CONNECTICUT LIGHT & POWER CO - Annual Report: 2011 (Form 10-K)

________________________________________________________________________________

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, 2011
	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 whether the registrants have submitted electronically and posted on its corporate Web sites, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

	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, 2011) was $6,218,948,649 based on a closing sales price of $35.17 per share for the 176,825,381 common shares outstanding on June 30, 2011.  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 issuers' classes of common stock, as of the latest practicable date:

Company - Class of Stock	Outstanding as of January 31, 2012
Northeast Utilities Common shares, $5.00 par value	177,203,768 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

GLOSSARY OF TERMS
The following is a glossary of 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 the Holyoke Water Power Company
NGS	Northeast Generation Services Company and subsidiaries
NPT	Northern Pass Transmission LLC, a jointly owned limited liability company, held by NUTV and NSTAR Transmission Ventures, Inc. on a 75 percent and 25 percent basis, respectively
NUTV	NU Transmission Ventures, Inc.
NU or the Company	Northeast Utilities and subsidiaries
NU Enterprises	NU Enterprises, Inc., the parent company of Select Energy, NGS, NGS Mechanical, Select Energy Contracting, Inc. and Boulos
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, RRR (a real estate subsidiary), 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 activities of PSNH and WMECO, Yankee Gas, a natural gas local distribution company, and NPT
RRR	The Rocky River Realty Company
Select Energy	Select Energy, Inc.
WMECO	Western Massachusetts Electric Company
Yankee	Yankee Energy System, Inc.
Yankee Gas	Yankee Gas Services Company
REGULATORS:
DEEP	Connecticut Department of Energy and Environmental Protection
DOE	U.S. Department of Energy
DPU	Massachusetts Department of Public Utilities
DPUC	Connecticut Department of Public Utility Control
EPA	U.S. Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
MA DEP	Massachusetts Department of Environmental Protection
NHPUC	New Hampshire Public Utilities Commission
PURA	Connecticut Public Utility Regulatory Authority (formerly DPUC)
SEC	Securities and Exchange Commission
OTHER:
2010 Healthcare Act	Patient Protection and Affordable Care Act
AOCI	Accumulated Other Comprehensive Income/(Loss)
AFUDC	Allowance For Funds Used During Construction
AMI	Advanced metering infrastructure
ARO	Asset Retirement Obligation
C&LM	Conservation and Load Management
CERLA	The federal Comprehensive Environmental Response, Compensation and Liability Act of 1980
CfD	Contract for Differences
CO2	Carbon dioxide
CTA	Competitive Transition Assessment
CWIP	Construction work in progress
CYAPC	Connecticut Yankee Atomic Power Company
DOER	Massachusetts Department of Energy Resources
EIA	Energy Independence Act
EMF	Electric and Magnetic Fields
EPS	Earnings Per Share
ERISA	Employee Retirement Income Security Act of 1974
ES	Default Energy Service
ESOP	Employee Stock Ownership Plan
ESPP	Employee Stock Purchase Plan
Fitch	Fitch Ratings
FMCC	Federally Mandated Congestion Charge
FTR	Financial Transmission Rights

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GAAP	Accounting principles generally accepted in the United States of America
GHG	Greenhouse Gas
GSC	Generation Service Charge
GSRP	Greater Springfield Reliability Project
GWh	Giga-watt Hours
HG&E	Holyoke Gas and Electric, a municipal department of the town of Holyoke, MA
HQ	Hydro-Québec, a corporation wholly owned by the Québec government, including its divisions that produce, transmit and distribute electricity in Québec, Canada
HVDC	High voltage direct current
Hydro Renewable Energy	H.Q. Hydro Renewable Energy, Inc., a wholly owned subsidiary of Hydro-Québec
IPP	Independent Power Producers
ISO-NE	ISO New England, Inc., the New England Independent System Operator
ISO-NE Tariff	ISO-NE FERC Transmission, Markets and Services Tariff
KV	Kilovolt
kWh	Kilowatt-Hours
LNG	Liquefied natural gas
LOC	Letter of Credit
LRS	Supplier of last resort service
MGP	Manufactured Gas Plant
Millstone	Millstone Nuclear Generating station, made up of Millstone 1, Millstone 2, and Millstone 3.  All three units were sold in March 2001.
Money Pool	Northeast Utilities Money Pool
Moody's	Moody's Investors Services, Inc.
MW	Megawatt
MWh	Megawatt-Hours
MYAPC	Maine Yankee Atomic Power Company
NEEWS	New England East-West Solution
NOx	Nitrogen oxide
Northern Pass	The high voltage direct current transmission line project from Canada into New Hampshire
NPDES	National Pollutant Discharge Elimination System
NU supplemental benefit trust	The NU Trust Under Supplemental Executive Retirement Plan
OCI	Other Comprehensive Income
PBO	Projected Benefit Obligation
PBOP	Postretirement Benefits Other Than Pension
PBOP Plan	Postretirement Benefits Other Than Pension Plan that provides certain retiree health care benefits, primarily medical and dental, and life insurance benefits
PCRBs	Pollution Control Revenue Bonds
Pension Plan	Single uniform noncontributory defined benefit retirement plan
PGA	Purchased Gas Adjustment
PPA	Pension Protection Act
RECs	Renewable Energy Certificates
Regulatory ROE	The average cost of capital method for calculating the return on equity related to the distribution and generation business segment excluding the wholesale transmission segment
RGGI	Regional Greenhouse Gas Initiative
RNS	Regional Network Service
ROE	Return on Equity
RPS	Renewable Portfolio Standards
RRB	Rate Reduction Bond or Rate Reduction Certificate
RSUs	Restricted share units
S&P	Standard & Poor's Financial Services LLC
SBC	Systems Benefits Charge
SCRC	Stranded Cost Recovery Charge
SERP	Supplemental Executive Retirement Plan
SO2	Sulfur dioxide
SS	Standard service
TCAM	Transmission Cost Adjustment Mechanism
TSA	Transmission Service Agreement
UI	The United Illuminating Company
WWL Project	The construction of a 16-mile gas pipeline between Waterbury and Wallingford, Connecticut and the increase of vaporization output of Yankee Gas' LNG plant
YAEC	Yankee Atomic Electric Company
Yankee Companies	Connecticut Yankee Atomic Power Company, Yankee Atomic Electric Company and Maine Yankee Atomic Power Company

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

2011 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:

·

actions or inaction by local, state and federal regulatory and taxing bodies;

·

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

·

changes in weather patterns;

·

changes in laws, regulations or regulatory policy;

·

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;

·

technological developments;

·

changes in accounting standards and financial reporting regulations;

·

actions of rating agencies;

·

the expected timing and likelihood of completion of the pending merger with NSTAR, including the timing, receipt and terms and conditions of any required governmental and regulatory approvals of the pending merger that could reduce anticipated benefits or cause the parties to abandon the merger, the diversion of management's time and attention from our ongoing business during this time period, as well as the ability to successfully integrate the businesses, and the risk that the credit ratings of the combined company or its subsidiaries may be different from what the companies expect; and

·

other presently unknown or unforeseen factors.  

Other risk factors are detailed in our reports filed with the SEC and updated as necessary, and we encourage you to consult such disclosures.

All such factors are difficult to predict, contain uncertainties that 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 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

Please refer to the Glossary of Terms for definitions of defined terms and abbreviations used in this Annual Report on Form 10-K.

PENDING MERGER WITH NSTAR

On October 18, 2010, NU and NSTAR announced that each company’s Board of Trustees unanimously approved a Merger Agreement (the “agreement”), under which NSTAR will become a direct wholly owned subsidiary of NU.  On October 14, 2011, NU and NSTAR extended the Termination Date of the agreement, as defined therein, from October 16, 2011 to April 16, 2012.  The transaction is structured as a merger of equals in a tax-free exchange of shares.  Under the terms of the agreement, NSTAR shareholders will receive 1.312 NU common shares for each NSTAR common share that they own (the “exchange ratio”).  Following the merger, NU will provide electric and natural gas energy delivery service to approximately 3.5 million electric and natural gas customers through six regulated electric and natural gas utilities in Connecticut, Massachusetts and New Hampshire.  On March 4, 2011, NU shareholders approved the agreement, approved an increase in the number of NU common shares authorized for issuance by 155 million common shares to 380 million common shares and fixed the number of trustees at 14.  NSTAR shareholders approved the agreement on March 4, 2011.

Subject to the conditions in the agreement, our first quarterly dividend per common share paid after the closing of the merger will be increased to an amount that is at least equal, after adjusting for the exchange ratio, to NSTAR's last quarterly dividend paid prior to the closing.

Completion of the merger is subject to various customary conditions, including, among others, receipt of all required regulatory approvals.  NU and NSTAR are awaiting approvals from PURA and the DPU.

In December 2010, the Connecticut Office of Consumer Counsel, supported by the Connecticut Attorney General, petitioned PURA to reconsider its earlier conclusion that it lacked jurisdiction to review the merger.  On June 1, 2011, PURA declined to change its conclusion that it lacked jurisdiction over the merger.  However, on January 18, 2012, PURA issued a decision that revised its June 1, 2011 decision.  The January 18, 2012 decision ruled that NU and NSTAR must seek approval from PURA pursuant to Connecticut law prior to completing the merger.  NU and NSTAR filed an application with PURA seeking approval of the merger on January 19, 2012.  Hearings began February 14, 2012 and PURA is scheduled to issue a final decision on April 2, 2012.  

On November 24, 2010, NU and NSTAR filed a joint petition requesting the DPU’s approval of the merger and filed supplemental testimony and a net benefit analysis with the DPU on April 8, 2011, in response to the DPU’s revision of its merger standard to a “net benefits” standard.  On February 15, 2012, NU and NSTAR reached comprehensive merger-related settlement agreements with both the Massachusetts DOER and the Massachusetts AG.  The first settlement agreement was reached with both the AG and the DOER and covers a variety of rate-making and rate design issues, including a distribution rate freeze until 2016 for NSTAR Electric Company, NSTAR Gas Company and WMECO.  The second settlement agreement was reached with the DOER and covers a variety of matters impacting the advancement of Massachusetts clean energy goals established by the Green Communities Act and Global Warming Solutions Act.

Pursuant to the terms and provisions of the settlement agreements, the parties agree that the proposed merger between NU and NSTAR is consistent with the public interest and should be approved by the DPU.  However, the settlement agreements allow the Attorney General and DOER to terminate their respective agreements for any reason at any time prior to approval by the DPU.  All parties have requested that the DPU approve the merger on April 4, 2012.  If both the DPU and PURA issue acceptable decisions by that date, we expect the merger will be consummated by April 16, 2012.  

All other approvals required to consummate the merger have been received.  For further information regarding regulatory approvals on the pending merger, see “Regulatory Developments and Rate Matters – Regulatory Approvals for Pending Merger with NSTAR,” in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, in this Annual Report on Form 10-K.

THE COMPANY

NU, headquartered in Hartford, Connecticut, is a public utility holding company subject to regulation by 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 that serves residential, commercial and industrial customers in parts of Connecticut;

●

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

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●

Western Massachusetts Electric Company (WMECO), a regulated electric utility that serves residential, commercial and industrial customers in parts of western Massachusetts and owns solar generating assets; and

●

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

NU also owns certain unregulated businesses through its wholly owned subsidiary, NU Enterprises, which are included in its Parent and other companies’ results of operations.

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 distribution segment (which also includes the generation businesses of PSNH and WMECO and our natural gas distribution business) and the transmission segment.  Our distribution segment represented approximately 53 percent of our Regulated companies’ earnings and our electric transmission segment represented approximately 47 percent.  

REGULATED ELECTRIC DISTRIBUTION

General

NU’s electric distribution segment consists of the distribution businesses of CL&P, PSNH and WMECO, which are engaged in the distribution of electricity to retail customers in Connecticut, New Hampshire and western Massachusetts, respectively, plus the regulated electric generation businesses of PSNH and WMECO.  The following table shows the sources of 2011 electric franchise retail revenues for NU’s electric distribution companies, collectively, based on categories of customers:

	Sources of Revenue		% of Total Revenues
	Residential		58
	Commercial		33
	Industrial		7
	Other		2
	Total		100%

A summary of changes in the electric distribution companies’ retail electric sales (GWh) for 2011, as compared to 2010, on an actual and weather normalized basis (using a 30-year average) is as follows:

		2011		2010		Percentage Decrease		Weather Normalized Percentage Decrease
Residential		14,766		14,913		(1.0)%		(0.2)%
Commercial		14,301		14,506		(1.4)%		(0.3)%
Industrial		4,418		4,481		(1.4)%		(0.2)%
Other		327		330		(1.0)%		(1.0)%
Total		33,812		34,230		(1.2)%		(0.3)%

Actual retail electric sales for all three electric companies were lower in 2011 compared to 2010 due primarily to milder weather in the summer of 2011, compared to warmer than normal weather in the summer of 2010.  In 2011, cooling degree days in Connecticut and western Massachusetts were 20.9 percent lower than 2010, and in New Hampshire, cooling degree days were 23.7 percent lower than 2010.  

On a weather-normalized basis, total retail electric sales decreased slightly in 2011, as compared to 2010.  We believe the weather-normalized commercial sales for CL&P and WMECO decreased in 2011, compared to 2010, due to the slow economic recovery in these service areas.  PSNH commercial sales increased in 2011 due to one large self-generating customer who experienced multiple generation outages and relied on PSNH for energy.  Industrial sales for both CL&P and WMECO decreased in 2011, compared to 2010, due in part to weak manufacturing activity in Connecticut and western Massachusetts.  Our commercial and industrial electric sales continue to be negatively impacted by utilization of distributed generation and conservation programs.  

Major Storms

On August 28, 2011, Tropical Storm Irene caused extensive damage to our distribution system resulting in incremental restoration costs of $135.6 million.  Approximately 800,000 of our 1.9 million electric distribution customers were without power at the peak of the outages, with approximately 670,000 of those customers in Connecticut.  

On October 29, 2011, an unprecedented autumn snowstorm inundated our service territory with heavy snow, causing significant damage to our distribution and transmission systems resulting in incremental restoration costs of $218.5 million.  Approximately 1.2 million of our electric distribution customers were without power at the peak of the outages, with approximately 810,000 of those customers in Connecticut, approximately 237,000 of those customers in New Hampshire, and approximately 140,000 of those customers in Massachusetts.  In terms of customer outages, this was the most severe storm in CL&P’s history, surpassing Tropical

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Storm Irene; the third most severe in PSNH’s history, following a December 2008 ice storm and a February 2010 winter storm; and the most severe in WMECO's history.

CL&P recorded a pre-tax charge for a storm fund reserve of $30 million, in the fourth quarter of 2011, to provide bill credits to its residential customers who remained without power after noon on Saturday, November 5, 2011 as a result of the October snowstorm, and to provide contributions to certain Connecticut charitable organizations.  Approximately $27 million of the storm fund reserve was used to provide a one-time credit on the February 2012 bills of approximately 192,000 CL&P customers and approximately $3 million was paid to charitable organizations in December 2011.  CL&P will not seek to recover this amount in its rates.

Estimated incremental restoration costs related to the two storms are summarized in the table below and consist of costs that are deferred for future recovery and costs that are capitalized:

		For the Year Ended December 31, 2011
(Millions of Dollars)		Deferred for Future Recovery			Capitalized			Total Incremental Costs
Tropical Storm Irene:
CL&P		$	105.6		$	18.2		$	123.8
PSNH			7.0			1.1			8.1
WMECO			3.2			0.5			3.7
Total Tropical Storm Irene			115.8			19.8			135.6
October Snowstorm:
CL&P			157.7			16.9			174.6
PSNH			14.7			2.2			16.9
WMECO			23.5			3.5			27.0
Total October Snowstorm			195.9			22.6			218.5
Total Storm Costs		$	311.7		$	42.4		$	354.1

We believe our response to both storms was prudent and therefore we believe it is probable that CL&P, PSNH and WMECO will be allowed to recover these storm costs.  Each operating company will seek recovery of its estimated deferred storm costs through its applicable regulatory recovery process.  For further information regarding various reviews on storm response and preparedness, see “Regulatory Developments and Rate Matters – 2011 Major Storms,” in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations in this Annual Report on Form 10-K.

THE CONNECTICUT LIGHT AND POWER COMPANY - DISTRIBUTION

CL&P’s distribution business consists primarily of the purchase, delivery and sale of electricity to its residential, commercial and industrial customers.  As of December 31, 2011, CL&P furnished retail franchise electric service to approximately 1.2 million customers in 149 cities and towns in Connecticut.  CL&P does not own any electric generation facilities.  

The following table shows the sources of CL&P’s 2011 electric franchise retail revenues based on categories of customers:

	Sources of Revenue		% of Total Revenues
	Residential		59
	Commercial		32
	Industrial		6
	Other		3
	Total		100%

Rates

CL&P is subject to regulation by PURA, 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, CTA, SBC and other charges that are assessed on all customers.

The CTA is a charge assessed to recover stranded costs associated with electric industry 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 industry restructuring.  The CTA and SBC are annually reconciled to actual costs incurred, with any difference refunded to, or recovered from, customers.

Under Connecticut law, all of CL&P's customers are entitled to choose their energy suppliers, while CL&P remains their electric distribution company.  Under SS rates for customers with less than 500 kilowatts of demand and LRS rates for customers with 500 kilowatts of demand or greater, CL&P purchases power for those customers who do not choose a competitive energy supplier and passes the cost to such customers through a combined  GSC and FMCC charge on customers' bills.  The combined GSC and FMCC

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charges for both types of service recover all of CL&P’s costs of procuring energy from wholesale suppliers and are adjusted periodically and reconciled semi-annually in accordance with the directives of PURA.

CL&P continues to supply approximately 35 percent of its customer load at SS or LRS rates while the other 65 percent of its customer load has migrated to competitive energy suppliers.  Because this customer migration is only for energy supply service, it has no impact on CL&P’s delivery business or its operating income.

Distribution Rates: On June 30, 2010, PURA issued a final order in CL&P’s most recent retail distribution rate case approving annualized distribution rate increases of $63.4 million effective July 1, 2010 and an incremental $38.5 million effective July 1, 2011.  The 2010 increase was deferred from customer bills until January 1, 2011 to coincide with the decline in revenue requirements associated with the final payment of CL&P’s RRBs.  In its decision, PURA also maintained CL&P’s authorized distribution segment regulatory ROE of 9.4 percent.  In 2011, CL&P earned a distribution segment regulatory ROE of 9.4 percent, compared to 7.9 percent in 2010.

AMI:  On August 29, 2011, PURA issued a draft decision rejecting the full deployment of AMI meters to all of CL&P’s customers at that time.  PURA instead indicated that CL&P should begin installing AMI meters at a more moderate pace once industry standards are developed and CL&P has selected a specific technology to install.  On September 2, 2011, the Commissioner of DEEP filed a motion with PURA to suspend the proceeding while the Bureau of Energy and Technology Policy conducts a process to establish an AMI policy for Connecticut, in accordance with the state law.  On September 8, 2011, PURA granted DEEP’s motion and suspended its proceedings.  No further schedule is available at this time from either DEEP or PURA.  As a result, CL&P has removed the projected AMI capital costs of approximately $257 million from its current five-year capital program.

CL&P has a transmission adjustment clause as part of its retail distribution 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.  

CL&P, jointly with UI, has entered into four CfDs for a total of approximately 787 MW of capacity with three generation projects being built or modified and one demand response project.  The capacity CfDs extend through 2026 and obligate the utilities to pay the difference between a set price and the value that the projects receive in the ISO-NE markets.  The contracts have terms of up to 15 years beginning in 2009 and are subject to a sharing agreement with UI, whereby UI will have a 20 percent share of the costs and benefits of these contracts.  CL&P's portion of the costs and benefits of these contracts will be paid by or refunded to CL&P's customers.

Sources and Availability of Electric Power Supply

As noted above, CL&P does not own any generation assets and purchases energy to serve its SS and LRS loads from a variety of competitive sources through periodic requests for proposals.  CL&P enters into supply contracts for SS periodically for periods of up to three years to mitigate the risks associated with energy price volatility for its residential and small and medium load commercial and industrial customers.  CL&P enters into supply contracts for LRS for larger commercial and industrial customers every three months.  Currently, CL&P has contracts in place with various suppliers for all of its SS loads through 2012, and 40 percent of expected load for 2013.  CL&P’s contracts for its LRS loads extend through the second quarter of 2012.

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE - DISTRIBUTION

PSNH’s distribution business consists primarily of the purchase, delivery and sale of electricity to its residential, commercial and industrial customers.  As of December 31, 2011, PSNH furnished retail franchise electric service to approximately 498,000 retail customers in 211 cities and towns in New Hampshire.  PSNH also owns and operates approximately 1,200 MW of primarily fossil fueled electricity generation plants.  Included in those electric generating plants is PSNH’s 50 MW wood-burning Northern Wood Power Project at its Schiller Station in Portsmouth, New Hampshire, and approximately 70 MW of hydroelectric generation.  PSNH’s distribution segment includes the activities of its generation business.

The Clean Air Project, a wet scrubber project, was constructed and placed in service by PSNH at its Merrimack Station in September 2011.  The cost of the project will be recovered through PSNH's ES rates under New Hampshire law.  By November 2011, both of Merrimack station’s coal-fired units were integrated with the scrubber, and the scrubber is now reducing emissions from the units.  PSNH expects to complete remaining project construction activities in mid-2012.  We currently expect the final costs of the project to be approximately $422 million.

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The following table shows the sources of PSNH’s 2011 electric franchise retail revenues based on categories of customers:

	Sources of Revenue		% of Total Revenues
	Residential		54
	Commercial		35
	Industrial		8
	Other		3
	Total		100%

Rates

PSNH is subject to regulation by the 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 ES rate recovers its generation and purchased power costs from customers on a current basis and allows for an ROE of 9.81 percent on its generation investment.  

Under New Hampshire law, the SCRC allows PSNH to recover its stranded costs, including above-market expenses incurred under mandated power purchase obligations 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. PSNH recovers the costs of these RRBs through the SCRC rate.  The amount of the RRB obligation decreases each quarter and the RRBs are scheduled to be retired as of May 1, 2013.

On an annual basis, PSNH files with the NHPUC an ES/SCRC cost reconciliation filing for the preceding year.  The difference between revenues and costs are included in the ES/SCRC rate calculations and refunded to or recovered from customers in the subsequent period approved by the NHPUC.  

The TCAM allows PSNH to recover on a fully reconciling basis its transmission related costs.  The TCAM is adjusted on July 1 of each year.

Distribution Rates:  On June 28, 2010, the NHPUC approved a joint settlement of PSNH’s rate case allowing a net distribution rate increase of $45.5 million on an annualized basis effective July 1, 2010, an annualized distribution rate decrease of $2.4 million effective July 1, 2011 and projected increases of $9.5 million and $11.1 million on July 1, 2012 and 2013, respectively.  If PSNH’s 12-month trailing average regulatory ROE is greater than 10 percent, amounts over the 10 percent level will be allocated 75 percent to customers and 25 percent to PSNH.  The settlement also provided that the authorized regulatory ROE on distribution only plant will continue at the previously allowed level of 9.67 percent.  PSNH’s distribution segment regulatory ROE was 9.7 percent (including generation) in 2011, compared to 10.2 percent in 2010.

In March 2011, PSNH filed with the NHPUC to collect certain exogenous costs, step increases, and storm costs, as permitted by its 2010 rate case settlement.  These rate increases were offset by the scheduled termination, on June 30, 2011, of a rate recoupment charge, also from the 2010 rate case settlement.  During the second quarter of 2011, the NHPUC issued rate orders approving net increases in revenue requirements effective July 1, 2011 to (1) recover exogenous costs, (2) implement a step increase program for capital additions and the reliability enhancement program, and (3) allow for the recovery of the 2010 windstorm costs.  Together with the scheduled termination of the rate recoupment charge, the net impact of these rate changes was a $2.4 million decrease in rates effective July 1, 2011.

Under New Hampshire law, all of 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, customer migration levels began to increase significantly in 2009 as energy costs decreased from their historic high levels and competitive energy suppliers with more pricing flexibility were able to offer electricity supply at lower prices than PSNH.  By the end of 2011, approximately 2.6 percent of all of PSNH’s customers (approximately 36 percent of load), mostly large commercial and industrial customers, had switched to competitive energy suppliers.  The increased level of migration has caused an increase in the ES rate, as fixed costs of PSNH’s generation assets must be spread over a smaller group of customers and lower sales volume.  The customers that did not choose a third party supplier, predominately residential and small commercial and industrial customers, are now paying a larger proportion of these fixed costs. On July 26, 2011, the NHPUC ordered PSNH to file a rate proposal that would mitigate the impact of customer migration expected to occur when the ES rate is higher than market prices.  On January 26, 2012, the NHPUC rejected the PSNH proposal and ordered PSNH to file a new proposal, no later than June 30, 2012, addressing certain issues raised by the NHPUC.

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

On November 22, 2011, the NHPUC opened a docket to consider the in-service status of the Clean Air Project, the appropriate rate treatment, PSNH’s prudence in construction of the project and the propriety of setting temporary rates.  Hearings on temporary rates are scheduled for March 12 and 13, 2012.  _{Following hearings on temporary rates, it is expected that recovery of costs of the Clean Air}

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_{Project will begin during the second quarter of 2012.  No formal schedule} for the comprehensive prudence review or for permanent rates has been established.

Sources and Availability of Electric Power Supply

During 2011, approximately 72 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 28 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 2012 in a similar manner.  Included in the 72 percent above are PSNH obligations to purchase power from approximately two dozen IPPs, the output of which it either uses to serve its customer load or sells into the ISO-NE market.

WESTERN MASSACHUSETTS ELECTRIC COMPANY - DISTRIBUTION

WMECO’s distribution business consists primarily of the purchase, delivery and sale of electricity to residential, commercial and industrial customers.  As of December 31, 2011, WMECO furnished retail franchise electric service to approximately 206,000 retail customers in 59 cities and towns in the western region of Massachusetts.  WMECO does not own any fossil or hydro-electric generating facilities and purchases its energy requirements from competitive suppliers.  In 2009, pursuant to the Massachusetts Green Communities Act, WMECO was authorized to install 6 MW of solar energy generation in its service territory.  In October 2010, WMECO completed development of a 1.8 MW solar generation facility on a site in Pittsfield, Massachusetts and in December 2011 completed development of a 2.3 MW solar generation facility in Springfield, Massachusetts.  WMECO is continuing to evaluate sites suitable for development of the remaining 1.9 MW of the authorized 6 MW of capacity.  WMECO will sell all energy and other products from its solar generation facilities into the ISO-NE market.

The following table shows the sources of WMECO’s 2011 electric franchise retail revenues based on categories of customers:

	Sources of Revenue		% of Total Revenues
	Residential		57
	Commercial		34
	Industrial		11
	Other		(2)
	Total		100%

Rates

WMECO is subject to regulation by the 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 recover their reasonable operation and capital costs, to attract needed capital and maintain their financial integrity, while also protecting relevant public interests.

Under Massachusetts law, all of WMECO's customers are entitled to choose their energy suppliers, while WMECO remains their distribution company.  WMECO purchases power from competitive suppliers 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 small commercial and industrial customers have continued to buy their power from WMECO at basic service rates.  A greater proportion of large commercial and industrial customers have switched to a competitive energy supplier.

WMECO continues to supply approximately 53 percent of its customer load at basic service rates while the other 47 percent of its customer load has migrated to competitive energy suppliers.  Because this customer migration is only for energy supply service, it has no impact on WMECO’s delivery business or its operating income.

The DPU has approved a number of individual cost and revenue requirement recovery mechanisms over the years. These individual mechanisms recover costs associated with providing energy, retail transmission of energy, administrative costs to procure energy, bad debt costs associated with providing energy, company investments in renewable energy such as solar generation, and credits given to customers who generate renewable energy.  There is also a mechanism for the recovery of stranded generation costs as a result of the 1999 electric restructuring act in Massachusetts.  Additionally the DPU has provided cost and revenue requirement recovery mechanisms for certain operating expenses.  These individual mechanisms include recovery of employee pension and post-retirement health benefit costs, certain state government regulatory review, energy efficiency programs, customer arrearage forgiveness programs and low income customer discounts.  In WMECO’s January 31, 2011 rate decision, WMECO received approval for a revenue decoupling reconciliation mechanism that provides assurance that WMECO will recover a DPU pre-established level of baseline distribution delivery service revenue to manage all other distribution operating expenses and earn a level of return on its capital investment. The reconciliation mechanisms noted above are trued up on an annual basis producing deferrals for future recovery.

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Distribution Rates:  On January 31, 2011, the DPU issued a final decision in WMECO’s July 2010 rate application, authorizing a $16.8 million annualized rate increase in distribution revenues and an allowed regulatory ROE of 9.6 percent effective February 1, 2011.  The DPU also authorized WMECO’s request to recover certain active hardship account balances, the recovery of certain storm costs over five years and a full decoupling mechanism, whereby actual revenue billed by WMECO is reconciled with WMECO’s target revenue on an annual basis.  The DPU did not authorize rate recovery of a proposed $20 million average increase in WMECO’s capital spending plan.  WMECO’s distribution segment regulatory ROE was 9 percent in 2011, compared to 4.6 percent in 2010.  

WMECO is subject to service quality (SQ) metrics that measure safety, reliability and customer service, and WMECO pays any charges incurred for failure to meet such metrics to customers.  WMECO will not be required to pay an assessment charge for its 2011 performance results as WMECO performed at or above its target for all of its SQ metrics in 2011.

Sources and Availability of Electric Power Supply

As noted above, WMECO does not own any generation assets (other than its recently developed solar generation) and purchases its energy requirements from a variety of competitive sources through requests for proposals issued periodically, consistent with DPU regulations.  WMECO enters into supply contracts for basic service for 50 percent of its residential and small commercial and industrial customers twice a year for twelve month terms.  WMECO enters into supply contracts for basic service for 100 percent of large commercial and industrial customers every three months.

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 208,000 customers in 71 cities and towns), and size of service territory (2,187 square miles).  Total throughput (sales and transportation) in 2011 was approximately 55 Bcf.  Yankee Gas provides firm natural gas sales service to retail customers who require a continuous natural gas supply throughout the year, such as residential customers who rely on gas for heating, hot water and cooking needs, and commercial and industrial customers who choose to purchase natural gas from Yankee Gas.  Yankee Gas also owns a 1.2 Bcf LNG facility in Waterbury, Connecticut, which is used primarily to assist it in meeting its supplier-of-last-resort obligations and also enables it to make economic purchases of natural gas, which typically occur during periods of low demand.

Retail natural gas service in Connecticut is partially unbundled: residential customers in Yankee Gas’ service territory buy gas supply and delivery only from Yankee Gas while commercial and industrial customers may choose their gas suppliers.  Yankee Gas 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 commercial and industrial customers that have the capability to switch from natural gas to an alternative fuel on short notice, for whom Yankee Gas can interrupt service during peak demand periods or at any other time to maintain distribution system integrity.  

The following table shows the sources of 2011 natural gas operating revenues based on categories of customers:

	Sources of Revenue		% of Total Revenues
	Residential		50
	Commercial		30
	Industrial		17
	Other		3
	Total		100%

A summary of firm natural gas sales in million cubic feet for Yankee Gas for 2011 and 2010 and the percentage changes in 2011, as compared to 2010 on an actual and weather normalized basis (using a 30-year average) is as follows:

		For the Year Ended December 31, 2011 Compared to 2010
Firm Natural Gas		Sales (million cubic feet) (1)       2011                    2010				Percentage Increase		Weather Normalized Percentage Increase/ (Decrease)
Residential		13,508		13,403		0.8%			(3.2)%
Commercial		17,175		15,137		13.5%			9.8%
Industrial		16,197		14,866		8.9%			8.0%
Total		46,880		43,406		8.0%			5.1%
Total, Net of Special Contracts (2)		38,197		35,038		9.0%			5.4%

⁽¹⁾

The 2010 sales volumes for commercial customers have been adjusted to conform to current year presentation.  

⁽²⁾

Special contracts are unique to the customers who take service under such an arrangement and generally specify the amount of distribution revenue to be paid to Yankee Gas regardless of the customers’ usage.

Our firm natural gas sales are subject to many of the same influences as are our retail electric sales, but have benefitted from migration of interruptible customers switching to firm service rates and the addition of gas-fired distributed generation in Yankee Gas' service territory.  Actual firm natural gas sales in 2011 were 8 percent higher than 2010.  Colder weather, especially in the first quarter of 2011,

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was a contributing factor to the higher sales.  Heating degree days for 2011 in Connecticut were 6.4 percent higher than 2010.  On a weather normalized basis, actual firm natural gas sales in 2011 were 5.1 percent higher than 2010.

In November 2011, Yankee Gas completed construction of its WWL project, a 16-mile natural gas pipeline between Waterbury and Wallingford, Connecticut and an increase of vaporization output of its LNG plant.  Construction on the project began in April 2010 and total costs were approximately $54 million.  

Rates

Yankee Gas is subject to regulation by PURA, 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, affiliate transactions, management efficiency and construction and operation of distribution, production and storage facilities.

Distribution Rates:  On June 29, 2011 PURA issued a final decision in Yankee Gas’ rate proceeding, which it amended in September 2011.  The final amended decision approved a regulatory ROE of 8.83 percent, based on a capital structure of 52.2 percent common equity and 47.8 percent debt, approved the inclusion in rates of costs associated with the WWL project, and also allowed for a substantial increase in annual spending for bare steel and cast iron pipe replacement, as requested by Yankee Gas.  Yankee Gas’ regulatory ROE was 9.3 percent in 2011, as compared to 8.6 percent in 2010.

Sources and Availability of Natural Gas Supply

PURA requires that Yankee Gas meet the needs of its firm customers under all weather conditions.  Specifically, Yankee Gas must structure its supply portfolio to meet firm 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 also owns a 1.2 Bcf LNG facility in Waterbury, Connecticut, which is used primarily to assist the company in meeting its supplier-of-last-resort obligations and also enables Yankee Gas to make economic purchases of natural gas, typically in periods of low demand.  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 capacity from the three interstate pipelines that directly 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, Iroquois Gas Transmission Pipeline, Algonquin Pipeline, Union Gas Limited, Dominion Transmission, Inc., National Fuel Gas Supply Corporation, Transcontinental Gas Pipeline Company, and Texas Eastern Transmission, L.P. pipelines.  Yankee Gas considers these transportation arrangements adequate for its needs.

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 of all market participants, has served since 2005 as the regional transmission organization of the New England transmission system.  ISO-NE works to ensure the reliability of the system, administers, subject to FERC approval, the independent system operator tariff, oversees the efficient and competitive functioning of the regional wholesale power market and determines which costs of all regional major transmission facilities are shared by consumers throughout New England.

Wholesale Transmission Rates

Wholesale transmission revenues are recovered through formula rates that are approved by the FERC.  Our transmission revenues are recovered from New England customers through charges that recover costs of transmission and other transmission-related services provided by all regional transmission owners, with a portion of those revenues collected from the distribution segments of CL&P, PSNH and WMECO.  These rates provide for the annual reconciliation and recovery or refund of estimated costs to actual costs.  The difference between estimated and actual costs is deferred for future recovery from, or refunded to, transmission customers.

FERC ROE Proceedings

Pursuant to a series of orders involving the ROE for regionally planned New England transmission projects, the FERC set the base ROE at 11.14 percent and approved incentives that increased the ROE to 12.64 percent for those projects that were in-service by the end of 2008.  Beginning in 2009, the ROE for all regional transmission investment approved by ISO-NE is 11.64 percent, which includes the 50 basis points for joining the regional transmission organization.  In addition, certain projects were granted additional ROE incentives by FERC under its transmission incentive policy.  As a result, CL&P earns between 12.64 percent and 13.1 percent on its major transmission projects and WMECO earns 12.89 percent on the Massachusetts portion of GSRP.  All appeals of FERC's incentive ROE orders for New England transmission owners have been denied.  

On September 30, 2011, several New England state attorneys general, state regulatory commissions, consumer advocates and other parties filed a joint complaint with the FERC under Sections 206 and 306 of the Federal Power Act alleging that the base ROE used in calculating formula rates for transmission service under the ISO-NE Open Access Transmission Tariff by New England transmission

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owners, including CL&P, PSNH and WMECO, is unjust and unreasonable.  The complainants asserted that the current 11.14 percent rate, which became effective in 2006, is excessive due to changes in the capital markets, and seek an order to reduce the rate to 9.2 percent, effective September 30, 2011.

On October 20, 2011, the New England transmission owners responded to the complaint, asking FERC to dismiss the complaint on the basis that the complainants failed to carry their burden of proof under Section 206 of the Federal Power Act to demonstrate that the existing base ROE is unjust and unreasonable.  The New England transmission owners included testimony and analysis reflecting a base ROE of 11.2 percent using FERC’s methodology and precedents, which they believe demonstrates that the current base ROE of 11.14 percent remains just and reasonable.

As of December 31, 2011, CL&P, PSNH, and WMECO had approximately $1.5 billion of aggregate shareholder equity invested in their transmission facilities.  As a result, each 10 basis point change in the authorized base ROE would change annual consolidated earnings by approximately $1.5 million.

FERC has not issued an order in this proceeding and NU cannot predict when this proceeding will be concluded, the outcome of this proceeding, or its impact on NU’s financial position, results of operations or cash flows.

Transmission Projects

NEEWS

CL&P and WMECO are continuing to develop and construct the NEEWS project, which is comprised of GSRP, the Interstate Reliability Project and the Central Connecticut Reliability Project, and is estimated to cost $1.3 billion in the aggregate.  

CL&P and WMECO commenced substation construction on GSRP, the largest project in NEEWS, in December 2010 and began full construction in Connecticut and Massachusetts in late 2011.  GSRP was approximately 50 percent complete as of December 31, 2011 and we expect it to be placed in service in late 2013 at a cost of approximately $718 million.  

CL&P is designing and building the Interstate Reliability Project in coordination with National Grid USA, whose segment of this phase will interconnect with CL&P’s at the Connecticut-Rhode Island border.  In August 2010, ISO-NE reaffirmed the need for the Interstate Reliability Project.  CL&P filed its siting applications in late 2011 and approvals are expected in late 2013, with construction commencing in late 2013 or early 2014.  We expect the project will be placed in service in late 2015 and that CL&P's share of the costs will be $218 million.  

The Central Connecticut Reliability Project, which involves construction of a new 345 KV overhead line from Bloomfield, Connecticut to Watertown, Connecticut at a cost of $301 million, is the third major part of NEEWS.  In March 2011, ISO-NE announced that it would review the Central Connecticut Reliability Project along with other central Connecticut projects as part of a study known as the Greater Hartford Central Connecticut Study.  We expect ISO-NE to issue preliminary need results and transmission solutions in 2013.   

Included as part of NEEWS are expenditures for associated reliability related projects, all of which have received siting approval and most of which are under construction.  These projects began going into service in 2010 and will continue to go into service through 2013.

Northern Pass Transmission Line Project

NPT is a limited liability company jointly owned by NU and NSTAR to construct, own and operate the Northern Pass transmission line, a planned HVDC transmission line from the Québec-New Hampshire border to Franklin, New Hampshire and an associated alternating current radial transmission line between Franklin and Deerfield, New Hampshire.  Northern Pass will interconnect at the Québec/New Hampshire border with a planned HVDC transmission line being developed by HQ.  NUTV, a subsidiary of NU, holds a 75 percent interest in NPT, with NSTAR Transmission Ventures, Inc., a subsidiary of NSTAR, holding the remaining 25 percent.  We currently estimate that our 75 percent share of the costs to build the Northern Pass transmission project will be approximately $830 million out of total expected costs of approximately $1.1 billion (including capitalized AFUDC).

Under a TSA between NPT and Hydro Renewable Energy, a subsidiary of HQ, NPT will sell to Hydro Renewable Energy 1,200 MW of firm electric transmission rights over the Northern Pass for a 40-year term and charge cost-based rates.  The projected cost-of-service calculation includes an ROE of 12.56 percent through the construction phase of the project and, during commercial operation, the ROE will be equal to the ISO-NE regional rates base ROE (currently 11.14 percent) plus 1.42 percent.  During the development and construction phases under the TSA, NPT will record non-cash AFUDC earnings.  On March 18, 2011, the NHPUC filed a request with the FERC seeking rehearing on the ROE granted to Northern Pass.  On August 5, 2011, FERC denied the request by the NHPUC.

In October 2010, NPT filed the Northern Pass project design with ISO-NE for technical approval and filed a presidential permit application with the DOE seeking permission for NPT to construct and maintain facilities that cross the U.S. border.  The DOE held seven meetings in New Hampshire in mid-March 2011 seeking public comment.  In response to concerns raised at these meetings, NPT revised its application to request additional time during the public comment period to allow NPT to review alternative routes.  On June 15, 2011, the DOE extended the scoping comment period for at least forty-five days after NPT files an alternative route with the DOE.  After the final route has been identified, certain environmental studies will need to be completed in order to obtain DOE permits. We expect to commence construction in 2014 and place the project in service in the fourth quarter of 2016.

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On February 8, 2012, the New Hampshire legislature passed a bill that could potentially prohibit the use of eminent domain for the development of any “non-reliability“ electric transmission projects such as Northern Pass.  The bill is currently awaiting action by the Governor.  We are reviewing the potential impact of the bill on NPT, should it be enacted, including its effect on the project's route, cost and schedule.  We believe that NPT will be able to acquire the necessary rights along an acceptable route, which would make it feasible to construct the project even if the bill is enacted.  Given the ultimate design needs of the project, along with siting and permit requirements, which will vary depending upon the route ultimately selected, there is a possibility for further delay in commencement of construction.

Other Transmission Transactions

On May 31, 2011, CL&P and the Connecticut Transmission Municipal Electric Energy Cooperative (CTMEEC), a non-profit municipal joint action transmission entity formed by several Connecticut municipal electric utilities, completed the sale by CL&P to CTMEEC of a segment of high voltage transmission lines built by CL&P in the town of Wallingford, Connecticut.  The assets were sold at their net book value of $42.5 million, plus reimbursement of closing costs.  CL&P is operating and maintaining the lines under an agreement with CTMEEC.  The transaction did not include the transfer of land or equipment unrelated to electric transmission service.   

Transmission Rate Base

Under our FERC-approved tariff, transmission projects generally enter rate base after they are placed in commercial operation.  At the end of 2011, our transmission rate base was approximately $2.96 billion, including approximately $2.1 billion at CL&P, $390 million at PSNH and $467 million at WMECO.  We forecast that our total transmission rate base will grow to approximately $4.8 billion by the end of 2016, including approximately $804 million at NPT.   

CONSTRUCTION AND CAPITAL IMPROVEMENT PROGRAM  

The principal focus of our construction and capital improvement program is maintaining, upgrading and expanding our existing electric transmission, distribution and generation systems and our natural gas distribution system.  Our consolidated capital expenditures in 2011 totaled approximately $1.2 billion, essentially all of which was expended by the Regulated companies.  The 2012 capital expenditures of these companies are estimated to total approximately $1.14 billion, $500 million by CL&P, $212 million by PSNH, $251 million by WMECO, $40 million by NPT, and $94 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 we expect to become committed projects in 2012.

In 2011, CL&P’s transmission capital expenditures totaled $128.6 million, and its distribution capital expenditures totaled $338.5 million.  For 2012, CL&P projects transmission capital expenditures of $174 million and distribution capital expenditures of $315 million.  During the period 2012 through 2016, CL&P plans to invest approximately $837 million in transmission projects, the majority of which will be for NEEWS, and $1.42 billion on distribution projects.  In addition, CL&P expects to spend $11 million on regulated generation in 2012, and a total of $45 million during the period 2012 through 2016.  If all of the transmission and distribution projects are built as proposed, CL&P’s rate base for transmission assets is projected to increase from approximately $2.1 billion at the end of 2011 to approximately $2.45 billion by the end of 2016, and its rate base for electric distribution is projected to increase from approximately $2.6 billion to approximately $3.11 billion over the same period.

In 2011, PSNH's transmission capital expenditures totaled $68.1 million, its distribution capital expenditures totaled $98.8 million and its generation capital expenditures totaled $124.8 million.  For 2012, PSNH projects transmission capital expenditures of $66 million, distribution capital expenditures of $112 million and generation capital expenditures of $34 million.  During the period 2012 through 2016, PSNH plans to spend $468 million on transmission projects, $560 million on distribution projects, and $159 million on generation projects.  If all of the transmission, distribution and generation projects are built as proposed, PSNH’s rate base for electric transmission is projected to increase from $390 million at the end of 2011 to $721 million by the end of 2016, and its rate base for distribution and generation assets is projected to increase from approximately $1.6 billion to approximately $1.76 billion over the same period.

In 2011, WMECO's transmission capital expenditures totaled $236.8 million, its distribution capital expenditures totaled $41.8 million and solar generation expenditures were $11.7 million.  In 2012, WMECO projects transmission capital expenditures of $193 million, distribution capital expenditures of $39 million and expenditures of $19 million on solar generation.  During the period 2012 through 2016, WMECO plans to spend $510 million on transmission projects, with the bulk of that amount to be spent on GSRP, $199 million on distribution projects and $49 million on solar generation.  If all of the transmission, distribution and generation projects are built as proposed, WMECO’s rate base for electric transmission is projected to increase from $467 million at the end of 2011 to $814 million by the end of 2016 and its rate base for distribution and generation assets is projected to increase from $441 million to $498 million over the same period.

In addition, we project transmission capital expenditures by NPT of $40 million in 2012 and during the period 2012 through 2016, we project NPT to spend $812 million on Northern Pass.

In 2011, Yankee Gas capital expenditures totaled $102.8 million.  For 2012, Yankee Gas projects total capital expenditures of $94 million, of which $26 million is expected to be related to basic business activities such as relocation of conflicting gas facilities and the purchase of meters, tools and information technology, $48 million related to reliability improvements, and $20 million for load growth and new business requests.  During the period 2012 through 2016, Yankee Gas plans on making $564 million of capital expenditures.  Future capital spending will likely be affected by price differences between the cost of natural gas and home heating oil, natural gas supply, new home construction, road reconstruction, regulatory mandates and business requirements.  Excluding non-recurring major

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projects, NU expects that approximately 25 percent of Yankee Gas’ capital expenditures over the 2012 through 2016 period will be related to basic business activities, approximately 30 percent will be related to load growth and new business, and approximately 45 percent will be related to reliability initiatives and infrastructure.  If all of Yankee Gas’ projects are built as proposed, Yankee Gas’ rate base is projected to increase from $754 million at the end of 2011 to approximately $1.04 billion by the end of 2016.

FINANCING

On April 1, 2011, CL&P completed the remarketing of $62 million of tax-exempt secured PCRBs, which mature on May 1, 2031.  The PCRBs carry a coupon rate of 1.25 percent until April 1, 2012, at which time CL&P expects to remarket the bonds.

On May 26, 2011, PSNH issued $122 million of first mortgage bonds with a coupon rate of 4.05 percent and a maturity date of June 1, 2021, and used the proceeds to redeem $119.8 million of tax-exempt 1992 Series D and 1993 Series E PCRBs, each with a maturity date of May 1, 2021 and a coupon rate of 6 percent.  The refinancing is expected to reduce PSNH’s interest costs by approximately $2.2 million in 2012.

On September 13, 2011, PSNH issued $160 million of first mortgage bonds, due September 1, 2021, with a coupon rate of 3.20 percent, and on September 16, 2011, WMECO issued $100 million of senior unsecured notes due September 15, 2021 carrying a coupon rate of 3.50 percent.

In addition, on October 24, 2011, CL&P issued $120.5 million of PCRBs carrying a coupon rate of 4.375 percent that will mature on September 1, 2028, and $125 million of PCRBs carrying a coupon of 1.25 percent that mature on September 1, 2028 and are subject to mandatory tender on September 3, 2013.  The proceeds of CL&P’s issuances were used to refund $245.5 million of PCRBs that carried a coupon rate of 5.85 percent and had a maturity date of September 1, 2028.  The refinancing is expected to reduce CL&P’s interest costs by approximately $7.5 million in 2012.

Our credit facilities and indentures require that NU parent and certain of its subsidiaries, including CL&P, PSNH, WMECO and Yankee Gas, 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.    

In 2012, in addition to remarketing the $62 million PCRBs at CL&P, NU parent has a debt maturity on April 1, 2012 of $263 million, which NU expects to refinance with proceeds of a new debt issuance, and Yankee Gas has an annual sinking fund requirement of $4.3 million.  Also, in 2012, we expect to issue $150 million of long-term debt comprised of $100 million by WMECO and $50 million by Yankee Gas in the second half of 2012.

NUCLEAR DECOMMISSIONING

General

CL&P, PSNH, WMECO and several other New England electric utilities are stockholders in three inactive regional nuclear generation companies, CYAPC, MYAPC and YAEC (collectively, 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.

OTHER REGULATORY AND ENVIRONMENTAL MATTERS

General

We are regulated in virtually all aspects of our business by various federal and state agencies, including 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 PURA, which has jurisdiction over CL&P and Yankee Gas, the NHPUC, which has jurisdiction over PSNH, and the DPU, which has jurisdiction over WMECO.

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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, 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 2011, PSNH’s Clean Air Project, the installation of a wet flue gas desulphurization system at its Merrimack coal station to reduce its mercury and sulfur dioxide emissions, was placed into service.  The Clean Air Project is expected to be fully operational in mid-2012 and is designed to capture more than 80 percent of the mercury in the coal from the coal burning stations and to reduce sulfur dioxide emissions by more than 90 percent, making Merrimack one of the cleanest coal-burning plants in the nation.  We expect the final costs of the project to be approximately $422 million.  Compliance with additional environmental laws and regulations, particularly air and water pollution control requirements, may cause changes in operations or require further investments in new equipment at existing facilities.  

Water Quality Requirements

The Clean Water Act requires every “point source” discharger of pollutants into navigable waters to obtain a NPDES permit from the EPA 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.  In each of the last three years, the costs incurred by PSNH related to compliance with NPDES and state discharge permits have not been material.  

On September 29, 2011, the EPA issued for public review and comment a draft renewal NPDES permit under the Clean Water Act for PSNH’s Merrimack Station.  The draft permit would require PSNH to install a closed-cycle cooling system at the station.  The EPA estimated that the net present value cost to install this system and operate it over a 20-year period would be approximately $112 million.  On October 27, 2011, the EPA extended the initial 60-day public review and comment period on the draft permit for an additional 90 days until February 28, 2012.  The EPA has no deadline to consider comments and to issue a final permit Merrimack Station can continue to operate under its current permit pending issuance of the final permit and subsequent resolution of appeals by PSNH and other parties.  Due to the site specific characteristics of PSNH's other fossil fueled electric generating stations, we believe it is unlikely that they would have similar permit requirements imposed on them.

Air Quality Requirements

The Clean Air Act Amendments (CAAA), as well as New Hampshire law, impose stringent requirements on emissions of SO₂ and NO_X for the purpose of controlling acid rain and ground level ozone.  In addition, the CAAA address the control of toxic air pollutants.  Requirements for the installation of continuous emissions monitors and expanded permitting provisions also are included.

In December 2011, the EPA finalized the Mercury and Air Toxic Standards (MATS) that require the reduction of emissions of hazardous air pollutants from new and existing coal- and oil-fired electric generating units.  Commonly called the Utility MACT (maximum achievable control technology) rules, it establishes emission limits for mercury, arsenic and other hazardous air pollutants from coal- and oil-fired units.  MATS is the first implementation of a nationwide emissions standard for hazardous air pollutants across all electric generating units and provides utility companies with up to five years to meet the requirements.  PSNH owns and operates approximately 1,000 MW of fossil fueled electric generating units subject to MATS, including the Merrimack, Newington and Schiller stations.  We believe the Clean Air Project at our Merrimack Station, together with existing equipment, will enable the facility to meet the MATS requirements.  A review of the potential impact of MATS on our other PSNH units is not yet complete.  Additional controls may be required at these facilities.  To date, the financial impact of these potential controls has not been determined.

In New Hampshire, the Multiple Pollutant Reduction Program capped NO_X, SO₂ and CO₂ emissions beginning in 2007.  In addition, a 2006 New Hampshire law required PSNH to install a wet flue gas desulphurization system to reduce mercury emissions of its coal fired plants by at least 80 percent from all PSNH coal fired stations (with the co-benefit of reductions in SO₂ emissions as well).  The Clean Air Project enables PSNH to satisfy this requirement.   

 

In addition, Connecticut, New Hampshire and Massachusetts are each members of the RGGI, a cooperative effort by nine northeastern and mid-Atlantic states, to develop a regional program for stabilizing and reducing CO₂ emissions from fossil fueled electric generating plants.  Because CO₂ allowances issued by any participating state are usable across all nine RGGI state programs, the individual state CO₂ trading programs, in the aggregate, 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 currently own any generating assets (other than the solar facilities owned by WMECO, which do not emit CO₂), neither is required to acquire CO₂ allowances; however, the CO₂ allowance costs borne by generators that provide energy supply to CL&P and WMECO will likely be included in wholesale rates charged to them, which costs are then recoverable from customers.

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NU’s carbon emission inventory accounts for and reports all direct carbon dioxide (CO₂) methane (CH₄) nitrous oxide (N₂O) sulfur hexafluoride (SF₆) emissions for operations of NU and its subsidiaries in carbon dioxide equivalents.  Total carbon emissions include those from sources owned or operated by NU (Scope 1) and those that are a consequence of NU’s activities, but occur from sources owned or controlled by others, such as emissions from purchased electricity and line loss during the transmission and distribution of electricity (Scope 2).  NU emissions expressed in thousand metric tons of carbon dioxide equivalent (CO₂-e) for NU and its system companies for 2008 through 2010 are shown below.

	2010		2009		2008
Total CO2-e emissions (excludes CO2  from biomass and biofuels)	3,976		3,930		5,131

Data was collected and calculated using the World Resource Institute greenhouse gas protocol tools except for stationary combustion emissions associated with electric generating units where more accurate Continuous Emissions Monitoring System data was available.  EPA reporting protocol was used for generation calculations where applicable.

PSNH anticipates that its generating units will emit between four million and five million tons of CO₂ per year excluding emissions from the operation of PSNH’s Northern Wood Power Project.  Under the RGGI formula, the Northern Wood Power 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 provided up to 2.5 million banked CO₂ allowances per year for PSNH’s fossil fueled electric generating plants during the 2009 through 2011 compliance period.  These banked CO₂ allowances initially comprised approximately one-half of the yearly CO₂ allowances required for PSNH’s generating plants for compliance 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 our 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 sold to retail customers to have direct ties to renewable sources.  In 2011, the total RPS obligation was 9.58 percent and it will ultimately reach 23.8 percent in 2025.  Energy suppliers, like PSNH, purchase RECs from producers that generate energy from a qualifying resource and use them to satisfy the RPS requirements.  PSNH also owns renewable sources and uses a portion of internally generated RECs and purchased RECs to meet 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 for each REC requirement for which PSNH is deficient.  The costs of both the RECs and alternative compliance payments are recovered by PSNH through its ES rates charged to customers.  

The RECs generated from PSNH’s Northern Wood Power Project, a wood-burning facility, are sold to other energy suppliers and the proceeds from the sale of these RECs is credited back to customers.  

Similarly, Connecticut's RPS statute requires increasing percentages of the electricity sold to retail customers to have direct ties to renewable sources.  In 2011, the total RPS obligation was 15 percent and will ultimately reach 27 percent in 2020.  CL&P is permitted to recover any costs incurred in complying with RPS from its customers through rates.

Massachusetts’ RPS program also requires electricity suppliers to meet renewable energy standards.  For 2011, the requirement was 15.1 percent, and will ultimately reach 27.1 percent in 2020.  WMECO is permitted to recover any costs incurred in complying with RPS from its customers through rates.

Hazardous Materials Regulations

Prior to the last quarter of the 20^th century when environmental best practices and laws were implemented, utility companies often disposed of residues from operations by depositing or burying them on-site or disposing of them at off-site landfills or other facilities.  Typical materials disposed of include coal gasification byproducts, fuel oils, ash, and other materials that might contain polychlorinated biphenyls or that otherwise might be hazardous.  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, based upon currently available information, is 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 these practices.  As of December 31, 2011, 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 $31.7 million, representing 59 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 MGP facilities.  These facilities were owned and operated by our predecessor companies 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.

HWP, a wholly owned subsidiary of NU, is continuing to evaluate additional potential remediation requirements at a river site in Massachusetts containing tar deposits associated with an MGP site that HWP sold to HG&E, a municipal electric utility, in 1902.  

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HWP is at least partially responsible for this site and has already conducted substantial investigative and remediation activities.  HWP's share of the remediation costs related to this site is not recoverable from customers.

Electric and Magnetic Fields

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

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

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.  The EPA 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.  The EPA has mandated GHG emission reporting beginning in 2011 for emissions for certain aspects of our business including stationary combustion, volume of gas supplied to large customers and fugitive emissions of SF-6 gas and methane.

We are continually evaluating the regulatory risks and regulatory uncertainty presented by climate change concerns.  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, carbon taxes, fuel and energy taxes, or regulations requiring additional capital expenditures at our generating facilities.  Product efficiency standards and regulations could impact the demand for energy use by our customers.  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.  

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, (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.  PSNH and its hydroelectric projects are subject to conditions set forth in such licenses, the Federal Power Act 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 that 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.  PSNH is not presently encountering any of these challenges.

EMPLOYEES

As of December 31, 2011, we employed a total of 6,063 employees, excluding temporary employees, of which 1,828 were employed by CL&P, 1,243 were employed by PSNH, 346 were employed by WMECO, 413 were employed by Yankee Gas and 2,228 were employed by NUSCO.  Approximately 2,279 employees of CL&P, PSNH, WMECO, NUSCO and Yankee Gas are members of the International Brotherhood of Electrical Workers or 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.  

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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.

Item 1A.

Risk Factors

In addition to the matters set forth under “Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995” included immediately prior to Item 1, Business, above, we are subject to a variety of significant risks.  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 other matters.  The commissions’ policies and regulatory actions could have a material impact on the Regulated companies’ financial position, results of operations and cash flows.

Our transmission, distribution and generation systems may not operate as expected, and could require unplanned expenditures, which could adversely affect our financial position, results of operations and cash flows.

Our ability to properly operate our transmission, distribution and generation systems is critical to the financial performance of our business.  Our transmission, distribution and generation businesses face several operational risks, including the breakdown or failure of or damage to equipment or processes (especially due to age); labor disputes; disruptions in the delivery of electricity, including impacts on us or our customers; increased capital expenditure requirements, including those due to environmental regulation; information security risk, such as a breach of our systems on which sensitive utility customer data and account information are stored; catastrophic events such as fires, explosions, or other similar occurrences; extreme weather conditions beyond equipment and plant design capacity; and other unanticipated operations and maintenance expenses and liabilities.  The failure of our transmission, distribution and generation systems to operate as planned may result in increased capital costs, reduced earnings or unplanned increases in operation and maintenance costs.  At PSNH, outages at generating stations may be deemed imprudent by the NHPUC resulting in disallowance of replacement power costs.  Such costs that are not recoverable from our customers would have an adverse effect on our financial position, results of operations and cash flows.

Limits on our access to and increases in the cost of 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.  In addition, higher interest rates would increase our cost of borrowing, which could adversely impact our results of operations.  A downgrade of our credit ratings or events beyond our control, such as a disruption in global capital and credit markets, 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 or may elect to exercise their termination rights, which would adversely affect our earnings.

We are exposed to the risk that counterparties to various arrangements who owe us money, have contracted to supply us with energy, coal, or other commodities or services, or who work with us as strategic partners, including on significant capital projects, will not be able to perform their obligations, will terminate such arrangements or, with respect to our credit facilities, fail to honor their commitments.  Should any of these counterparties fail to perform their obligations or terminate such arrangements, we might be forced to replace the underlying commitment at higher market prices and/or have to delay the completion of, or cancel a capital project.  Should any lenders under our credit facilities fail to perform, the level of borrowing capacity under those arrangements could decrease.  In any such events, our financial position, results of operations, or cash flows could be adversely affected.

Difficulties in obtaining necessary rights of way, or siting, design or other approvals for major transmission projects,  environmental concerns or actions of regulatory authorities, communities or strategic partners may cause delays or cancellation of such projects, which would adversely affect our earnings.

Various factors could result in increased costs or result in delays or cancellation of our transmission projects. These include the regulatory approval process, environmental and community concerns, design and siting issues, difficulties in obtaining required rights of way and actions of strategic partners.  Should any of these factors result in such delays or cancellations, our financial position, results of operations, and cash flows could be adversely affected.

Economic events or factors, changes in regulatory or legislative policy and/or regulatory decisions or construction of new generation may delay completion of or displace or result in the abandonment of our planned transmission projects or adversely affect our ability to recover our investments or result in lower than expected earnings.

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Our transmission construction plans could be adversely affected by economic events or factors, new legislation, regulations, or judicial or regulatory interpretations of applicable law or regulations or regulatory decisions.  Any of such events could cause delays in, or the inability to complete or abandonment of, economic or reliability related projects, which could adversely affect our ability to achieve forecasted earnings or to recover our investments or result in lower than expected rates of return.  Recoverability of all such investments in rates may be subject to prudence review at the FERC.  While we believe that all of such costs have been and will be prudently incurred, we cannot predict the outcome of future reviews should they occur.

In addition, our transmission projects may be delayed or displaced by new generation facilities, which could result in reduced transmission capital investments, reduced earnings, and limited future growth prospects.

Many of our transmission projects are expected to help alleviate identified reliability issues and reduce customers' costs.  However, if, due to economic events or factors or further regulatory or other delays, the in-service date for one or more of these projects is delayed, there may be increased risk of failures in the electricity transmission system and supply interruptions or blackouts, 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. Our projected earnings and growth could be adversely affected were FERC to reduce these incentives in the future below the levels presently anticipated.

Increases in electric and gas prices and/or a weak economy, can lead to changes in legislative and regulatory policy promoting energy efficiency, conservation, and self-generation and/or a reduction in our customers’ ability to pay their bills, which may adversely impact our business.

Energy consumption is significantly impacted by the general level of economic activity and cost of energy supply.  Economic downturns or periods of high energy supply costs typically can lead to the development of legislative and regulatory policy designed to promote reductions in energy consumption and increased energy efficiency and self-generation by customers.  This focus on conservation, energy efficiency and self-generation may result in a decline in electricity and gas sales in our service territories.  If any such declines were to occur without corresponding adjustments in rates, then our revenues would be reduced and our future growth prospects would be limited.

In addition, 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 financial position, results of operations or cash flows.

Changes in regulatory and/or legislative policy could negatively impact our transmission planning and cost allocation rules.

The existing FERC-approved New England transmission tariff allocates the costs of transmission facilities that provide regional benefits to all customers of participating transmission-owning utilities.  As new investment in regional transmission infrastructure occurs in any one state, its cost is shared across New England in accordance with a FERC approved formula found in the transmission tariff.  All New England transmission owners' agreement to this regional cost allocation is set forth in the Transmission Operating Agreement.  This agreement can be modified with the approval of a majority of the transmission owning utilities and approval by FERC.  In addition, other parties, such as state regulators, may seek certain changes to the regional cost allocation formula, which could have adverse effects on the rates our distribution companies charge their retail customers.  

FERC has issued rules requiring all regional transmission organizations and transmission owning utilities to make compliance changes to their tariffs and contracts in order to further encourage the construction of transmission for generation, including renewable generation.  This compliance will require ISO-NE and New England transmission owners to develop methodologies that allow for regional planning and cost allocation for transmission projects chosen in the regional plan that are designed to meet public policy goals such as reducing greenhouse gas emissions or encouraging renewable generation. Such compliance may also allow non-incumbent utilities and other entities to participate in the planning and construction of new projects in our service area and regionally.

Changes in the Transmission Operating Agreement, the New England Transmission Tariff or legislative policy, or implementation of these new FERC planning rules, could adversely affect our transmission planning, our earnings and our prospects for growth.

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 distribution and generation businesses.

Under state law, our Regulated 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 such costs incurred by our Regulated companies, such as for construction, operation and maintenance, as well as a return on investment on their respective regulated assets, including the construction costs incurred by PSNH for the Clean Air Project at its Merrimack Station.  PSNH’s expenditures for the project are subject to prudence review by the NHPUC.  The amount of costs incurred by the Regulated companies, coupled with increases in fuel and energy prices, could lead to consumer or regulatory resistance to the timely recovery of such costs, thereby adversely affecting our financial position, results of operations or cash flows.  

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Additionally, state legislators may enact laws that significantly impact our Regulated companies’ revenues, including by mandating electric or gas rate relief and/or by requiring surcharges to customer bills to support state programs not related to the utilities or energy policy.  Such increases could pressure overall rates to our customers and our routine requests to regulators for rate relief.

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 approval to recover the costs of these contracts from the PURA 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.

PSNH meets most of its energy requirements through its own 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 energy to meet its 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.

Migration of customers from PSNH energy service to competitive energy suppliers is increasing the cost to the remaining customers of energy produced by PSNH generation assets and decrease our revenues.

PSNH’s ES rates have been higher than competitive energy prices offered to some customers in recent years, due primarily to lower natural gas prices.  Further increases are expected as the costs associated with the Clean Air Project are fully phased into rates.  The remaining retail energy service customers are experiencing an increase in PSNH’s ES rate by 5 percent to 7 percent due to migration of large commercial and industrial customers and the lower base in which to recover PSNH's fixed generation costs.  This increase may in turn cause further migration and further increasing of PSNH ES rates.  This trend could lead to PSNH continuing to lose retail customers and increasing the burden of supporting the cost of its generation facilities on remaining customers and being unable to support the cost of its generation facilities through an ES rate.  

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

Pursuant to New Hampshire law, PSNH placed the Clean Air Project in service at its Merrimack Station in Bow, New Hampshire. PSNH’s recovery of costs in constructing the project is subject to prudence review by the NHPUC.  A material prudence disallowance could adversely affect PSNH’s financial position, results of operations or cash flows.  While we believe we have prudently incurred all expenditures to date, we cannot predict the outcome of any prudence reviews.  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 position 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, acts of war or terrorism, or cyber breaches could negatively impact our business.

Because our generation and transmission facilities are part of an interconnected regional grid, we face the risk of blackout due to a disruption on a neighboring interconnected system.  

Acts of war or terrorism could target our generating, transmission and distribution facilities or our data management systems.  Such actions could impair our ability to manage these facilities or operate our system effectively, resulting in loss of service to customers.  

In addition, cyber intrusions targeting our information systems could impair our ability to properly manage our data, networks, systems and programs, adversely affect our business operations or lead to release of confidential customer information or critical operating information.  While we have implemented measures designed to prevent cyber-attacks and mitigate their effects should they occur, our systems are vulnerable to unauthorized access and cyber intrusions.  We cannot discount the possibility that a security breach may occur or quantify the potential impact of such an event.

Any such grid disturbances, acts of war or terrorism, or cyber breaches could result in a significant decrease in revenues, significant expense to repair system damage or security breaches, and liability claims, which could have a material adverse impact on our financial position, results of operations or cash flows.

Severe storms could cause significant damage to our electrical facilities requiring extensive capital expenditures, the recovery for which is subject to approval by regulators.

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Severe weather, such as Tropical Storm Irene in August 2011 and the October 29, 2011 snowstorm, and other such major natural disasters, could cause widespread damage to our transmission and distribution facilities.  The resulting cost of repairing damage to our facilities and the potential disruption of our operations could exceed our financial reserves and insurance.  

Tropical Storm Irene and the October 2011 snowstorm caused significant damage to our transmission and distribution systems.  As a result, we have recorded $312 million (predominantly at CL&P) for estimated restoration costs as regulatory assets, subject to future recovery from customers.  If, upon review, any of our state regulatory authorities finds that our actions were imprudent, some of those restoration costs may not be recoverable from customers.  The inability to recover a significant amount of such costs could have an adverse effect on our financial position, results of operations and cash flows.

Market performance or changes in assumptions 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.  Our future pension obligations, costs and liabilities are highly dependent on a variety of factors beyond our control.  These factors include estimated investment returns, interest rates, discount rates, health care cost trends, benefit changes, salary increases and the demographics of plan participants.  If our assumptions prove to be inaccurate, our future costs could increase significantly.  In 2008 and 2009, due to the financial crisis, the value of our pension assets declined.  As a result, we made a contribution of approximately $144 million in 2011 and expect to make an approximate $197 million contribution in 2012.  In addition, various factors, including underperformance of plan investments and changes in law or regulation, could increase the amount of contributions required to fund our pension plan in the future.  Additional 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 negatively affect our financial position, results of operations or cash flows.  

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 that 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 financial position, results of operations or 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 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 financial position, results of operations or 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, included in this Annual Report on Form 10-K.

As a holding company with no revenue-generating operations, NU parent’s liquidity 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 debt service obligations and to pay dividends on its common shares is largely dependent on the ability of its subsidiaries to pay dividends to or to repay borrowings from 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 operating expenses, 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 to 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, dividends and its own debt obligations would be restricted.

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Risks Related to the Pending Merger with NSTAR

We may be unable to obtain the approvals required to complete the merger or such approvals may contain material restrictions or conditions which may make it undesirable to complete the merger.

The merger is subject to numerous conditions, including the approval of PURA and the DPU, which may not approve the merger, or such approvals may impose conditions on the completion, or require changes to the terms of the merger, including restrictions on the business, operations or financial performance of the combined company, which could be adverse to the company's interests.  These conditions or changes could also delay or increase the cost of the merger or limit the net income or financial prospects of the combined company.

We will be subject to business uncertainties and contractual restrictions while the merger is pending.

The work required to complete the merger may place a significant burden on management and internal resources.  Management's attention and other company resources may be focused on the merger instead of on day-to-day management activities, including pursuing other opportunities beneficial to NU.  In addition, while the merger is pending our business operations are restricted by the merger agreement to ordinary course of business activities consistent with past practice, which may cause us to forgo otherwise beneficial business opportunities.

We may lose management personnel and other key employees and be unable to attract and retain such personnel and employees.

Uncertainties about the effect of the merger on management personnel and employees may impair our ability to attract, retain and motivate key personnel until the merger is completed and for a period of time thereafter, which could affect our financial performance.

The merger may not be completed, which may have an adverse effect on our share price and future business and financial results, and we could face litigation concerning the merger, whether or not the merger is consummated.

Failure to complete the merger could negatively affect our share price, as well as our future business and financial results.  If the merger is not completed for certain reasons specified in the merger agreement, we may be required to pay NSTAR a termination fee of $135 million plus up to $35 million of certain expenses incurred by NSTAR.  In addition, we must pay our own costs related to the merger including, among others, legal, accounting, advisory, financing and filing fees and printing costs, whether the merger is completed or not.  Further, whether or not the merger is completed, we could be subject to litigation related to the failure to complete the merger or other factors, which may adversely affect our business, financial results and share price.

If completed, the merger may not achieve its intended results.

We entered into the merger agreement with the expectation that the merger would result in various benefits. If the merger is completed, our ability to achieve the anticipated benefits will be subject to a number of uncertainties, including whether our businesses can be integrated in an efficient and effective manner.  Failure to achieve these anticipated benefits could adversely affect our business, financial results and share price.   

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, 2011, our electric operating subsidiaries owned 32 transmission and 404 distribution substations that had an aggregate transformer capacity of 6,584,000 kilovolt amperes (kVa) and 26,839,000 kVa, respectively; 2,969 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; 34,972 pole miles of overhead and 4,000 conduit bank miles of underground distribution lines; and 551,338 underground and overhead line transformers in service with an aggregate capacity of 38,721,890 kVa.

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Electric Generating Plants

As of December 31, 2011, PSNH owned the following electric generating plants:  

Type of Plant			Number of Units		Year Installed		Claimed Capability* (kilowatts)
Total - Fossil-Steam Plants			5 units		1952-74		953,805
Total - Hydro			20 units		1901-83		68,994
Total - Internal Combustion			5 units		1968-70		101,869
Total - Biomass - Steam Plant			1 unit		1954-2006		42,594
Total PSNH Generating Plant			31 units				1,167,262

*

Claimed capability represents winter ratings as of December 31, 2011.  The combined nameplate capacity of the generating plants is approximately 1,200 MW.

As of December 31, 2011, WMECO owned the following electric generating plant:  

Type of Plant			Number of Sites		Year Installed		Claimed Capability** (kilowatts)
Total - Solar Fixed Tilt, Photovoltaic			2 sites		2010-11		4,100

** Claimed capability represents the direct current nameplate capacity of the plant.

CL&P did not own any electric generating plants during 2011.

Yankee Gas

As of December 31, 2011, Yankee Gas owned 28 active gate stations, 200 district regulator stations, and 3,256 miles of natural gas main pipeline.  Yankee Gas also owns a 1.2 Bcf LNG facility in Waterbury, Connecticut, and 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 PURA determines that such facilities will be more cost effective than other options for mitigating FMCC and Locational Installed Capacity (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 PURA and a determination by the PURA that such purchase is in the public interest.  Finally, Section 127 of Public Act 11-80 allows CL&P to submit a proposal to the DEEP to build, own or operate one or more generation facilities up to 10 MWs using Class 1 renewable energy.

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.  PSNH’s status as a public utility gives it the ability to petition the NHPUC for the right to exercise eminent domain for its transmission and distribution services in appropriate circumstances.  

 

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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 holds valid franchises to sell gas in the areas in which Yankee Gas supplies gas service, which it acquired either directly or from its predecessors in interest.  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 PURA 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.

Item 3.

Legal Proceedings

1.

Yankee Companies v. U.S. Department of Energy

The Yankee Companies (YAEC, MYAPC, and CYAPC) commenced litigation in 1998 against the 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.  On September 7, 2010, the trial court issued its decision following remand and awarded CYAPC $39.7 million, YAEC $21.2 million and MYAPC $81.7 million.  The DOE filed an appeal and the Yankee Companies cross-appealed.  Briefs were filed and oral arguments in the appeal of the remanded case occurred on November 7, 2011.  If the Court follows its previous schedule, a decision could be handed down within six months of the argument (second quarter 2012).  The application of any damages that 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.  On November 18, 2011, the court ordered the record closed in the YAEC case, and closed the record in the CYAPC and MYAPC cases subject to a limited opportunity of the government to reopen the records for further limited proceedings.  The parties’ post-trial briefs will be filed during the first quarter of 2012 with a decision to come thereafter.

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 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 activity and expenditures at the sites are ongoing.  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.  Judgment was entered on March 31, 2010.  On April 23, 2010, the NU Companies filed a Notice of Appeal with respect to the court’s decision, which has been fully briefed.  The Phase II trial, which would determine what portion of the remediation costs at the Waterbury-North site are attributable to UGI's control, was held in August and September, 2011.  We expect a decision in the first quarter of 2012. Any recovery resulting from the case (following the appeal and the Waterbury-North complaint) would flow back to the NU Companies' customers, and the NU Companies would continue to seek

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recovery as appropriate of remediation and other associated costs with regard to the sites for which no recovery from UGI will be forthcoming.   

3.

Bankruptcy of Independent Power Producer

On February 1, 2011, an independent power producer, AES Thames, L.L.C. (Thames), which is the counterparty to a CL&P electricity purchase agreement, filed a voluntary Chapter 11 petition  in the U.S. Bankruptcy Court in Delaware (Case No. 11-10334).  Thames owned and operated a 181 MW coal fired generation plant in Montville, Connecticut providing electric energy to CL&P and process steam to a nearby paperboard manufacturer.  Citing market conditions and regulatory and legislative uncertainties, Thames advised CL&P on January 24, 2011 that it was shutting the plant down for an undetermined period.  Under an amendment to the electricity purchase agreement entered into in 1999, Thames had agreed to supply CL&P with energy from the plant for a reduced price in exchange for a substantial prepayment.  The electricity purchase agreement was due to expire in 2015.  On January 23, 2012, the bankruptcy case was converted to a liquidation under Chapter 7 of the bankruptcy code.  A trustee has been appointed.  No further deliveries under the CL&P contract with Thames will be made.  This matter is not expected to have any impact on CL&P’s results of operations.  

4.

Conservation Law Foundation v. PSNH

On July 21, 2011, the Conservation Law Foundation (CLF) filed a citizens suit under the provisions of the federal Clean Air Act against PSNH alleging permitting violations at the company’s Merrimack generating station.  The suit alleges that PSNH failed to have proper permits for replacement of the Unit 2 turbine at Merrimack and installation of activated carbon injection equipment for the unit, and violated a permit condition concerning operation of the electrostatic precipitators at the station.  The suit seeks injunctive relief, civil penalties, and costs.  CLF has pursued similar claims before the NHPUC, the Air Resources Council, and the Site Evaluation Committee, all of which have been denied.  PSNH believes this suit is without merit and intends to defend it vigorously.  

5.

Other Legal Proceedings

For further discussion of legal proceedings, see Item 1, Business:  “- Regulated Electric Distribution,” “-Regulated Gas Distribution - Yankee Gas Services Company,” and  ”- 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 15, 2012.  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		42		Vice President - Accounting and Controller.
Gregory B. Butler		54		Senior Vice President and General Counsel.
Jean M. LaVecchia*		60		Vice President - Human Resources of NUSCO.
David R. McHale		51		Executive Vice President and Chief Financial Officer.
Leon J. Olivier		63		Executive Vice President and Chief Operating Officer.
James B. Robb*		51		Senior Vice President, Enterprise Planning and Development of NUSCO.
Charles W. Shivery		66		Chairman of the Board, President and Chief Executive Officer.

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

Jay S. Buth.  Mr. Buth was elected 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 was elected 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.

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David R. McHale.  Mr. McHale was elected Executive Vice President and Chief Financial Officer of NU, CL&P, PSNH and WMECO, 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, PSNH and WMECO 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, Inc. 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.

Mine Safety Disclosures

Not applicable.

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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 sales prices for the past two years, by quarter, are shown below:

Year		Quarter		High			Low
2011		First		$	35.13		$	31.19
		Second			36.47			33.31
		Third			35.87			30.02
		Fourth			36.40			30.80
2010		First		$	28.00		$	24.68
		Second			28.21			24.83
		Third			30.25			25.24
		Fourth			32.21			29.51

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, 2011.  

As of January 31, 2011, there were 38,300 registered common shareholders of our company on record.  As of the same date, there were a total of 196,069,808 common shares issued.  

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 14, 2012, our Board of Trustees declared a dividend of 29.375 cents per share, payable on March 30, 2012 to shareholders of record as of March 1, 2012.

On October 11, 2011, our Board of Trustees declared a dividend of 27.5 cents per share, payable on December 30, 2011 to shareholders of record as of November 10, 2011.

On July 12, 2011, our Board of Trustees declared a dividend of 27.5 cents per share, payable on September 30, 2011 to shareholders of record as of September 1, 2011.

On April 12, 2011, our Board of Trustees declared a dividend of 27.5 cents per share, payable on June 30, 2011 to shareholders of record as of June 1, 2011.

On February 8, 2011, our Board of Trustees declared a dividend of 27.5 cents per share, payable on March 31, 2011 to shareholders of record as of March 1, 2011.

On October 12, 2010, our Board of Trustees declared a dividend of 25.625 cents per share, payable on December 31, 2010 to shareholders of record as of December 1, 2010.

On July 12, 2010, our Board of Trustees declared a dividend of 25.625 cents per share, payable on September 30, 2010 to shareholders of record as of September 1, 2010.

On April 13, 2010, our Board of Trustees declared a dividend of 25.625 cents per share, payable on June 30, 2010 to shareholders of record as of June 1, 2010.

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.

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 Item 8, Financial Statements and Supplementary Data, 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 2011 and 2010, CL&P approved and paid $243.2 million and $217.7 million, respectively, of common stock dividends to NU.

During 2011 and 2010, PSNH approved and paid $58.8 million and $50.6 million, respectively, of common stock dividends to NU.

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During 2011 and 2010, WMECO approved and paid $26.3 million and $14.9 million, respectively, of common stock dividends to NU.

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

Item 6.				Selected Consolidated Financial Data
NU Selected Consolidated Financial Data (Unaudited)
(Thousands of Dollars, except percentages and common share information)					2011			2010			2009			2008			2007
Balance Sheet Data:
	Property, Plant and Equipment, Net				$	10,403,065		$	9,567,726		$	8,839,965		$	8,207,876		$	7,229,945
	Total Assets (f)					15,647,066			14,472,601			14,057,679			13,988,480			11,581,822
	Total Capitalization (a)					9,078,321			8,627,985			8,253,323			7,293,960			6,667,920
	Obligations Under Capital Leases (a)					12,358			12,236			12,873			13,397			14,743
Income Statement Data:
	Operating Revenues				$	4,465,657		$	4,898,167		$	5,439,430		$	5,800,095		$	5,822,226
	Income from Continuing Operations					400,513			394,107			335,592			266,387			251,455
	Income from Discontinued Operations					-			-			-			-			587
	Net Income Attributable to Noncontrolling Interests					5,820			6,158			5,559			5,559			5,559
	Net Income Attributable to Controlling Interests				$	394,693		$	387,949		$	330,033		$	260,828		$	246,483
Common Share Data:
	Basic Earnings Per Common Share:
		Income from Continuing Operations			$	2.22		$	2.20		$	1.91		$	1.68		$	1.59
		Income from Discontinued Operations				-			-			-			-			-
		Net Income Attributable to Controlling Interests			$	2.22		$	2.20		$	1.91		$	1.68		$	1.59
	Diluted Earnings Per Common Share:
		Income from Continuing Operations			$	2.22		$	2.19		$	1.91		$	1.67		$	1.59
		Income from Discontinued Operations				-			-			-			-			-
		Net Income Attributable to Controlling Interests			$	2.22		$	2.19		$	1.91		$	1.67		$	1.59
	Weighted Average Common Shares Outstanding
		Basic				177,410,167			176,636,086			172,567,928			155,531,846			154,759,727
		Diluted				177,804,568			176,885,387			172,717,246			155,999,240			155,304,361
	Dividends Declared Per Share				$	1.10		$	1.03		$	0.95		$	0.83		$	0.78
	Market Price - Closing (high) (b)				$	36.31		$	32.05		$	26.33		$	31.15		$	33.53
	Market Price - Closing (low) (b)				$	30.46		$	24.78		$	19.45		$	19.15		$	26.93
	Market Price - Closing (end of year) (b)				$	36.07		$	31.88		$	25.79		$	24.06		$	31.31
	Book Value Per Share (end of year)				$	22.65		$	21.60		$	20.37		$	19.38		$	18.79
	Tangible Book Value Per Share (end of year) (c)				$	21.03		$	19.97		$	18.74		$	17.54		$	16.93
	Rate of Return Earned on Average Common Equity (%) (d)					10.1			10.7			10.2			8.8			8.6
	Market-to-Book Ratio (end of year) (e)					1.6			1.5			1.3			1.2			1.7
Capitalization:
	Total Equity					44	%		44	%		44	%		41	%		44	%
	Preferred Stock, not subject to mandatory redemption					1			1			1			2			2
	Long-Term Debt (a)					55			55			55			57			54
						100	%		100	%		100	%		100	%		100	%
(a)		Includes portions due within one year, but excludes RRBs for Long-Term Debt.
(b)		Market price information reflects closing prices as reflected by the New York Stock Exchange.
(c)		Common Shareholders' Equity adjusted for goodwill and intangibles divided by total common shares outstanding.
(d)		Net Income divided by average Common Shareholders' Equity.
(e)		The closing market price divided by the book value per share.
(f)		As of December 31, 2011, Total Assets has been adjusted to reflect the current portions of regulatory assets and liabilities, and related deferred tax amounts, as current assets and liabilities.  Amounts as of December 31, 2010 have been reclassified to conform to the December 31, 2011 presentation.

26

CL&P Selected Consolidated Financial Data (Unaudited)
(Thousands of Dollars)					2011			2010			2009			2008			2007
Operating Revenues					$	2,548,387		$	2,999,102		$	3,424,538		$	3,558,361		$	3,681,817
Net Income						250,164			244,143			216,316			191,158			133,564
Cash Dividends on Common Stock						243,218			217,691			113,848			106,461			79,181
Property, Plant and Equipment, Net						5,827,384			5,586,504			5,340,561			5,089,124			4,401,846
Total Assets (b)						8,791,396			8,255,192			8,364,564			8,336,118			7,018,099
Rate Reduction Bonds						-			-			195,587			378,195			548,686
Long-Term Debt (a)						2,583,753			2,583,102			2,582,361			2,270,414			2,028,546
Preferred Stock Not Subject to Mandatory Redemption						116,200			116,200			116,200			116,200			116,200
Obligations Under Capital Leases (a)						10,715			10,613			10,956			11,207			13,602
PSNH Selected Consolidated Financial Data (Unaudited)
(Thousands of Dollars)					2011			2010			2009			2008			2007
Operating Revenues					$	1,013,003		$	1,033,439		$	1,109,591		$	1,141,202		$	1,083,072
Net Income						100,267			90,067			65,570			58,067			54,434
Cash Dividends on Common Stock						58,828			50,584			40,844			36,376			30,720
Property, Plant and Equipment, Net						2,256,688			2,053,281			1,814,714			1,580,985			1,388,405
Total Assets (b)						3,116,541			2,879,121			2,697,191			2,628,833			2,106,969
Rate Reduction Bonds						85,368			138,247			188,113			235,139			282,018
Long-Term Debt (a)						997,722			836,365			836,255			686,779			576,997
Obligations Under Capital Leases (a)						1,326			1,428			1,670			1,931			1,141

WMECO Selected Consolidated Financial Data (Unaudited)
(Thousands of Dollars)						2011			2010			2009			2008			2007
Operating Revenues						$	417,315		$	395,161		$	402,413		$	441,527		$	464,745
Net Income							43,054			23,090			26,196			18,330			23,604
Cash Dividends on Common Stock							26,305			14,882			18,203			39,706			12,779
Property, Plant and Equipment, Net							1,077,833			817,146			705,760			624,205			559,357
Total Assets							1,502,893			1,199,559			1,101,800			1,048,489			991,088
Rate Reduction Bonds							26,892			43,325			58,735			73,176			86,731
Long-Term Debt (a)							499,545			400,288			305,475			303,868			303,872
Obligations Under Capital Leases (a)							141			83			105			126			-
(a)				Includes portions due within one year, but excludes RRBs for Long-Term Debt.
(b)				As of December 31, 2011, Total Assets has been adjusted to reflect the current portions of regulatory assets and liabilities, and related deferred tax amounts, as
				current assets and liabilities.  Amounts as of December 31, 2010 have been reclassified to conform to the December 31, 2011 presentation.
See the Combined Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for a description of any accounting changes materially affecting the comparability of the information reflected in the tables above.

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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 diluted basis.  

Refer to the Glossary of Terms included in this Annual Report on Form 10-K for abbreviations and acronyms used throughout this Management's Discussion and Analysis of Financial Condition and Results of Operations.  

The only common equity securities that are publicly traded are common shares of NU.  The earnings and 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 GAAP that is calculated by dividing the Net Income Attributable to Controlling Interests of each business by the weighted average 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 diluted EPS determined in accordance with GAAP as an indicator of operating performance.

The discussion below also includes non-GAAP financial measures referencing our 2011 earnings and EPS excluding expenses related to NU's pending merger with NSTAR and a non-recurring charge at CL&P for the establishment of a reserve to provide bill credits to its residential customers and donations to charitable organizations, as well as our 2010 earnings and EPS excluding merger expenses incurred in 2010 and certain non-recurring benefits from the settlement of tax issues.  We use these non-GAAP financial measures to more fully compare and explain the 2011, 2010 and 2009 results without including the impact of these non-recurring items.  Due to the nature and significance of these items on Net Income Attributable to Controlling Interests, 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 Interests 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 diluted EPS and Net Income Attributable to Controlling Interests 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.  All forward-looking information for 2012 and thereafter provided in this Management’s Discussion and Analysis assumes we will operate on a stand-alone basis, excluding the impacts of the pending merger with NSTAR, unless otherwise indicated.

Financial Condition and Business Analysis

Pending Merger with NSTAR:

On October 18, 2010, NU and NSTAR announced that each company's Board of Trustees unanimously approved a merger agreement (the “agreement”), under which NSTAR will become a direct wholly owned subsidiary of NU.  On October 14, 2011, NU and NSTAR extended the termination date of the agreement, as defined therein, from October 16, 2011 to April 16, 2012.  The transaction is structured as a merger of equals in a tax-free exchange of shares.  Under the terms of the agreement, NSTAR shareholders will receive 1.312 NU common shares for each NSTAR common share that they own (the “exchange ratio”).  Following the merger, NU will provide electric and natural gas energy delivery service to approximately 3.5 million electric and natural gas customers through six regulated electric and natural gas utilities in Connecticut, Massachusetts and New Hampshire.  On March 4, 2011, NU shareholders approved the agreement, approved an increase in the number of NU common shares authorized for issuance by 155 million common shares to 380 million common shares and fixed the number of trustees at 14.  NSTAR shareholders approved the agreement on March 4, 2011.

Subject to the conditions in the agreement, our first quarterly dividend per common share paid after the closing of the merger will be increased to an amount that is at least equal, after adjusting for the exchange ratio, to NSTAR's last quarterly dividend paid prior to the closing.  

Completion of the merger is subject to various customary conditions, including, among others, receipt of all required regulatory approvals.  NU and NSTAR are awaiting approvals from PURA and the DPU.  PURA is scheduled to issue a final decision on April 2, 2012.  On February 15, 2012, NU and NSTAR reached comprehensive merger-related settlement agreements with both the Massachusetts Attorney General and the Massachusetts Department of Energy Resources agreeing to certain conditions with respect to the merger, which are subject to DPU approval and have been requested by the parties to be approved on April 4, 2012.  If both PURA and the DPU issue acceptable decisions by such dates, we expect the merger will be consummated by April 16, 2012.  For further information regarding regulatory approvals on the pending merger, see “Regulatory Developments and Rate Matters – Regulatory Approvals for Pending Merger with NSTAR,” in this Management's Discussion and Analysis.

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Executive Summary

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

Results:

·

We earned $394.7 million, or $2.22 per share, in 2011, compared with $387.9 million, or $2.19 per share, in 2010.  Excluding merger-related costs of $11.3 million, or $0.06 per share, and a non-recurring charge at CL&P of $17.9 million, or $0.10 per share, we earned $423.9 million, or $2.38 per share, in 2011.  The non-recurring charge at CL&P relates to the establishment of a reserve to provide bill credits to its residential customers and donations to charitable organizations (“storm fund reserve”).  Improved results in 2011 were due primarily to the impact of electric distribution rate case decisions that were effective July 1, 2010 for CL&P and PSNH and February 1, 2011 for WMECO and the impact of a higher level of investment in transmission infrastructure.

·

Our Regulated companies earned $420.4 million, or $2.36 per share, in 2011, including the $17.9 million CL&P storm fund reserve, compared with $384 million, or $2.16 per share, in 2010.  

·

The distribution segment of our Regulated companies earned $220.8 million, or $1.24 per share, in 2011, including the $17.9 million CL&P storm fund reserve, compared with $206.2 million, or $1.16 per share, in 2010.  The transmission segment of our Regulated companies earned $199.6 million, or $1.12 per share, in 2011, compared with $177.8 million, or $1.00 per share, in 2010.  

·

NU parent and other companies recorded net expenses of $25.7 million, or $0.14 per share, in 2011, compared with earnings of $3.9 million, or $0.03 per share, in 2010.  In 2011, excluding merger-related costs of $11.3 million, or $0.06 per share, NU parent and other companies recorded net expenses of $14.4 million, or $0.08 per share.  In 2010, results included a non-recurring benefit of $15.7 million, or $0.09 per share, associated with the settlement of tax issues and a charge of $9.4 million, or $0.06 per share, associated with merger-related costs.

2011 Major Storm Items:

·

On August 28, 2011, Tropical Storm Irene caused extensive damage to our distribution system resulting in incremental restoration costs of $135.6 million, $123.8 million of which were incurred by CL&P.  Approximately 800,000 of our 1.9 million electric distribution customers were without power at the peak of the outages.  CL&P capitalized $18.2 million of the restoration costs and deferred $105.6 million for future recovery.  

·

On October 29, 2011, an unprecedented storm inundated our service territory with heavy snow causing significant damage to our distribution and transmission systems resulting in incremental restoration costs of $218.5 million, $22.6 million of which were capitalized and $195.9 million were deferred for future recovery.  Approximately 1.2 million of our electric distribution customers were without power at the peak of the outages.  This was the largest storm in CL&P’s and WMECO's history and third largest in PSNH’s history in terms of customer outages.  CL&P’s portion of incremental restoration costs was $174.6 million, of which $16.9 million was capitalized and $157.7 million was deferred for future recovery.  

·

The storms met the regulatory criteria for cost deferral and as a result, except for the CL&P storm fund reserve, they had no material impact on our results of operations.  We believe our response to the storm damage was prudent and therefore we believe it is probable that CL&P, PSNH and WMECO will be allowed to recover these storm costs.  Each operating company will seek recovery of its estimated deferred storm costs through its applicable regulatory recovery process.  

·

CL&P recorded a storm fund reserve of $30 million ($17.9 million after-tax) to provide bill credits to its residential customers who remained without power after noon on Saturday, November 5, 2011 as a result of the October snowstorm, and to provide donations to certain Connecticut charitable organizations.  CL&P will not seek to recover this amount in its rates.  

·

A number of governmental inquiries have been initiated in Connecticut, New Hampshire and Massachusetts to review the response of utilities and other entities to Tropical Storm Irene and the October snowstorm.  Certain reviews were completed while other inquiries are expected to be completed in the second quarter of 2012.

Strategy, Legislative, Regulatory and Other Items:

·

On June 29, 2011, the DPUC (now PURA) issued a final decision in the Yankee Gas rate proceeding that was amended on September 28, 2011.  The decision resulted in essentially no changes to distribution rates for 2011 and an increase of approximately $7 million in Yankee Gas’ annual revenues beginning July 1, 2012.

·

On September 30, 2011, several parties filed a joint complaint with the FERC alleging that the base ROE used in calculating formula rates for transmission service under the ISO-NE Open Access Transmission Tariff by New England transmission owners, including CL&P, PSNH and WMECO, is unjust and unreasonable, and seeking an order to reduce the rate from 11.14 percent to 9.2 percent.  On October 20, 2011, the New England transmission owners filed their response seeking dismissal of the complaint on the basis that the complainants failed to demonstrate that the existing base ROE is unjust and unreasonable and provided testimony and analysis demonstrating that the 11.14 percent base ROE remains just and reasonable.  The FERC has not yet issued an order in this proceeding.  

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·

On September 13, 2011, CL&P and WMECO received the required permit from U.S. Army Corps of Engineers allowing them to commence full construction of GSRP.  The $718 million project is expected to be placed in service in late 2013.  As of December 31, 2011, GSRP was approximately 50 percent complete.

·

In September 2011, the Clean Air Project was placed in service at PSNH’s Merrimack Station.  By November 2011, both of the Merrimack Station’s coal-fired units were integrated with the scrubber, which is reducing emissions from the units.  Finalization of project activities, including water discharge enhancements, is expected in mid-2012.  We expect the project will cost approximately $422 million.  

·

Yankee Gas’ WWL project was completed and placed in service in November 2011.  Project costs totaled approximately $54 million, $3.6 million below the previous estimate of $57.6 million.

·

On December 23, 2011, CL&P filed a siting application with the Connecticut Siting Council to build the 40-mile, $218 million Connecticut section of the IRP.  In early 2012, National Grid is expected to file siting applications with regulators in Massachusetts and Rhode Island to build its sections of the IRP.  We expect to receive approvals from all three states in late 2013 and to place the IRP in service by late 2015.  

Liquidity:

·

Cash and cash equivalents totaled $6.6 million as of December 31, 2011, compared with $23.4 million as of December 31, 2010, while cash capital expenditures totaled $1.1 billion in 2011, compared with $954.5 million in 2010.

·

On February 14, 2012, our Board of Trustees declared a quarterly common dividend of $0.29375 per share, payable on March 30, 2012 to shareholders of record as of March 1, 2012, which equates to $1.175 per share on an annualized basis.  Assuming our pending merger with NSTAR closes in 2012 after NSTAR pays its March 30, 2012 dividend of $0.45 per share, the terms of the merger agreement would require NU's first quarterly dividend paid after the merger to be at least $0.343 per share, or at least $1.372 per share on an annualized basis.

·

Cash flows provided by operating activities in 2011 totaled $901.1 million, compared with $832.6 million in 2010 (amounts are net of RRB payments).  The improved cash flows in 2011 were due primarily to the impact of the recent electric distribution rate case decisions and 2011 income tax refunds, as compared to 2010 income tax payments, partially offset by a Pension Plan contribution and cash disbursements associated with major storm costs.  On a stand-alone basis, 2012 cash flows provided by operating activities, net of RRB payments, are expected to be lower than in 2011 due primarily to approximately $50 million more in Pension Plan contributions than in 2011 and approximately $27 million in bill credits provided to CL&P residential customers in February 2012.

·

In 2011, we issued $260 million of new long-term debt consisting of $160 million by PSNH and $100 million by WMECO.  Additionally, CL&P remarketed $62 million of tax-exempt secured PCRBs in April 2011 and refinanced $245.5 million of PCRBs in October 2011.  PSNH refinanced $119.8 million of PCRBs in May 2011.  In April 2012, NU parent has a debt maturity of $263 million, which we expect will be refinanced.  In addition to remarketing the CL&P $62 million PCRBs, we expect to issue $150 million of long-term debt comprised of $100 million by WMECO and $50 million by Yankee Gas in the second half of 2012.

Overview

Consolidated:  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 Interests and diluted EPS, for 2011, 2010 and 2009 is as follows:

		For the Years Ended December 31,
		2011						2010						2009
(Millions of Dollars, except   per share amounts)		Amount			Per Share			Amount			Per Share			Amount			Per Share
Net Income Attributable to   Controlling Interests (GAAP)		$	394.7		$	2.22		$	387.9		$	2.19		$	330.0		$	1.91
Regulated Companies		$	438.3		$	2.46		$	384.0		$	2.16		$	323.5		$	1.87
NU Parent and Other Companies			(14.4)			(0.08)			(2.4)			(0.00)			6.5			0.04
Non-GAAP Earnings			423.9			2.38			381.6			2.16			330.0			1.91
Non-Recurring Tax Settlements			-			-			15.7			0.09			-			-
Merger-Related Costs			(11.3)			(0.06)			(9.4)			(0.06)			-			-
Storm Fund Reserve			(17.9)			(0.10)			-			-			-			-
Net Income Attributable to   Controlling Interests (GAAP)		$	394.7		$	2.22		$	387.9		$	2.19		$	330.0		$	1.91

Improved results in 2011 were due primarily to the impact of electric distribution rate case decisions that were effective July 1, 2010 for CL&P and PSNH and February 1, 2011 for WMECO, the impact of a higher level of investment in transmission infrastructure, colder than normal weather in the first quarter of 2011, continued cost management efforts, and the absence of a net charge of approximately $3 million, or approximately $0.02 per share, taken in the first quarter of 2010 associated with the enactment of the 2010 Healthcare

30

Act.  These benefits were partially offset by a decline in NU parent and other companies' results, a second quarter 2011 refund to transmission wholesale customers, as compared to a recovery from those customers in 2010, lower retail electric sales in 2011, compared to 2010, as well as higher Pension and PBOP costs, depreciation, property taxes and the storm fund reserve.

Regulated Companies:  Our Regulated companies consist of the electric distribution and transmission segments, with the Yankee Gas natural gas distribution segment and PSNH and WMECO generation activities included in the distribution segment.  A summary of our Regulated companies' earnings by segment for 2011, 2010 and 2009 is as follows:

		For the Years Ended December 31,
(Millions of Dollars)		2011			2010			2009
CL&P Transmission		$	151.9		$	143.9		$	136.8
PSNH Transmission			24.1			20.7			18.0
WMECO Transmission			22.8			13.0			9.5
NPT			0.8			0.2			-
Total Transmission			199.6			177.8			164.3
CL&P Distribution			110.6			94.1			74.0
PSNH Distribution			76.2			69.3			47.5
WMECO Distribution			20.2			10.1			16.7
Yankee Gas			31.7			32.7			21.0
Total Distribution			238.7			206.2			159.2
Subtotal - Regulated Companies’ Earnings  Before Non-Recurring Charge		$	438.3		$	384.0		$	323.5
Storm Fund Reserve (1)		$	(17.9)		$	-		$	-
Net Income - Regulated Companies		$	420.4		$	384.0		$	323.5

⁽¹⁾

Attributable to the CL&P distribution segment.

The increased 2011 transmission segment earnings as compared to 2010 were due primarily to a higher level of investment in transmission infrastructure, and a higher proportion of equity funding to support the transmission investments, partially offset by a 2011 refund to transmission wholesale customers, as compared to a recovery from those customers in 2010, primarily impacting CL&P.  The increased 2010 transmission segment earnings as compared to 2009 reflect a higher level of investment in transmission infrastructure.  Our transmission rate base totaled $2.96 billion at the end of 2011, compared with $2.76 billion at the end of 2010.

CL&P’s 2011 distribution segment earnings, excluding the $17.9 million storm fund reserve, were $16.5 million higher than 2010 due primarily to the impact of the 2010 distribution rate case decision that was effective July 1, 2010 and included an incremental rate increase effective July 1, 2011, lower uncollectibles expense and lower income taxes.  Partially offsetting these favorable items were higher Pension and PBOP costs, a 1.5 percent decrease in retail electric sales and higher depreciation and property taxes.  CL&P’s distribution segment regulatory ROE was 9.4 percent in 2011, as compared to 7.9 percent in 2010.

PSNH’s 2011 distribution segment earnings were $6.9 million higher than 2010 due primarily to higher revenues as a result of the permanent distribution rate increase effective July 1, 2010, and higher generation-related earnings, partially offset by the absence of the 2010 favorable impact of the distribution rate case settlement, which allowed for the recovery of certain actual expenses retroactive to August 1, 2009, higher property taxes and a 0.4 percent decrease in retail electric sales.  PSNH’s distribution segment regulatory ROE was 9.7 percent in 2011, as compared to 10.2 percent in 2010.

WMECO’s 2011 distribution segment earnings were $10.1 million higher than 2010 due primarily to the impact of the distribution rate case decision effective February 1, 2011 and lower operations and maintenance costs, partially offset by a $5.3 million pre-tax charge to establish a reserve related to a wholesale billing adjustment, and higher depreciation and amortization.  WMECO’s distribution segment regulatory ROE was 9 percent in 2011, as compared to 4.6 percent in 2010.

Yankee Gas’ 2011 earnings were $1 million lower than 2010 due primarily to higher pension and PBOP costs, the absence of a 2010 benefit related to the settlement of various tax matters, and higher depreciation and property taxes.  These unfavorable impacts were partially offset by higher revenues resulting from an 8 percent increase in total firm natural gas sales, and lower uncollectibles expense.  Yankee Gas’ regulatory ROE was 9.3 percent in 2011, as compared to 8.6 percent in 2010.

On August 28, 2011, Tropical Storm Irene caused extensive damage to our distribution system resulting in incremental restoration costs of $135.6 million.  Approximately 800,000 of our 1.9 million electric distribution customers were without power at the peak of the outages.

On October 29, 2011, an unprecedented storm inundated our service territory with heavy snow causing significant damage to our distribution and transmission systems resulting in incremental restoration costs of $218.5 million.  Approximately 1.2 million of our electric distribution customers were without power at the peak of the outages, with 810,000 of those customers in Connecticut, 237,000 in New Hampshire, and 140,000 in Massachusetts.  In terms of customer outages, this was the most severe storm in CL&P’s history, surpassing Tropical Storm Irene; the third most severe in PSNH’s history, following a December 2008 ice storm and a February 2010 winter storm; and the most severe in WMECO's history.

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Estimated incremental restoration costs related to the storms are summarized in the table below and consist of costs that are deferred for future recovery and costs that are capitalized:

		For the Year Ended December 31, 2011
(Millions of Dollars)		Deferred for Future Recovery			Capitalized			Total Incremental Costs
Tropical Storm Irene:
CL&P		$	105.6		$	18.2		$	123.8
PSNH			7.0			1.1			8.1
WMECO			3.2			0.5			3.7
Total Tropical Storm Irene			115.8			19.8			135.6
October Snowstorm:
CL&P			157.7			16.9			174.6
PSNH			14.7			2.2			16.9
WMECO			23.5			3.5			27.0
Total October Snowstorm			195.9			22.6			218.5
Total Storm Costs		$	311.7		$	42.4		$	354.1

The storms met the regulatory criteria for cost deferral in Connecticut, New Hampshire and Massachusetts and as a result, except for the CL&P storm fund reserve, the storm costs had no material impact on the results of operations of CL&P, PSNH or WMECO.  We believe our response to the storm damage was prudent and therefore we believe it is probable that CL&P, PSNH and WMECO will be allowed to recover these costs.  Each operating company will seek recovery of its costs through its applicable regulatory recovery process.  For further information regarding various reviews on storm response and preparedness, see “Regulatory Developments and Rate Matters - 2011 Major Storms,” in this Management's Discussion and Analysis.

CL&P recorded a pre-tax charge for a storm fund reserve of $30 million, in the fourth quarter of 2011, to provide bill credits to its residential customers who remained without power after noon on Saturday, November 5, 2011 as a result of the October snowstorm, and to provide contributions to certain Connecticut charitable organizations.  Approximately $27 million of the storm fund reserve was used to provide a one-time credit on the February 2012 bills of approximately 192,000 CL&P customers and approximately $3 million was paid to charitable organizations in December 2011.  CL&P will not seek to recover this non-recurring amount in its rates, which is approximately $17.9 million after-tax, or $0.10 per share.  

For the distribution segment of our Regulated companies, a summary of changes in CL&P, PSNH and WMECO retail electric GWh sales, as well as total sales and percentage changes, and Yankee Gas firm natural gas sales and percentage changes in million cubic feet for 2011, as compared to the same period in 2010, on an actual and weather normalized basis (using a 30-year average), is as follows:

		For the Year Ended December 31, 2011 Compared to 2010
		CL&P				PSNH				WMECO				Total Electric
Electric		Percentage Decrease		Weather Normalized Percentage Decrease		Percentage Increase/ (Decrease)		Weather Normalized Percentage Increase/ (Decrease)		Percentage Decrease		Weather Normalized Percentage Decrease		Sales (GWh)				Percentage Decrease		Weather Normalized Percentage Decrease
Residential		(1.0)%		- %		(1.1)%		(0.8)%		(0.6)%		-  %		14,766		14,913		(1.0)%		(0.2)%
Commercial		(2.0)%		(0.8)%		0.2%		1.1%		(1.5)%		(0.5)%		14,301		14,506		(1.4)%		(0.3)%
Industrial		(2.2)%		(1.2)%		(0.2)%		1.4%		(0.9)%		(0.1)%		4,418		4,481		(1.4)%		(0.2)%
Other		(0.8)%		(0.8)%		(4.3)%		(4.3)%		(0.6)%		(0.6)%		327		330		(1.0)%		(1.0)%
Total		(1.5)%		(0.5)%		(0.4)%		0.4%		(1.0)%		(0.2)%		33,812		34,230		(1.2)%		(0.3)%

		For the Year Ended December 31, 2011 Compared to 2010
Firm Natural Gas		Sales (million cubic feet) (1)				Percentage Increase		Weather Normalized Percentage Increase/ (Decrease)
Residential		13,508		13,403		0.8%		(3.2)%
Commercial		17,175		15,137		13.5%		9.8%
Industrial		16,197		14,866		8.9%		8.0%
Total		46,880		43,406		8.0%		5.1%
Total, Net of Special Contracts (2)		38,197		35,038		9.0%		5.4%

⁽¹⁾

The 2010 sales volumes for commercial customers have been adjusted to conform to current year presentation.  

⁽²⁾

Special contracts are unique to the customers who take service under such an arrangement and generally specify the amount of distribution revenue to be paid to Yankee Gas regardless of the customers’ usage.

Actual retail electric sales for all three electric companies were lower in 2011 compared to 2010 due primarily to milder weather in the summer of 2011, compared to warmer than normal weather in the summer of 2010.  In 2011, cooling degree days in Connecticut and western Massachusetts were 20.9 percent lower than 2010, and in New Hampshire, cooling degree days were 23.7 percent lower than

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2010.  For WMECO, the fluctuations in retail electric sales no longer impact earnings as the DPU approved a sales decoupling plan effective February 1, 2011.  Under this decoupling plan, WMECO now has an established level of baseline distribution delivery service revenues of $125.6 million that it is able to recover, which effectively breaks the relationship between kWhs consumed by customers and revenues recognized.

On a weather-normalized basis, total retail electric sales decreased slightly in 2011, as compared to 2010.  We believe the weather-normalized commercial sales for CL&P and WMECO decreased in 2011, compared to 2010, due to the slow economic recovery in these service areas.  PSNH commercial sales increased in 2011 due to one large self-generating customer who experienced multiple generation outages and relied on PSNH for energy.  Industrial sales for both CL&P and WMECO decreased in 2011, compared to 2010, due in part to weak manufacturing activity in Connecticut and western Massachusetts.  Our commercial and industrial electric sales continue to be negatively impacted by distributed generation and conservation programs.  

Our firm natural gas sales are subject to many of the same influences as our retail electric sales, but have benefitted from migration of interruptible customers switching to firm service rates and the addition of gas-fired distributed generation in Yankee Gas' service territory.  Actual firm natural gas sales in 2011 were 8 percent higher than 2010.  Colder weather, especially in the first quarter of 2011, was a contributing factor to the higher sales.  Heating degree days for 2011 in Connecticut were 6.4 percent higher than 2010.  On a weather normalized basis, actual firm natural gas sales in 2011 were 5.1 percent higher than 2010.

Our expense related to uncollectible receivable balances (our uncollectibles expense) is influenced by the economic conditions of our region.  Fluctuations in our uncollectibles expense are mitigated from an earnings perspective because a portion of the total uncollectibles expense for each of the electric distribution companies is recovered through each 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 (hardship customers) are fully recovered through their respective tariffs.  For 2011, our total pre-tax uncollectibles expense that impacts earnings was $11.7 million, as compared to $23.4 million in 2010.  The improvement in 2011 uncollectibles expense was due in part to continued enhanced accounts receivable collection efforts and credit monitoring.

NU Parent and Other Companies:  NU parent and other companies (which includes our competitive businesses held by NU Enterprises) recorded net expenses of $25.7 million, or $0.14 per share, in 2011, compared with earnings of $3.9 million, or $0.03 per share, in 2010.  In 2011, excluding merger-related costs of $11.3 million, or $0.06 per share, NU parent and other companies recorded net expenses of $14.4 million, or $0.08 per share.  In 2010, results included a non-recurring benefit of $15.7 million, or $0.09 per share, associated with the settlement of tax issues and a charge of $9.4 million, or $0.06 per share, associated with merger-related costs.

Future Outlook

We are not providing stand-alone EPS guidance in 2012 due to our pending merger with NSTAR.  However, we expect that a number of key factors will negatively impact earnings in 2012 as compared with 2011.  They include higher untracked Pension expense, which is expected to increase after-tax expense by approximately $15 million, higher reliability-related spending by CL&P, and a higher effective tax rate for CL&P's transmission and distribution segments.  We expect those factors to be partially offset by an expected increase in transmission rate base of more than $200 million by the end of 2012, lower NU parent interest costs, and the positive impact of distribution rate increases that were effective July 1, 2011 for CL&P and are expected to be effective on July 1, 2012 for Yankee Gas and PSNH.

Liquidity

Consolidated:  Cash and cash equivalents totaled $6.6 million as of December 31, 2011, compared with $23.4 million as of December 31, 2010.  

In 2011, our subsidiaries issued a total of $260 million in new long-term debt, excluding the refinancing of CL&P’s and PSNH’s PCRBs described below.  On September 13, 2011, PSNH issued $160 million of first mortgage bonds that will mature on September 1, 2021 carrying a coupon rate of 3.20 percent.  The net proceeds were used to repay short-term borrowings previously incurred in the ordinary course of business and for general working capital purposes.  On September 16, 2011, WMECO issued $100 million of unsecured senior notes that will mature on September 15, 2021 carrying a coupon rate of 3.50 percent.  The net proceeds were used to repay short-term borrowings previously incurred due largely in part to construction costs.

On April 1, 2011, CL&P remarketed $62 million of tax-exempt secured PCRBs that were subject to mandatory tender.  The PCRBs, which mature on May 1, 2031, carry a coupon rate of 1.25 percent and have a mandatory tender on April 1, 2012, at which time CL&P expects to remarket the bonds.

On May 26, 2011, PSNH issued $122 million of first mortgage bonds with a coupon rate of 4.05 percent and a maturity date of June 1, 2021, and used the proceeds to redeem $119.8 million of tax-exempt 1992 Series D and 1993 Series E PCRBs, each with a maturity date of May 1, 2021 and a coupon rate of 6 percent.  The refinancing is expected to reduce PSNH’s interest costs by approximately $2.2 million in 2012.

On October 24, 2011, CL&P issued $120.5 million of PCRBs carrying a coupon of 4.375 percent that will mature on September 1, 2028, and $125 million of PCRBs carrying a coupon of 1.25 percent that mature on September 1, 2028 and are subject to mandatory tender on September 3, 2013.  The proceeds of these issuances were used to refund $245.5 million of PCRBs that carried a coupon of 5.85

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percent and had a maturity date of September 1, 2028.  The refinancing is expected to reduce CL&P’s interest costs by approximately $7.5 million in 2012.

In 2012, in addition to remarketing the CL&P $62 million PCRBs, NU parent has a debt maturity on April 1, 2012 of $263 million, which we expect will be refinanced, and Yankee Gas has an annual sinking fund requirement of $4.3 million.  Also in 2012, we expect to issue $150 million of long-term debt comprised of $100 million by WMECO and $50 million by Yankee Gas in the second half of 2012.

On November 30, 2011, the FERC granted authorization to allow CL&P to incur total short-term borrowings up to a maximum of $450 million effective January 1, 2012 through December 31, 2013.  In anticipation of increasing its short-term debt availability, on February 15, 2012, CL&P filed an application with the FERC requesting authorization to increase CL&P’s total short-term borrowing capacity from a maximum of $450 million to a maximum of $600 million.  

Cash flows provided by operating activities in 2011 totaled $901.1 million, compared with operating cash flows of $832.6 million in 2010 and $745 million in 2009 (all amounts are net of RRB payments, which are included in financing activities on the accompanying consolidated statements of cash flows).  The improved cash flows were due primarily to the impact of the CL&P and PSNH 2010 distribution rate case decisions that were effective July 1, 2010 (the CL&P July 1, 2010 rate increase was deferred from customer bills until January 1, 2011), the WMECO distribution rate case decision that was effective February 1, 2011, and income tax refunds of $76.6 million in 2011 largely attributable to accelerated depreciation tax benefits, compared to income tax payments of $84.5 million in 2010.  Offsetting these benefits was a contribution of $143.6 million made into our Pension Plan in 2011, compared to $45 million in 2010, and approximately $157 million of cash disbursements made in 2011 associated with Tropical Storm Irene and the October snowstorm.  The increase in operating cash flows from 2009 to 2010 was due primarily to the absence in 2010 of costs incurred at PSNH and WMECO related to the major ice storm in December 2008 that were paid in the first quarter of 2009, a decrease in Fuel, Materials and Supplies attributable to a $31.8 million reduction in coal inventory levels at the PSNH generation business as ordered by the NHPUC, and increases in amortization on regulatory deferrals primarily attributable to 2009 activity within PSNH’s ES and CL&P’s CTA tracking mechanisms where such costs exceeded revenues resulting in an unfavorable cash flow impact in 2009.  Offsetting these favorable cash flow impacts was a $45 million contribution made into our Pension Plan in September 2010.  

On a stand-alone basis, 2012 cash flows provided by operating activities, net of RRB payments, are expected to be lower than in 2011 due primarily to approximately $50 million more in Pension Plan contributions than in 2011 and approximately $27 million in bill credits provided to CL&P residential customers in February 2012.  In 2012, cash payments for Tropical Storm Irene and the October storm costs are estimated to be approximately $160 million, as compared to 2011 payments of approximately $157 million.  

A summary of the current credit ratings and outlooks by Moody's, S&P and Fitch for senior unsecured debt of NU parent and WMECO and senior secured debt of CL&P and PSNH is as follows:

Moody's

S&P

Fitch

Current

Outlook

Current

Outlook

Current

Outlook

NU Parent

Baa2

Stable

BBB

Watch-Positive

BBB

Watch-Positive

CL&P

A2

Stable

A-

Watch-Positive

A-

Positive

PSNH

A3

Stable

A-

Watch-Positive

A-

Stable

WMECO

Baa2

Stable

BBB+

Watch-Positive

BBB+

Stable

On April 18, 2011, Fitch raised PSNH's senior secured rating to “A-” from “BBB+” to better reflect the firm's notching policy for senior secured debt.  On the same day, Fitch raised its outlook on CL&P to “positive” from “stable” in part to reflect improved cash flow metrics.  On May 16, 2011, S&P raised all of its corporate credit ratings and debt ratings on NU and its regulated utilities by one notch due primarily to improved financial metrics at the companies.  S&P maintained its Watch-Positive outlook pending consummation of NU’s merger with NSTAR.  On July 14, 2011, Fitch affirmed its existing ratings and outlooks of NU parent, CL&P, PSNH and WMECO.  There were no changes to Moody’s ratings or outlooks for NU or its subsidiaries in 2011.

We paid common dividends of $194.6 million in 2011, compared with $180.5 million in 2010 and $162.4 million in 2009.  This reflects an increase of approximately 7.3 percent in our common dividend beginning in the first quarter of 2011.  On February 14, 2012, our Board of Trustees declared a quarterly common dividend of $0.29375 per share, payable on March 30, 2012 to shareholders of record as of March 1, 2012, which equates to $1.175 per share on an annualized basis.  The dividend represented an increase of 6.8 percent over the $0.275 per share quarterly dividend paid in 2011.  Assuming our pending merger with NSTAR closes in 2012 after NSTAR pays its March 30, 2012 dividend of $0.45 per share, the terms of the merger agreement would require NU's first quarterly dividend paid after the merger to be at least $0.343 per share, or at least $1.372 per share on an annualized basis.  

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 state statute, the leverage restrictions in our revolving credit agreement and the ability of our subsidiaries to pay common dividends to NU parent.  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; PSNH is required to reserve an additional amount of retained earnings under its FERC hydroelectric license conditions.  In addition, 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.  The merger agreement requires that our first quarterly dividend per common share paid after the closing of the merger be increased to an amount that is at least equal, after adjusting for the exchange ratio, to NSTAR's last quarterly dividend paid prior to the closing.  We do not expect the restrictions will prevent NU from meeting its obligations under the merger agreement.

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In 2011, CL&P, PSNH, WMECO, and Yankee Gas paid $243.2 million, $58.8 million, $26.3 million, and $38.2 million, respectively, in common dividends to NU parent.  In 2011, NU parent made equity contributions to CL&P, PSNH, WMECO, and Yankee Gas of $6.7 million, $120 million, $91.8 million, and $8.5 million, respectively.

Cash capital expenditures included on the accompanying consolidated statements of cash flows and described in this “Liquidity” section do not include amounts incurred on capital projects but not yet paid, cost of removal, AFUDC related to equity funds, and the capitalized portions of pension and PBOP expense or income.  A summary of our cash capital expenditures by company for the years ended December 31, 2011, 2010, and 2009 is as follows:

		For the Years Ended December 31,
(Millions of Dollars)		2011			2010			2009
CL&P		$	424.9		$	380.3		$	435.7
PSNH			241.8			296.3			266.4
WMECO			238.0			115.2			105.4
Yankee Gas			98.2			82.5			54.8
NPT			24.9			7.5			-
Other			48.9			72.7			45.8
Total		$	1,076.7		$	954.5		$	908.1

The increase in our cash capital expenditures was the result of higher transmission segment cash capital expenditures of $150.6 million, primarily at WMECO and NPT, as well as higher capital expenditures at Yankee Gas related to the WWL Project.  

Proceeds from Sale of Assets in 2011 of $46.8 million included on the accompanying consolidated statement of cash flows related to the sale of certain CL&P transmission assets.  For further information, see “Business Development and Capital Expenditures - Transmission Segment - Other” in this Management's Discussion and Analysis.

As of December 31, 2011, NU parent had $17.9 million of LOCs issued for the benefit of certain subsidiaries (including $4 million for CL&P and $5.4 million for PSNH) and $256 million of short-term borrowings outstanding under its $500 million unsecured revolving credit facility.  The weighted-average interest rate on these short-term borrowings as of December 31, 2011 was 2.2 percent, based on a variable rate plus an applicable margin based on NU parent's credit ratings.  NU parent had $226.1 million of borrowing availability on this facility as of December 31, 2011.

CL&P, PSNH, WMECO, and Yankee Gas are parties to a joint unsecured revolving credit facility in a nominal aggregate amount of $400 million.  As of December 31, 2011, CL&P and Yankee Gas had short-term borrowings outstanding under this facility of $31 million and $30 million, respectively, leaving $339 million of aggregate borrowing capacity available.  The weighted-average interest rate on these short-term borrowings as of December 31, 2011 was 3.1 percent (4.03 percent for CL&P), which is based on a variable rate plus an applicable margin based on CL&P and Yankee Gas’ respective credit ratings.

We will continue to monitor availability of our credit facilities to assure that we have an adequate borrowing capacity.

Our credit facilities and 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 a consolidated debt to total capitalization ratio.  As of December 31, 2011, all such companies were in compliance with these covenants.  Refer to Note 8, “Short-Term Debt,” and Note 9, “Long-Term Debt,” to our consolidated financial statements included in this Annual Report on Form 10-K for further discussion of material terms and conditions of these agreements.

Business Development and Capital Expenditures

Consolidated:  Our consolidated capital expenditures, including amounts incurred but not paid, cost of removal, AFUDC, and the capitalized portions of pension and PBOP expense or income (all of which are non-cash factors), totaled $1.2 billion in 2011, $1 billion in 2010, and $969.2 million in 2009.  These amounts included $51.9 million in 2011, $68.7 million in 2010, and $52.7 million in 2009 related to our corporate service companies, NUSCO and RRR.

Regulated Companies:  Capital expenditures for the Regulated companies totaled $1.2 billion ($467.2 million for CL&P, $291.7 million for PSNH, and $290.3 million for WMECO) in 2011.

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Transmission Segment:  Transmission segment capital expenditures increased by $198.5 million in 2011, as compared with 2010, due primarily to increases at WMECO related to the construction of GSRP.  A summary of transmission segment capital expenditures by company in 2011, 2010 and 2009 is as follows:  

		For the Years Ended December 31,
(Millions of Dollars)		2011			2010			2009
CL&P		$	128.6		$	107.2		$	163.0
PSNH			68.1			49.1			59.4
WMECO			236.8			95.2			67.7
NPT			25.9			9.4			1.7
Totals		$	459.4		$	260.9		$	291.8

NEEWS:  GSRP, a project that involves the construction of 115 KV and 345 KV overhead lines from Ludlow, Massachusetts to Bloomfield, Connecticut, is the first, largest and most complicated project within the NEEWS family of projects.  On September 13, 2011, CL&P and WMECO received the required permit from U.S. Army Corps of Engineers allowing them to commence full construction on GSRP.  The $718 million project is expected to be placed in service in late 2013.  As of December 31, 2011, the project was approximately 50 percent complete.  

The Interstate Reliability Project, which includes CL&P’s construction of an approximately 40-mile, 345 KV overhead line from Lebanon, Connecticut to the Connecticut-Rhode Island border in Thompson, Connecticut where it will connect to transmission enhancements being constructed by National Grid, is our second major NEEWS project.  In August 2010, ISO-NE reaffirmed the need for the Interstate Reliability Project, which we expect to place in service in late 2015 at a cost of $218 million.  On December 23, 2011, CL&P filed a siting application with the Connecticut Siting Council to build the Connecticut section of the Interstate Reliability Project.  In early 2012, National Grid is expected to file siting applications with regulators in Massachusetts and Rhode Island to build its sections of the project.  The late 2015 expected in-service date assumes that all siting application approvals will be received from all three states in late 2013 with construction commencing in late 2013 or early 2014.  

The Central Connecticut Reliability Project, which involves construction of a $301 million new 345 KV overhead line from Bloomfield, Connecticut to Watertown, Connecticut, is the third major part of NEEWS.  In March 2011, ISO-NE announced that it would review the Central Connecticut Reliability Project along with other central Connecticut projects as part of a study known as the Greater Hartford Central Connecticut Study.  We expect ISO-NE to issue preliminary need results and transmission solutions in 2013.

Included as part of NEEWS are costs for associated reliability related projects, all of which have received siting approval and most of which are under construction.  These projects began going into service in 2010 and will continue to go into service through 2013.  

Through December 31, 2011, CL&P and WMECO had capitalized $132.6 million and $334.7 million, respectively, in costs associated with NEEWS, of which $33.9 million and $197.8 million, respectively, were capitalized in 2011.  The total expected cost of NU’s share of NEEWS is approximately $1.3 billion, of which $646 million and $616 million relate to CL&P and WMECO, respectively.  

On May 27, 2011, the FERC issued an order accepting CL&P’s and WMECO’s filing requesting changes to the ISO-NE Tariff in order to include 100 percent of the NEEWS CWIP in regional rate base effective June 1, 2011.  As a result of this order, CL&P and WMECO ceased accruing AFUDC on NEEWS CWIP as of June 1, 2011, and NU’s local customers will receive appropriate credits for the return on CWIP they have paid.

Northern Pass:  On October 4, 2010, NPT and Hydro Renewable Energy, a subsidiary of HQ, entered into a TSA in connection with the Northern Pass transmission project, which will be constructed by NPT.  Northern Pass is a planned HVDC transmission line from the Québec-New Hampshire border to Franklin, New Hampshire and an associated alternating current radial transmission line between Franklin and Deerfield, New Hampshire.  Northern Pass will interconnect at the Québec-New Hampshire border with a planned HQ HVDC transmission line.  

Under the terms of the TSA, which was accepted by the FERC without modification in February 2011, NPT will sell to HQ affiliate Hydro Renewable Energy 1,200 MW of firm electric transmission rights over the Northern Pass for a 40-year term and charge cost-based rates.  The projected cost-of-service calculation includes an ROE of 12.56 percent through the construction phase of the project, and during commercial operation, an ROE equal to the ISO-NE regional rates base ROE (currently 11.14 percent) plus 1.42 percent.  The TSA rates will be based on a capital structure for NPT of 50 percent debt and 50 percent equity.  During the development and the construction phases under the TSA, NPT will be recording non-cash AFUDC earnings.

In October 2010, NPT filed the Northern Pass project design with ISO-NE for technical approval and filed a presidential permit application with the DOE, which seeks permission to construct and maintain facilities that cross the U.S.-Canada border in New Hampshire and connect to HQ TransÉnergie's facilities in Québec.  The DOE held seven meetings in New Hampshire in mid-March 2011 seeking public comment.  In response to concerns raised at these meetings, NPT revised its application to request additional time during the public comment period to allow NPT to review alternative routes.  On June 15, 2011, the DOE extended the scoping comment period for at least forty-five days after NPT files an alternative route with the DOE.  Certain environmental studies will need to be completed in order to obtain DOE permits.  We expect construction to begin in 2014 and the project to be completed in the fourth quarter of 2016.

On February 8, 2012, the New Hampshire legislature passed a bill that could potentially prohibit the use of eminent domain for the development of any “non-reliability” electric transmission projects, such as Northern Pass.  The bill is currently awaiting action by the

36

New Hampshire Governor.  We are reviewing the potential impact of the bill on NPT, should it be enacted, including its effect on the project's route, cost and schedule.  We believe that NPT will be able to acquire the necessary rights along an acceptable route, which would make it feasible to construct the project even if the bill is enacted.  Given the ultimate design needs of the project, along with siting and permit requirements, which will vary depending upon the route ultimately selected, there is a possibility for further delay in commencement of construction.

We currently estimate that NU's 75 percent share of the costs of the Northern Pass transmission project will be approximately $830 million and NSTAR’s 25 percent share of the costs of the Northern Pass transmission project will be approximately $280 million, for a combined total expected cost of approximately $1.1 billion (including capitalized AFUDC).  Through December 31, 2011, we capitalized $37 million in costs associated with NPT.

Other:  On May 31, 2011, CL&P and the Connecticut Transmission Municipal Electric Energy Cooperative (CTMEEC), a non-profit municipal joint action transmission entity formed by several Connecticut municipal electric utilities, completed the sale by CL&P to CTMEEC of a segment of high voltage transmission lines built by CL&P in the town of Wallingford, Connecticut.  The assets were sold at their net book value of $42.5 million, plus reimbursement of closing costs.  CL&P is operating and maintaining the lines under an operations and maintenance agreement with CTMEEC.  The transaction did not include the transfer of land or equipment not related to electric transmission service.  The transaction did not impact our five-year capital plan and is already reflected in CL&P’s transmission rate base forecasts.  

Distribution Segment:  A summary of distribution segment capital expenditures by company for 2011, 2010 and 2009 is as follows:

		For the Years Ended December 31,
(Millions of Dollars)			2011			2010			2009
CL&P:
Basic Business		$	166.6		$	126.2		$	104.6
Aging Infrastructure			112.3			104.0			104.1
Load Growth			59.6			75.2			74.3
Total CL&P			338.5			305.4			283.0
PSNH:
Basic Business			47.7			41.2			55.5
Aging Infrastructure			25.3			19.5			17.8
Load Growth			25.8			23.1			25.5
Total PSNH			98.8			83.8			98.8
WMECO:
Basic Business			24.2			17.5			21.5
Aging Infrastructure			11.5			10.5			12.2
Load Growth			6.1			5.1			4.0
Total WMECO			41.8			33.1			37.7
Total - Electric Distribution (excluding Generation)			479.1			422.3			419.5
Yankee Gas			102.8			94.6			59.6
Other			1.0			2.0			0.6
Total Distribution			582.9			518.9			479.7
PSNH Generation:
Clean Air Project			101.1			149.7			119.3
Other			23.7			27.4			25.7
Total PSNH Generation			124.8			177.1			145.0
WMECO Generation			11.7			10.1			-
Total Distribution Segment		$	719.4		$	706.1		$	624.7

For the electric distribution business, basic business includes the relocation of plant, the purchase of meters, tools, vehicles, and information technology.  Aging infrastructure relates to the planned replacement of overhead lines, plant substations, transformer replacements, and underground cable replacement.  Load growth includes requests for new business and capacity additions on distribution lines and substation overloads.  

The Clean Air Project is a wet scrubber project that PSNH constructed and placed in service at its Merrimack Station in September 2011, the cost of which will be recovered through PSNH's ES rates under New Hampshire law.  By November 2011, both of Merrimack Station’s coal-fired units were integrated with the scrubber, which is reducing emissions from the units.  We expect finalization of project activities, including water discharge enhancements, in mid-2012 at a cost of approximately $422 million.  

On August 12, 2009, the DPU authorized WMECO to install up to 6 MW of solar energy generation in its service territory at an estimated cost of $41 million by the end of 2012.  In October 2010, WMECO completed development of a 1.8 MW solar generation facility on a site in Pittsfield, Massachusetts.  The full cost of this project was $9.4 million.  In December 2011, WMECO completed development of a 2.3 MW solar generation facility on a 12-acre brownfield site in Springfield, Massachusetts.  The full cost of the Springfield project was $11.4 million.  WMECO is continuing its evaluation of sites suitable for development of the remaining 1.9 MW of the authorized 6 MW of capacity.

Yankee Gas' WWL Project, a 16-mile natural gas pipeline between Waterbury and Wallingford, Connecticut and the increase of vaporization output of its LNG plant, was placed in service in November 2011.  Project costs totaled approximately $54 million, $3.6

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million below the previous estimate of $57.6 million.  Pursuant to the June 29, 2011 rate case decision, the WWL Project was included in Yankee Gas’ rate base upon entering service.  

Projected Capital Expenditures and Rate Base Estimates:  Excluding the impacts of the pending merger with NSTAR, a summary of the projected capital expenditures for the Regulated companies' electric transmission segment and their distribution segment (including generation) by company for 2012 through 2016, including our corporate service companies' capital expenditures on behalf of the Regulated companies, is as follows:

	Year
(Millions of Dollars)	2012			2013			2014			2015			2016			2012-2016 Total
CL&P Transmission	$	174		$	108		$	255		$	245		$	55		$	837
PSNH Transmission		66			125			142			94			41			468
WMECO Transmission		193			132			111			73			1			510
NPT		40			22			178			238			334			812
Subtotal Transmission	$	473		$	387		$	686		$	650		$	431		$	2,627
CL&P Distribution:
Basic Business	$	129		$	121		$	113		$	114		$	112		$	589
Aging Infrastructure		119			101			88			90			92			490
Load Growth		67			63			73			67			72			342
Total CL&P Distribution		315			285			274			271			276			1,421
PSNH Distribution:
Basic Business		52			49			49			50			48			248
Aging Infrastructure		29			24			28			26			25			132
Load Growth		31			37			33			40			39			180
Total PSNH Distribution		112			110			110			116			112			560
WMECO Distribution:
Basic Business		17			16			18			18			19			88
Aging Infrastructure		15			16			16			16			16			79
Load Growth		7			7			6			6			6			32
Total WMECO Distribution		39			39			40			40			41			199
Subtotal Electric Distribution	$	466		$	434		$	424		$	427		$	429		$	2,180
PSNH Generation:
Clean Air Project	$	21		$	2		$	-		$	-		$	-		$	23
Other		13			26			29			34			34			136
Total PSNH Generation		34			28			29			34			34			159
CL&P Generation		11			23			11			-			-			45
WMECO Generation		19			10			10			10			-			49
Subtotal Generation	$	64		$	61		$	50		$	44		$	34		$	253
Yankee Gas Distribution:
Basic Business	$	26		$	27		$	28		$	29		$	30		$	140
Aging Infrastructure		48			50			50			52			53			253
Load Growth		20			46			47			35			23			171
Total Yankee Gas Distribution	$	94		$	123		$	125		$	116		$	106		$	564
Corporate Service Companies	$	44		$	52		$	36		$	30		$	29		$	191
Total	$	1,141		$	1,057		$	1,321		$	1,267		$	1,029		$	5,815

Actual capital expenditures could vary from the projected amounts for the companies and periods above.  Economic conditions in the northeast could impact the timing of our major capital expenditures.  Most of these capital expenditure projections, including those for NPT, assume timely regulatory approval, which in most cases requires extensive review.  The amounts above assume that we receive favorable responses from regulators to our proposed capital program and that our major transmission initiatives, some of which have not yet been filed with regulators, are approved in a timely manner.  Delays in or denials of those approvals could reduce the levels of expenditures and associated rate base.  

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Based on the 2011 actual and 2012 through 2016 projected capital expenditures, the 2011 actual and 2012 through 2016 projected transmission, distribution and generation rate base as of December 31 of each year are as follows:

	Year
	2011			2012			2013			2014			2015			2016
(Millions of Dollars)
CL&P Transmission	$	2,100		$	2,149		$	2,091		$	2,211		$	2,424		$	2,450
PSNH Transmission		390			407			524			654			707			721
WMECO Transmission		467			615			722			747			853			814
NPT		-			-			-			-			-			804
Total Transmission		2,957			3,171			3,337			3,612			3,984			4,789
CL&P Distribution		2,603			2,726			2,826			2,932			3,019			3,114
PSNH Distribution		836			888			959			1,008			1,065			1,108
WMECO Distribution		423			434			442			446			451			455
Total Electric Distribution		3,862			4,048			4,227			4,386			4,535			4,677
CL&P Generation		-			9			29			35			31			28
PSNH Generation		759			726			683			673			663			652
WMECO Generation		18			31			37			43			48			43
Total Generation		777			766			749			751			742			723
Yankee Gas Distribution		754			771			812			866			987			1,042
Total	$	8,350		$	8,756		$	9,125		$	9,615		$	10,248		$	11,231

Transmission Rate Matters and FERC Regulatory Issues

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 these parties 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, serves as the regional transmission organization for New England.  ISO-NE works to ensure the reliability of the New England transmission 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 the portion of the costs of our major transmission facilities that are regionalized throughout New England.

Transmission - Wholesale Rates:  Our transmission rates recover our total transmission revenue requirements, ensuring that we recover all regional and local revenue requirements for providing transmission service.  These rates provide for annual reconciliations to actual costs.  The difference between billed and actual costs is deferred for future recovery from, or refund to, customers.  As of December 31, 2011, we were in a total net overrecovery position of $31.4 million, which will be refunded to customers in June 2012.  Of this amount, the transmission segments of CL&P, PSNH and WMECO were in an overrecovery position of $18.6 million, $1.7 million and $11.1 million, respectively.

Pursuant to a series of orders involving the ROE for regionally planned New England transmission projects, the FERC set the base ROE at 11.14 percent and approved incentives that increased the ROE to 12.64 percent for those projects that were in-service by the end of 2008.  Beginning in 2009, the ROE for all regional transmission investment approved by ISO-NE is 11.64 percent, which includes the 50 basis points for joining the regional transmission organization.  In addition, certain projects were granted additional ROE incentives by FERC under its transmission incentive policy.  As a result, CL&P earns between 12.64 percent and 13.1 percent on its major transmission projects.  On June 28, 2011, FERC denied a motion by several New England states to reconsider the financial incentives FERC had granted the vast majority of NEEWS investments in 2008.  Those incentives include an incremental 125-basis points to FERC’s base New England transmission ROE, cash recovery of earnings and interest on NEEWS investments while the projects are under construction, and recovery of prudently incurred costs on projects that are abandoned.  

FERC Base ROE Complaint: On September 30, 2011, several New England state attorneys general, state regulatory commissions, consumer advocates and other parties filed a joint complaint with the FERC under Sections 206 and 306 of the Federal Power Act alleging that the base ROE used in calculating formula rates for transmission service under the ISO-NE Open Access Transmission Tariff by New England transmission owners, including CL&P, PSNH and WMECO, is unjust and unreasonable.  The complainants asserted that the current 11.14 percent rate, which became effective in 2006, is excessive due to changes in the capital markets and are seeking an order to reduce the rate to 9.2 percent, effective September 30, 2011.  

On October 20, 2011, the New England transmission owners responded to the complaint, asking FERC to dismiss the complaint on the basis that the complainants failed to carry their burden of proof under Section 206 of the Federal Power Act to demonstrate that the existing base ROE is unjust and unreasonable.  The New England transmission owners included testimony and analysis reflecting a base ROE of 11.2 percent using FERC’s methodology and precedents, which they believe demonstrates that the current base ROE of 11.14 percent remains just and reasonable.

As of December 31, 2011, CL&P, PSNH, and WMECO had approximately $1.5 billion of aggregate shareholder equity invested in their transmission facilities.  As a result, each 10 basis point change in the authorized base ROE would change annual consolidated earnings by an approximate $1.5 million.

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Although additional testimony was submitted by the complainants and the New England transmission owners in November and December 2011, the FERC has not yet issued an order in this proceeding and we cannot predict when this proceeding will be concluded, the outcome of this proceeding, or its impact on our financial position, results of operations or cash flows.

Legislative Matters

2010 and 2011 Connecticut Legislation:  In May 2010, the Connecticut Legislature approved a state budget for the 2011 fiscal year, which called for the assessment of an Economic Transition Charge to electric utility customers and the issuance by the state of Connecticut of up to $760 million of economic recovery revenue bonds that would be repaid over eight years through additional charges on electric utility customer bills.  On September 29, 2010, the PURA approved a financing order for the bonds, but due primarily to legal challenges the bonds were never issued.  On June 21, 2011, Governor Malloy signed legislation approving the state budget for the 2012 fiscal year that revoked the authorization for the state to issue the economic recovery revenue bonds.  As a result of this change in legislation, as of July 1, 2011 CL&P customer bills do not include the charge associated with the economic recovery revenue bonds of approximately $0.0038 per kWh.

On July 1, 2011, Governor Malloy signed legislation that consolidated oversight of state energy and environmental activities into the DEEP.  Effective July 1, 2011, the DPUC was replaced by PURA, which is part of the DEEP.  The five commissioners of the DPUC were replaced by three directors of PURA.  PURA regulates Connecticut utility rates and terms of service and oversees certain safety standards of the state’s utilities, but various policy responsibilities, including the state’s Integrated Resource Plan, have been assumed by a separate division within DEEP.  The legislation also authorized the state’s electric distribution companies, including CL&P, to build up to 10 MW of renewable generation, and authorized DEEP to study the potential for increased natural gas usage in Connecticut, including usage as a transportation fuel.

2011 New Hampshire Legislation:  On March 30, 2011, the New Hampshire House of Representatives approved House Bill 648, which would preclude companies constructing non-reliability projects, such as Northern Pass, from using eminent domain to acquire property for construction of such projects.  On June 2, 2011, the New Hampshire Senate voted to send House Bill 648 back to the Senate Judiciary Committee for further study.  On December 8, 2011, the Senate Judiciary Committee endorsed a number of changes to the state’s eminent domain legislation, but those changes did not include a ban on using eminent domain for non-reliability projects.  On February 8, 2012, the New Hampshire legislature passed a bill that could potentially prohibit the use of eminent domain for development of any “non-reliability” electric transmission projects, such as Northern Pass.  The bill is currently awaiting action by the New Hampshire Governor.  For further information regarding the impacts to NPT, see “Business Development and Capital Expenditures - Transmission Segment – Northern Pass” in this Management's Discussion and Analysis.

Regulatory Developments and Rate Matters

Regulatory Approvals for Pending Merger with NSTAR:

Federal:  On February 10, 2012, the applicable Hart-Scott-Rodino waiting period expired.  On December 21, 2011, the Federal Communications Commission extended its approval until July 7, 2012.  On July 6, 2011, FERC issued its approval of the merger.  On December 20, 2011, the Nuclear Regulatory Commission issued two orders approving the indirect transfer of control of the operating licenses for Yankee Nuclear Power Station and Haddam Neck Plant held by YAEC and CYAPC, which will be effected upon the merger of NU and NSTAR.

Massachusetts:  On November 24, 2010, NU and NSTAR filed a joint petition requesting the DPU’s approval of our pending merger.  On March 10, 2011, the DPU issued an order that modified the standard of review to be applied in the review of mergers involving Massachusetts utilities from a “no net harm” standard to a “net benefits” standard, meaning that the companies must demonstrate that the pending transaction provides benefits that outweigh the costs.  NU and NSTAR filed supplemental testimony and a net benefit analysis with the DPU on April 8, 2011, estimating post-transaction net savings of approximately $780 million in the first 10 years following the closing of the merger and other customer benefits.  An effective date for the merger of October 1, 2011 was used in the development of the net benefit study that was filed with the DPU.  Evidentiary hearings began July 6, 2011 and concluded on July 28, 2011.  Briefs in the case were filed with the DPU in September and October 2011.  

On July 15, 2011, the DOER filed a motion to stay the proceedings.  On July 21, 2011, NU and NSTAR filed a response objecting to this motion.  The DPU originally scheduled oral arguments for November 4, 2011 regarding the motion, which were further postponed during the fourth quarter of 2011 while NU, NSTAR and other parties made attempts to narrow and discuss the issues presented by the motion to stay.  On January 6, 2012, oral arguments on the motion to stay were conducted.  On February 15, 2012, NU and NSTAR reached comprehensive merger-related settlement agreements with both the Massachusetts Attorney General and the DOER.  The first settlement agreement was reached with both the Attorney General and the DOER and covers a variety of rate-making and rate design issues, including a distribution rate freeze until 2016 for WMECO, NSTAR Electric Company and NSTAR Gas Company.  The second settlement agreement was reached with the DOER and covers a variety of matters impacting the advancement of Massachusetts clean energy goals established by the Green Communities Act and Global Warming Solutions Act.  Pursuant to the terms and provisions of the settlement agreements, all parties agree that the proposed merger between NU and NSTAR is consistent with the public interest and should be approved by the DPU.  However, the settlement agreements allow the Attorney General and DOER to terminate their respective agreements for any reason at any time prior to approval by the DPU.  All parties to the settlement agreements have requested that the DPU approve the merger on April 4, 2012.

Connecticut:  In December 2010, the Connecticut Office of Consumer Counsel, supported by the Connecticut Attorney General, petitioned the DPUC (now PURA) to reconsider its earlier view from November 2010 that it lacked jurisdiction.  On June 1, 2011, the

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PURA issued a decision stating that it lacked jurisdiction over the merger.  On June 30, 2011, the Office of Consumer Counsel filed an appeal of the PURA's final decision.  NRG Energy, Inc. (NRG) and the New England Power Generators Association (NEPGA) filed similar appeals in July 2011 and filed petitions with the Connecticut Superior Court in July 2011, each requesting a declaratory ruling that the PURA has jurisdiction over the merger.  On January 18, 2012, the PURA issued a final decision in which it revised its earlier declaratory ruling of June 1, 2011 that concluded it did not have jurisdiction to review the pending merger between NU and NSTAR. The final decision ruled that NU and NSTAR must now seek approval from PURA pursuant to Connecticut state law prior to completing the merger.  As a result, on January 19, 2012, NU and NSTAR filed with PURA an application for approval of the merger.  PURA is scheduled to issue a final decision on April 2, 2012.  

If both the DPU and PURA issue acceptable decisions by such dates, we expect the merger will be consummated by April 16, 2012.

New Hampshire:  On April 5, 2011, the NHPUC issued an order concluding that it does not have jurisdiction over the merger.

Maine:  On May 10, 2011, the Maine Public Utilities Commission approved the merger, subject to FERC approval, which was received on July 6, 2011.

Federal:

EPA Air Toxic Standard: On December 16, 2011, the EPA issued the Mercury and Air Toxic Standards, a rule that establishes emission limits for hazardous air pollutants, including mercury and arsenic, from new and existing coal- and oil-fired electric generating units.  The standards are the first to implement a nationwide emissions standard for hazardous air pollutants across all electric generating units, providing utility companies up to five years to meet the requirements.  PSNH owns and operates approximately 1,000 MW of fossil fuel electric generating units, subject to these standards, including the Merrimack, Newington and Schiller stations.  We believe the Clean Air Project at our Merrimack Station, along with existing equipment, enables that facility to meet at least the minimum requirements in the standards.  A review of the potential impact of this rule on PSNH’s other generating units is not yet complete.  However, PSNH believes that the work it has undertaken in recent years to comply with New Hampshire state regulations, including the Clean Air Project, will allow it to meet the new EPA Mercury and Air Toxic Standards without significant additional investment.

EPA Proposed NPDES Permit:  PSNH maintains a NPDES permit consistent with requirements of the Clean Water Act for Merrimack Station.  In 1997, PSNH filed in a timely manner for a renewal of this permit.  As a result, the existing permit was administratively continued.  On September 29, 2011, the EPA issued a draft renewal NPDES permit for PSNH's Merrimack Station for public review and comment.  The proposed permit contains many significant conditions to future operation.  The proposed permit would require PSNH to install a closed-cycle cooling system (including cooling towers) at the station.  The EPA estimated that the net present value cost to install this system and operate it over a 20-year period would be approximately $112 million.

On October 27, 2011, the EPA extended the initial 60-day period for public review and comment on the draft permit for an additional 90 days until February 28, 2012.  The EPA does not have a set deadline to consider comments and to issue a final permit.  Given the complex and unprecedented nature of many of the requirements, extensive comments to the EPA on the draft permit are anticipated from within the utility industry as well as from various environmental groups.  Merrimack Station is permitted to continue to operate under its present permit pending issuance of the final permit and subsequent resolution of matters appealed by PSNH and other parties.  Due to the site specific characteristics of PSNH's other fossil generating stations, we believe it is unlikely that they would have similar permit requirements imposed on them.

2011 Major Storms:

On June 1, 2011, a series of severe thunderstorms with high winds, including tornadoes, struck portions of WMECO’s service territory.  Approximately 17,000 WMECO electric distribution customers were without power.  On June 9, 2011, another series of severe thunderstorms with high winds struck CL&P, PSNH and WMECO's service territories, resulting in power outages for approximately 260,000 electric distribution customers, including 210,000 at CL&P.

On August 28, 2011, Tropical Storm Irene caused extensive damage to our distribution system.  Approximately 800,000 of our 1.9 million electric distribution customers were without power at the peak of the outages, with approximately 670,000 of those customers in Connecticut.  

On October 29, 2011, an unprecedented storm inundated our service territory with heavy snow causing significant damage to our distribution and transmission systems.  Approximately 1.2 million of our electric distribution customers were without power at the peak of the outages, with 810,000 of those customers in Connecticut, 237,000 in New Hampshire, and 140,000 in Massachusetts.  In terms of customer outages, this was the most severe storm in CL&P’s history, surpassing Tropical Storm Irene; the third most severe in PSNH’s history, following a December 2008 ice storm and a February 2010 wind storm; and the most severe in WMECO's history.

CL&P recorded a pre-tax charge for a storm fund reserve of $30 million to provide bill credits to its residential customers who remained without power after noon on Saturday, November 5, 2011 as a result of the October snowstorm, and to provide contributions to certain Connecticut charitable organizations.  CL&P will not seek to recover this amount in its rates.

The magnitude of the storms’ costs and damages met the criteria for cost deferral in Connecticut, New Hampshire, and Massachusetts and as a result, except for the CL&P storm fund reserve, the storms had no material impact on the results of operations of CL&P, PSNH and WMECO.  We believe our response to all storms was prudent and therefore we believe it is probable that CL&P, PSNH and

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WMECO will be allowed to recover these storm costs.  Each operating company will seek recovery of its estimated deferred storm costs through its applicable regulatory recovery process.  

Officials in Connecticut, New Hampshire and Massachusetts have all initiated inquiries into their state's utilities’ response to the October snowstorm, including CL&P, PSNH and WMECO.  In addition, the PURA has included a review of the utilities' responses during Tropical Storm Irene and hired a consultant for the purposes of conducting a management audit into the emergency response programs of CL&P.  These inquiries are expected to be completed in the second quarter of 2012.  Connecticut Governor Malloy appointed a panel to review the preparedness of numerous state entities, including the state's utilities, in the event of a category 3 hurricane.  This panel made its recommendations on January 9, 2012.  Governor Malloy also hired Witt Associates to provide an independent assessment of the state's and CL&P's preparedness, response and restoration efforts during the October snowstorm.  The Witt Associates’ Final Report was issued on December 1, 2011.  Numerous committees of the Connecticut General Assembly also held hearings covering all aspects of storm response in the state.  No official report is expected from these committees.  We are currently evaluating several long-term initiatives to address the findings and recommendations of the panel and Witt Associates' Final Report.  We believe that, if adopted, the future costs associated with these new long-term initiatives will be recovered from customers.

Connecticut – CL&P:

AMI:  On August 29, 2011, PURA issued a draft decision rejecting the full deployment of AMI meters to all of CL&P’s customers at that time.  PURA instead indicated that CL&P should begin installing AMI meters at a more moderate pace once industry standards are developed and CL&P has selected a specific technology to install.  On September 2, 2011, the Commissioner of DEEP filed a motion with PURA to suspend the proceeding while the Bureau of Energy and Technology Policy conducts a process to establish an AMI policy for Connecticut, in accordance with the state law.  On September 8, 2011, PURA granted DEEP’s motion and suspended its proceedings.  No further schedule is available at this time from either DEEP or PURA.  As a result, CL&P has removed the projected AMI capital costs of approximately $257 million from its current five-year capital program.

Standard Service and Last Resort Service Rates:  CL&P's residential and small commercial customers who do not choose competitive suppliers are served under SS rates, and large commercial and industrial customers who do not choose competitive suppliers are served under LRS rates.  CL&P is fully recovering from customers the costs of its SS and LRS services.  Effective January 1, 2012, the PURA approved a decrease to CL&P’s total average SS rate of approximately 8 percent and an increase to CL&P’s total average LRS rate of approximately 10.6 percent.  The energy supply portion of the total average SS rate decreased from 9.732 cents per kWh to 8.443 cents per kWh while the energy supply portion of the total average LRS rate increased from 7.202 cents per kWh to 8.605 cents per kWh.

CTA and SBC Reconciliation and Rates:   On March 31, 2011, CL&P filed with the PURA its 2010 CTA and SBC reconciliation, which compared CTA and SBC revenues to revenue requirements.  For the 12 months ended December 31, 2010, total CTA revenue requirements exceeded CTA revenues by $4.5 million.  For the 12 months ended December 31, 2010, the SBC revenues exceeded SBC revenue requirements by $19.8 million.  On October 12, 2011, PURA approved the 2010 CTA and SBC reconciliations as filed.  The decision allowed a CTA rate, effective January 1, 2012, that would recover $26.1 million during 2012, and requires CL&P to provide updated actual and projected costs when it files its requested rate adjustments for January 1, 2012.  The decision also allowed an SBC rate, effective January 1, 2012, that would collect $23.7 million during 2012.  

On December 22, 2011, PURA approved new CTA and SBC rates, effective January 1, 2012, using updated information provided by CL&P.  Based on that updated information, the CTA rate will decrease from 0.332 cents per kWh to 0.128 cents per kWh, and the SBC will increase from 0.037 cents per kWh to 0.143 cents per kWh.

FMCC Filing: On February 4, 2011, CL&P filed with the PURA its semi-annual filing, which reconciled actual FMCC revenues and charges and GSC revenues and expenses, for the period July 1, 2010 through December 31, 2010, and also included the previously filed revenues and expenses for the January 1, 2010 through June 30, 2010 period.  The filing identified a total net overrecovery of $0.3 million, which includes the remaining uncollected or non-refunded portions from previous filings.  A hearing was held during the second quarter of 2011 and on June 29, 2011, the PURA issued a final decision accepting CL&P’s calculations of GSC, bypassable FMCC and nonbypassable FMCC revenues and expenses for the period July 1, 2010 through December 31, 2010.  On August 1, 2011, CL&P filed with the PURA its semi-annual FMCC filing for the period January 1, 2011 through June 30, 2011.  The filing identified a total net overrecovery of $10.9 million for the period, which includes the remaining uncollected or non-refunded portions from previous filings.  A hearing was held during the fourth quarter of 2011 and on December 28, 2011, the PURA issued a final decision accepting CL&P’s calculations of GSC, bypassable FMCC and nonbypassable FMCC actual revenues and expenses for the six months reviewed in the proceeding.  On February 2, 2012, CL&P filed with the PURA its semi-annual FMCC filing for the period July 1, 2011 through December 31, 2011, and also included the previously filed revenues and expenses for the January 1, 2011 through June 30, 2011 period.  The filing identified a total net overrecovery of $18.7 million, which includes the remaining uncollected or non-refunded portions from previous filings.  PURA has not yet set a schedule to review this filing, but we do not expect the outcome of the PURA's review to have a material adverse impact on CL&P's financial position, results of operations or cash flows.

 

Procurement Fee Rate Proceedings:  In prior years, CL&P submitted to the PURA its proposed methodology to calculate the variable incentive portion of its transition service procurement fee, which was effective for the years 2004, 2005 and 2006, and requested approval of the pre-tax $5.8 million 2004 incentive fee.  CL&P has not recorded amounts related to the 2005 and 2006 procurement fee in earnings.  CL&P recovered the $5.8 million pre-tax amount, which was recorded in 2005 earnings, through a CTA reconciliation process.  On January 15, 2009, the PURA issued a final decision in this docket reversing its December 2005 draft decision and stated that CL&P was not eligible for the procurement incentive compensation for 2004.  A $5.8 million pre-tax charge (approximately $3.5 million net of tax) was recorded in the 2008 earnings of CL&P, and an obligation to refund the $5.8 million to customers was established

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as of December 31, 2008.  CL&P filed an appeal of this decision on February 26, 2009.  On February 4, 2010, the Connecticut Superior Court reversed the PURA decision.  The Court remanded the case back to the PURA for the correction of several specific errors.  On February 22, 2010, the PURA appealed the Connecticut Superior Court’s February 4, 2010 decision to the Connecticut Appellate Court, which then transferred the appeal to the Connecticut Supreme Court.  A decision is expected from the Connecticut Supreme Court in the second half of 2012.

Connecticut - Yankee Gas:

Distribution Rates:  On June 29, 2011, PURA issued a final decision in the Yankee Gas rate proceeding that it amended on September 28, 2011.  The final decision approved a regulatory ROE of 8.83 percent, based on a capital structure of 52.2 percent common equity and 47.8 percent debt, approved Yankee Gas’ WWL Project, and also allowed for an increase for bare steel and cast iron pipe annual replacement funding, as requested by Yankee Gas.  The changes were effective July 20, 2011 and will have the effect of decreasing revenues by $0.2 million for the twelve months ending June 30, 2012 and increasing revenues by $6.9 million for the twelve months ending June 30, 2013.

New Hampshire:

Distribution Rates:  In March 2011, PSNH filed with the NHPUC to collect certain exogenous costs, step increases, and storm costs, as permitted by its 2010 rate case settlement.  These rate increases were offset by the scheduled termination, on June 30, 2011, of a rate recoupment charge, also from the 2010 rate case settlement.  During the second quarter of 2011, the NHPUC issued rate orders approving net increases in revenue requirements effective July 1, 2011 to (1) recover exogenous costs, (2) implement a step increase program for capital additions and the reliability enhancement program, and (3) allow for the recovery of the 2010 windstorm costs.  Together with the scheduled termination of the rate recoupment charge, the net impact of these rate changes was a $2.4 million decrease in rates effective July 1, 2011.

ES, SCRC, and TCAM Filings:  During the second quarter of 2011, PSNH filed with the NHPUC requests for ES, SCRC and TCAM rates of 8.89 cents per kWh, 1.09 cents per kWh, and 1.189 cents per kWh, respectively, to be effective July 1, 2011.  On June 28, 2011, the NHPUC issued orders approving the ES and SCRC rates as filed, and on June 29, 2011, the NHPUC issued an order approving the TCAM rate as filed.

On July 26, 2011, the NHPUC ordered PSNH to file a rate proposal that would mitigate the impact of customer migration expected to occur when the ES rate is higher than market prices.  On January 26, 2012, the NHPUC rejected the PSNH proposal and ordered PSNH to file a new proposal no later than June 30, 2012, addressing certain issues raised by the NHPUC.

On November 22, 2011, the NHPUC opened a docket to place the Clean Air Project into ES rates, including conducting a prudence review and establishing temporary rates.  Hearings are scheduled on temporary rates for March 12 and 13, 2012.  Following hearings on temporary rates, it is expected that recovery of costs of the Clean Air Project will begin during the second quarter of 2012.  No formal schedule for the comprehensive prudence review or for permanent rates has been established.

On December 30, 2011, the NHPUC issued an order establishing an ES rate of 8.31 cents per kWh, effective January 1, 2012, as opposed to the previous 8.89 cents per kWh.

In September 2011, PSNH filed a petition with the NHPUC requesting a change in its SCRC annual rate for the period January 1, 2012 through December 31, 2012.  In mid-December 2011, PSNH filed updated values, which set the proposed SCRC rate at 1.23 cents per kWh.  In late December 2011, the NHPUC approved the SCRC rate as filed.

ES and SCRC Reconciliation:  On an annual basis, PSNH files with the NHPUC an ES/SCRC cost reconciliation filing for the preceding year.  On April 29, 2011, the NHPUC approved a settlement between PSNH and the NHPUC staff regarding PSNH’s 2009 ES/SCRC reconciliation filing.  The settlement did not have a material impact on PSNH's financial position, results of operations or cash flows.  On May 2, 2011, PSNH filed its 2010 ES/SCRC reconciliation with the NHPUC, whose evaluation includes a prudence review of PSNH's generation and power purchase activities.  In November 2011, PSNH and the NHPUC staff reached a settlement regarding PSNH’s 2010 ES/SCRC reconciliation filing.  The settlement did not have a material impact on PSNH's financial position, results of operations or cash flows.  The NHPUC held a hearing on the settlement in late November 2011, and issued an order approving the settlement on January 26, 2012.  

As of December 31, 2011, PSNH had ES and SCRC regulatory assets of $17.3 million and $1.5 million, respectively, which are being recovered from customers in 2012.  

Merrimack Clean Air Project:  On July 7, 2009, the New Hampshire Site Evaluation Committee (NHSEC) determined that PSNH's Clean Air Project was not subject to the NHSEC’s review as a “sizeable” addition to a power plant under state law.  The NHSEC upheld its decision in an order dated January 15, 2010, denying requests for rehearing.  This order was appealed to the New Hampshire Supreme Court on February 23, 2010.  On July 21, 2011, the New Hampshire Supreme Court ruled that the appellants lacked standing to file their original action with the NHSEC, and that the NHSEC erred in entertaining the appellants' filing.  The Court vacated the NHSEC’s decision, confirming PSNH's position that NHSEC approval was not necessary.

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Massachusetts:  

Basic Service Rates:  In 2011, WMECO’s fixed basic service rates ranged from 6.993 cents per kWh to 6.998 cents per kWh for residential customers, 7.498 cents per kWh to 8.006 cents per kWh for small commercial and industrial customers, and 6.958 cents per kWh to 7.450 cents per kWh for medium and large commercial and industrial customers.  Effective January 1, 2012, WMECO’s rates for all basic service customers increased to reflect the basic service solicitations conducted by WMECO in November 2011.  WMECO’s fixed basic service rates for residential customers increased to 7.715 cents per kWh, fixed rates for small commercial and industrial customers increased to 8.238 cents per kWh and fixed rates for large commercial and industrial customers increased to 8.451 cents per kWh.  The fixed price increased by 0.753 cents per kWh for street lighting customers to 6.403 cents per kWh.  

Critical Accounting Policies

The preparation of financial statements in conformity with GAAP requires management to make estimates, assumptions and, at times, difficult, subjective or complex judgments.  Changes in these estimates, assumptions and judgments, in and of themselves, could materially impact our financial position, results of operations or cash flows.  Our management communicates to and discusses with our Audit Committee of the Board of Trustees significant matters relating to critical accounting policies.  Our critical accounting policies are discussed below.  See the combined notes to our consolidated financial statements for further information concerning the accounting policies, estimates and assumptions used in the preparation of our consolidated financial statements.  

Regulatory Accounting:  The accounting policies of the Regulated companies conform to GAAP applicable to rate-regulated enterprises and historically reflect the effects of the rate-making process.

The application of accounting guidance applicable to rate-regulated enterprises results in recording regulatory assets and liabilities.  Regulatory assets represent the deferral of incurred costs that are probable of future recovery in customer rates.  In some cases, we record regulatory assets before approval for recovery has been received from the applicable regulatory commission.  We must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery.  We base our conclusion on certain factors, including, but not limited to, regulatory precedent.  Regulatory liabilities represent revenues received from customers to fund expected costs that have not yet been incurred or probable future refunds to customers.

We use our best judgment when recording regulatory assets and liabilities; however, regulatory commissions can reach different conclusions about the recovery of costs, and those conclusions could have a material impact on our consolidated financial statements. We believe it is probable that the Regulated companies will recover the regulatory assets that have been recorded.  If we determined that we could no longer apply the accounting guidance applicable to rate-regulated enterprises to our operations, or that we could not conclude that it is probable that costs would be recovered or reflected in future rates, the costs would be charged to earnings in the period in which the determination is made.

For further information, see Note 2, “Regulatory Accounting,” to the consolidated financial statements.  

Unbilled Revenues:  The determination of retail energy sales to residential, commercial and industrial customers is based on the reading of meters, which occurs regularly throughout the month.  Billed revenues are based on these meter readings and the majority of recorded annual revenues is based on actual billings.  At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimates, and an estimated amount of unbilled revenues is recorded.

Unbilled revenues represent an estimate of electricity or natural gas delivered to customers but not yet billed.  Unbilled revenues are included in Operating Revenues on the statement of income and are assets on the balance sheet that are reclassified to Accounts Receivable in the following month as customers are billed.  Such estimates are subject to adjustment when actual meter readings become available, when there is a change in estimates and under other circumstances.  

The Regulated companies estimate unbilled revenues monthly using the daily load cycle method.  The daily load cycle method allocates billed sales to the current calendar month based on the daily load for each billing cycle.  The billed sales are subtracted from total month load, net of delivery losses, to estimate unbilled sales.  Unbilled revenues are estimated by first allocating sales to the respective customer classes and then applying an average rate by customer class to the estimate of unbilled sales.  The estimate of unbilled revenues is sensitive to numerous factors, such as energy demands, weather and changes in the composition of customer classes that can significantly impact the amount of revenues recorded.  

For further information, see Note 1L, “Summary of Significant Accounting Policies - Revenues,” to the consolidated financial statements.  

Pension and PBOP:  Our subsidiaries participate in a Pension Plan covering certain of our regular employees and in a PBOP Plan to provide certain health care benefits, primarily medical and dental, and life insurance benefits to retired employees.  For each of these plans, the development of the benefit obligation, fair value of plan assets, funded status and net periodic benefit cost is based on several significant assumptions.  We evaluate these assumptions at least annually and adjust them as necessary.  Changes in these assumptions could have a material impact on our financial position, results of operations or cash flows.  

Pre-tax net periodic pension expense (excluding SERP) for the Pension Plan was $127.7 million, $80.4 million and $39.7 million for the years ended December 31, 2011, 2010 and 2009, respectively.  The pre-tax net PBOP Plan expense was $43.6 million, $41.6 million and $37.2 million for the years ended December 31, 2011, 2010 and 2009, respectively.

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We develop key assumptions for purposes of measuring the plans’ liabilities as of December 31 and expenses for the subsequent year.  These assumptions include the long-term rate of return on plan assets, discount rate, compensation/progression rate, and health care cost trend rates and are discussed below.

Long-Term Rate of Return on Plan Assets:  In developing this assumption, we consider historical and expected returns and input from our actuaries and consultants.  Our expected long-term rate of return on assets is based on assumptions regarding target asset allocations and corresponding expected rates of return for each asset class.  We routinely review the actual asset allocations and periodically rebalance the investments to the targeted asset allocations when appropriate.  We used an aggregate expected long-term rate of return assumption of 8.25 percent on Pension and PBOP Plan assets as of December 31, 2011.

Discount Rate:  Payment obligations related to the Pension Plan and PBOP Plan are discounted at interest rates applicable to the timing of the plans’ cash flows.  The discount rate that is utilized in determining the pension and PBOP obligations is based on a yield-curve approach.  This approach is based on a population of bonds with an average rating of AA based on bond ratings by Moody’s, S&P and Fitch, and uses bonds with above median yields within that population.  The discount rates determined on this basis are 5.03 percent for the Pension Plan and 4.84 percent for the PBOP Plan as of December 31, 2011 and 5.57 percent and 5.28 percent for the respective plans as of December 31, 2010.  

Compensation/Progression Rate:  This assumption reflects the expected long-term salary growth rate, which impacts the estimated benefits that pension plan participants receive in the future.  We used a compensation/progression rate of 3.5 percent as of December 31, 2011 and 2010, which reflects our current expectation of future salary increases, including consideration of the levels of increases built into union contracts.  

Actuarial Determination of Expense:  Pension and PBOP expense are determined by our actuaries and consist of service cost and prior service cost, interest cost based on the discounting of the obligations, amortization of actuarial gains and losses and amortization of the net transition obligation, offset by the expected return on plan assets.  Actuarial gains and losses represent differences between assumptions and actual information or updated assumptions.

We determine the expected return on plan assets by applying our assumed rate of return to a four-year rolling average fair values, which reduces year-to-year volatility.  This calculation recognizes investment gains or losses over a four-year period from the years in which they occur.  Investment gains or losses for this purpose are the difference between the calculated expected return and the actual return or loss based on the change in the fair value of assets during the year.  As of December 31, 2011, investment losses that remain to be reflected in the calculation of plan assets over the next four years were $369 million and $5.8 million for the Pension Plan and PBOP Plan, respectively.  As investment gains and losses are reflected in the average plan asset fair values, they are subject to amortization with other unrecognized actuarial gains or losses.  The plans currently amortize unrecognized actuarial gains or losses as a component of pension and PBOP expense over the average future employee service period of approximately 10 and 9 years, respectively.  As of December 31, 2011, the net unrecognized actuarial losses on the Pension and PBOP Plan liabilities, subject to amortization, were $819.3 million and $202.5 million, respectively.

Forecasted Expenses and Expected Contributions:  Based upon the assumptions and methodologies discussed above, we estimate that forecasted expense for the Pension Plan and PBOP Plan will be $167.9 million and $44.7 million, respectively, in 2012.  Pension and PBOP expense for subsequent years will depend on future investment performance, changes in future discount rates and other assumptions, and various other factors related to the populations participating in the plans.  Pension and PBOP expense charged to earnings is net of the amounts capitalized.  

We expect to continue our policy to contribute to the PBOP Plan at the amount of PBOP expense, excluding curtailments and special benefit amounts and adding contributions for the amounts received from the federal Medicare subsidy.  NU's policy is to annually fund the Pension Plan in an amount at least equal to what will satisfy the requirements of ERISA, as amended by the PPA, and the Internal Revenue Code.  NU's Pension Plan has historically been well funded, and a contribution was not required to be made from 1991 until the third quarter of 2010, when PSNH made a contribution to the plan of $45 million.  NU made contributions totaling $143.6 million in 2011, $112.6 million of which were contributed by PSNH.  Our Pension Plan funded ratio (the value of plan assets divided by the funding target in accordance with the requirements and guidelines of the PPA) was 80 percent as of January 1, 2011.  We currently estimate that quarterly contributions aggregating to a total of $197.3 million will be made in 2012.  

Sensitivity Analysis:  The following represents the hypothetical increase to the Pension Plan’s (excluding SERP) and PBOP Plan’s reported annual cost as a result of a change in the following assumptions by 50 basis points (in millions):

		As of December 31,
		Pension Plan Cost						Postretirement Plan Cost
Assumption Change			2011			2010		2011			2010
Lower long-term rate of return		$	10.3		$	10.7		$	1.3		$	1.2
Lower discount rate		$	14.2		$	13.4		$	2.3		$	2.2
Higher compensation increase		$	6.5		$	6.1		$	N/A			N/A

Pension Plan Contributions Discount Rate Sensitivity Analysis:  Fluctuations in the average discount rate used to calculate expected Pension Plan contributions can have a significant impact on the amount of Pension Plan contributions estimated to be required.  As of December 31, 2011, the average discount rate (segment rate) used to calculate funding target and to determine the expected Pension Plan contributions totaling $590 million for the period 2013 through 2016 was approximately 5.5 percent.  If this discount rate was decreased by 50 basis points, all other items remaining constant, then the expected aggregate contributions would increase to

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approximately $710 million for the period 2013 through 2016.  In addition, the market performance of existing plan assets, the valuation of the plan's liabilities, and a variety of other factors would impact the Pension Plan contributions.  

Health Care Cost:  The health care cost trend assumption used to project increases in medical costs was 7 percent for determining 2011 PBOP Plan expense.  For 2012 and 2013, the rate is 7 percent, subsequently decreasing one half percentage point per year to an ultimate rate of 5 percent in 2017.  The effect of a hypothetical increase in the health care cost trend rate by one percentage point would be to have increased service and interest cost components of PBOP Plan expense by $1.2 million in 2011, with a $16.2 million impact on the postretirement benefit obligation.

See Note 10A, “Employee Benefits - Pension Benefits and Postretirement Benefits Other Than Pensions,” to the consolidated financial statements for more information.

Goodwill and Intangible Assets:  We are required to test goodwill balances for impairment at least annually by applying a fair value-based test that requires us to use estimates and judgment.  We have selected October 1^st of each year as the annual goodwill impairment testing date.  Goodwill impairment is deemed to exist if the net book value of a reporting unit exceeds its estimated fair value and if the implied fair value of goodwill based on the estimated fair value of the reporting unit is less than the carrying amount of the goodwill.  If goodwill were deemed to be impaired, it would be written down in the current period to the extent of the impairment.  

We determine the discount rate using the capital asset pricing model methodology.  This methodology uses a weighted average cost of capital in which the ROE is developed using risk-free rates, equity premiums and a beta representing Yankee Gas' volatility relative to the overall market.  The resulting discount rate is intended to be comparable to a rate that would be applied by a market participant.  The discount rate may change from year to year as it is based on external market conditions.

We performed an impairment analysis as of October 1, 2011 for the Yankee Gas goodwill balance of $287.6 million.  We determined that the fair value of Yankee Gas substantially exceeds its carrying value and no impairment exists.  In performing the evaluation, we estimated the fair value of the Yankee Gas reporting unit and compared it to the carrying amount of the reporting unit, including goodwill.  We estimated the fair value of Yankee Gas using a discounted cash flow methodology and two market approaches that analyze comparable companies or transactions.  This evaluation requires the input of several critical assumptions, including future growth rates, cash flow projections, operating cost escalation rates, rates of return, a risk-adjusted discount rate, long-term earnings and merger multiples of comparable companies.

Income Taxes:  Income tax expense is estimated annually for each of the jurisdictions in which we operate.  This process involves estimating current and deferred income tax expense or benefit and the impact of temporary differences resulting from differing treatment of items for financial reporting and income tax return reporting purposes.  Such differences are the result of timing of the deduction for expenses, as well as any impact of permanent differences resulting from tax credits, non-tax deductible expenses, in addition to various other items, including items that directly impact our tax return as a result of a regulatory activity (flow-through items).  The temporary differences and flow-through items result in deferred tax assets and liabilities that are included in the consolidated balance sheets.  The income tax estimation process impacts all of our segments.  We record income tax expense quarterly using an estimated annualized effective tax rate.  

A reconciliation of expected tax expense at the statutory federal income tax rate to actual tax expense recorded is included in Note 11, “Income Taxes,” to the consolidated financial statements.

We also account for uncertainty in income taxes, which applies to all income tax positions previously filed in a tax return and income tax positions expected to be taken in a future tax return that have been reflected on our balance sheets.  We follow generally accepted accounting principles to address the methodology to be used in recognizing, measuring and classifying the amounts associated with tax positions that are deemed to be uncertain, including related interest and penalties.  The determination of whether a tax position meets the recognition threshold under this guidance is based on facts and circumstances available to us.  Once a tax position meets the recognition threshold, the tax benefit is measured using a cumulative probability assessment.  Assigning probabilities in measuring a recognized tax position and evaluating new information or events in subsequent periods requires significant judgment and could change previous conclusions used to measure the tax position estimate.  New information or events may include tax examinations or appeals (including information gained from those examinations), developments in case law, settlements of tax positions, changes in tax law and regulations, rulings by taxing authorities and statute of limitation expirations.  Such information or events may have a significant impact on our financial position, results of operations and cash flows.  

Accounting for Environmental Reserves:  Environmental reserves are accrued when assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated.  Adjustments made to estimates of environmental liabilities could have a significant impact on earnings.  We estimate these liabilities based on findings through various phases of the assessment, considering the most likely action plan from a variety of available options (ranging from no action to full site remediation and long-term monitoring), current site information from our site assessments, remediation estimates from third party engineering and remediation contractors, and our prior experience in remediating contaminated sites.  Our estimates incorporate currently enacted state and federal environmental laws and regulations and data released by the EPA and other organizations.  The estimates associated with each possible action plan are judgmental in nature partly because there are usually several different remediation options from which to choose.  Our estimates are subject to revision in future periods based on actual costs or new information from other sources, including the level of contamination at the site recently enacted laws and regulations or a change in estimates due to certain economic factors.  

For further information, see Note 12A, “Commitments and Contingencies - Environmental Matters,” to the consolidated financial statements and Other Matters below.

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Fair Value Measurements:  We follow fair value measurement guidance that defines fair value as the price that would be received for the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (an exit price).  We have applied this guidance to the Company's derivative contracts that are recorded at fair value, marketable securities held in NU’s supplemental benefit trust and WMECO’s spent nuclear fuel trust, our valuations of investments in our pension and PBOP plans, and nonrecurring fair value measurements of nonfinancial assets such as goodwill and AROs.  

Changes in fair value of the regulated company derivative contracts are recorded as Regulatory assets or liabilities, as we expect to recover the costs of these contracts in rates.  These valuations are sensitive to the prices of energy and energy related products in future years for which markets have not yet developed and assumptions are made.  

We use quoted market prices when available to determine fair values of financial instruments.  If quoted market prices are not available, fair value is determined using quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments that are not active and model-derived valuations.  When quoted prices in active markets for the same or similar instruments are not available, we value derivative contracts using models that incorporate both observable and unobservable inputs.  Significant unobservable inputs utilized in the models include energy and energy-related product prices for future years for long-dated derivative contracts, future contract quantities under full requirements and supplemental sales contracts, and market volatilities.  Discounted cash flow valuations incorporate estimates of premiums or discounts, reflecting risk adjusted profit that would be required by a market participant to arrive at an exit price, using available historical market transaction information.  Valuations of derivative contracts also reflect our estimates of nonperformance risk, including credit risk.  

For further information, see Item 7A, “Quantitative and Qualitative Disclosures about Market Risk,” included in this Annual Report on Form 10-K for a sensitivity analysis of how changes in the prices of energy and energy related products would impact earnings.  

For further information on derivative contracts and marketable securities, see Note 1J, “Summary of Significant Accounting Policies - Derivative Accounting,” Note 4, “Derivative Instruments,” and Note 5, “Marketable Securities,” to the consolidated financial statements.

Other Matters

Environmental Matter:  HWP continues to investigate the potential need for additional remediation at a river site in Massachusetts containing tar deposits associated with an MGP site that HWP sold to HG&E, a municipal utility, in 1902.  As of December 31, 2011, HWP had a $2.4 million reserve for estimated costs that HWP considers probable over the remaining life of the remediation term.  Although a material increase to the reserve is not presently anticipated, management cannot reasonably estimate potential additional investigation or remediation costs because these costs would depend, among other things, on the nature, extent and timing of additional investigation and remediation that may be required by the MA DEP.

For further information, see Note 12A, “Commitments and Contingencies - Environmental Matters,” to the consolidated financial statements.

Accounting Standards Issued But Not Yet Adopted:  For information regarding new accounting standards, see Note 1D, “Summary of Significant Accounting Policies - Accounting Standards Issued But Not Yet Adopted,” to the consolidated financial statements.

Contractual Obligations and Commercial Commitments:  Information regarding our contractual obligations and commercial commitments as of December 31, 2011 is summarized annually through 2016 and thereafter as follows: