effective July 1, 2010.  On July 31, 2009, the NHPUC approved a temporary increase in distribution rates of $25.6 million on an annualized basis, effective August 1, 2009.  PSNH expects a decision on the permanent distribution rate request in mid-2010.  Any differences between allowed temporary rates and permanent rates will be reconciled back to August 1, 2009.

·

On August 12, 2009, the Massachusetts Department of Public Utilities (DPU) approved the installation of 6 MW of solar energy generation in WMECO's service territory at an estimated cost of $41 million.  The return on equity (ROE) on these assets will be a fully tracking 9 percent.  

·

On January 8, 2010, CL&P filed an application with the Connecticut Department of Public Utility Control (DPUC) to raise distribution rates by $133.4 million to be effective July 1, 2010, and by an additional $44.2 million to be effective July 1, 2011.  CL&P proposed that the first year’s increase would be deferred until January 1, 2011 and that approximately $67 million of cash revenue requirement for the second half of 2010 would be deferred and recovered from CL&P customers between January 1, 2011 and June 30, 2012.  A DPUC decision on this rate application is expected in mid-2010.

Liquidity:

·

NU completed a public offering of approximately 19 million common shares on March 20, 2009, resulting in $370.8 million of net proceeds to the Company after offering expenses of $12.5 million.  The proceeds were used to fund capital investment programs for our regulated companies and to repay short-term borrowings.  We anticipate a single public offering of approximately $300 million in NU common shares in the next five years, which is expected no earlier than 2012.

·

We issued $462 million of debt in 2009 ($312 million at CL&P and $150 million at PSNH), comprised of $400 million in first mortgage bonds at rates of 4.5 percent and 5.5 percent, and $62 million in remarketed pollution control revenue bonds (PCRBs) at a one-year fixed rate of 5.25 percent.  We expect to issue an aggregate amount of approximately $145 million of long-term debt in the first half of 2010 ($95 million at WMECO and $50 million at Yankee Gas).  

·

We had total outstanding long-term and short-term debt of approximately $4.7 billion as of December 31, 2009, compared with approximately $4.8 billion as of December 31, 2008.  The decline reflects a reduction of approximately $520 million in notes payable to banks, partially offset by approximately $400 million in increases to long-term debt.  The decline in total debt was due primarily to increased cash flows from operations and the sale by NU of approximately 19 million common shares.

·

Our cash capital expenditures totaled $908.1 million in 2009, compared with $1.3 billion in 2008.  The decrease in our cash capital expenditures was primarily the result of lower transmission segment capital expenditures, particularly at CL&P, due to the completion in 2008 of three major transmission projects in southwest Connecticut.  We project total capital expenditures of approximately $1.1 billion in 2010 (including non-cash factors) due to higher expenditures for NEEWS and other regulated company projects.  

·

After rate reduction bond (RRB) payments included in financing activities, we had cash flows provided by operating activities in 2009 of $745 million, which represented an increase of approximately $321 million from 2008.  The improved cash flows were due

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primarily to higher transmission revenues at CL&P; approximately $225 million more in cash collected in 2009 compared to 2008 for costs that are tracked and passed on to customers; approximately $100 million less in cash expenditures on fuel, materials and supplies in 2009 (largely due to lower amounts spent for Yankee Gas storage due to lower natural gas prices); and the absence in 2009 of the litigation settlement payment of $49.5 million made in March 2008.  

·

We project consolidated cash flows provided by operating activities, net of RRB payments, of approximately $4 billion from 2010 through 2014, ranging from approximately $700 million in 2010 to approximately $1.1 billion in 2014.  This projection reflects a cash contribution of approximately $45 million into the Company’s pension plan in the third quarter of 2010, as well as a potential contribution in 2011 of approximately $200 million.

·

Our cash and cash equivalents totaled $27 million as of December 31, 2009, compared with $89.8 million as of December 31, 2008.  As of December 31, 2009, we also had $702.8 million of aggregate borrowing availability on our revolving credit lines, as compared to $157.8 million of availability as of December 31, 2008.  This increase in availability was primarily a result of the 2009 equity and debt issuances, higher cash flows provided by operating activities and lower capital expenditures.  Our credit facilities in a total nominal amount of $900 million will expire on November 6, 2010.  While we expect to renew these facilities before the expiration date, costs associated with the new facilities will likely be higher than those associated with the existing credit facilities due to changes in credit market conditions.

Overview

 

Consolidated:  We earned $330 million, or $1.91 per share, in 2009, compared with $260.8 million, or $1.67 per share, in 2008 and $246.5 million, or $1.59 per share, in 2007.  Excluding the after-tax charge of $29.8 million, or $0.19 per share, for the settlement of litigation, we earned $290.6 million, or $1.86 per share, in 2008.  The increase in 2009 results was due primarily to a $34.4 million increase in earnings from our regulated distribution and transmission segments, which includes their shares of the resolution of several routine income tax audits that increased NU earnings in 2009 and 2008 by $13.8 million and $8.9 million, respectively.  The EPS for 2009 reflected the issuance of approximately 19 million common shares on March 20, 2009.  A summary of our earnings by business, which also reconciles the non-GAAP financial measures of consolidated non-GAAP earnings and EPS, as well as EPS by business, to the most directly comparable GAAP measures of consolidated net income attributable to controlling interest and fully diluted EPS, for 2009, 2008 and 2007 is as follows:

		For the Years Ended December 31,
		2009						2008						2007
(Millions of Dollars, except   per share amounts)		Amount			Per Share			Amount			Per Share			Amount			Per Share
Net income attributable to   controlling interest (GAAP)		$	330.0		$	1.91		$	260.8		$	1.67		$	246.5		$	1.59
Regulated companies		$	323.5		$	1.87		$	289.1		$	1.85		$	228.7		$	1.47
Competitive businesses			15.8			0.09			13.1			0.08			11.7			0.08
NU parent and other companies			(9.3)			(0.05)			(11.6)			(0.07)			6.1			0.04
Non-GAAP earnings			330.0			1.91			290.6			1.86			246.5			1.59
Litigation charge (after-tax)			-			-			(29.8)			(0.19)			-			-
Net income attributable to   controlling interest (GAAP)		$	330.0		$	1.91		$	260.8		$	1.67		$	246.5		$	1.59

Regulated Companies:  Our regulated companies operate in two segments:  electric transmission and electric and gas distribution, with PSNH generation included in its distribution segment.  A summary of regulated company earnings by segment for 2009, 2008 and 2007 is as follows:

		For the Years Ended December 31,
(Millions of Dollars)		2009			2008			2007
CL&P Transmission		$	136.8		$	115.6		$	66.7
PSNH Transmission			18.0			16.7			10.7
WMECO Transmission			9.5			6.0			5.1
Total Transmission		$	164.3		$	138.3		$	82.5
CL&P Distribution		$	74.0		$	70.0		$	61.4
PSNH Distribution			47.5			41.4			43.7
WMECO Distribution			16.7			12.3			18.5
Yankee Gas			21.0			27.1			22.6
Total Distribution		$	159.2		$	150.8		$	146.2
Net Income - Regulated Companies		$	323.5		$	289.1		$	228.7

The higher 2009 and 2008 transmission segment earnings reflect an increased investment in this segment as we continued to build out our transmission infrastructure to meet our customers' and the region's reliability needs.  The results primarily reflect the effect of CL&P's investment of approximately $1.6 billion since the beginning of 2005 in the southwest Connecticut transmission projects that were completed in late 2008.  Our transmission segment rate base has increased from approximately $1.5 billion as of December 31, 2007 to approximately $2.6 billion as of December 31, 2009.  

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