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, 2012
	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

1-02301	NSTAR ELECTRIC COMPANY (a Massachusetts corporation) 800 Boylston Street Boston, Massachusetts 02199 Telephone:  (617) 424-2000	04-1278810

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:

	4.25%	Series
	4.78%	Series

NSTAR Electric Company, Public Service Company of New Hampshire and Western Massachusetts Electric Company each meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and each is 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
NSTAR Electric 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
NSTAR Electric 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, 2012) was $12,177,646,948 based on a closing sales price of $38.81 per share for the 313,776,010 common shares outstanding on June 30, 2012.  

Northeast Utilities, directly or indirectly, holds all of the 6,035,205 shares, 100 shares, 301 shares, and 434,653 shares of the outstanding common stock of The Connecticut Light and Power Company, NSTAR Electric 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, 2013
Northeast Utilities Common shares, $5.00 par value	314,338,271 shares
The Connecticut Light and Power Company Common stock, $10.00 par value	6,035,205 shares
NSTAR Electric Company Common Stock, $1.00 par value	100 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

i

ii

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

2012 FORM 10-K ANNUAL REPORT

TABLE OF CONTENTS

iii

NORTHEAST UTILITIES AND SUBSIDIARIES

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARY

NSTAR ELECTRIC COMPANY AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

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, including NSTAR LLC and its subsidiaries for periods after April 10, 2012.

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:

·

the possibility that expected merger synergies will not be realized or will not be realized within the expected time period,

·

cyber breaches, acts of war or terrorism, or grid disturbances,

·

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, 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 us to predict all of such factors, nor can we 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.

1

NORTHEAST UTILITIES AND SUBSIDIARIES

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

NSTAR ELECTRIC COMPANY AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

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.

NU, headquartered in Boston, Massachusetts and 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;

●

NSTAR Electric Company (NSTAR Electric), a regulated electric utility that serves residential, commercial and industrial customers in parts of Massachusetts;

●

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;

●

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;

●

NSTAR Gas Company (NSTAR Gas), a regulated natural gas utility that serves residential, commercial and industrial customers in parts of Massachusetts; 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 subsidiaries, NU Enterprises and NSTAR LLC, which are included in its Parent and other companies’ results of operations.

Although NU, CL&P, NSTAR Electric, PSNH and WMECO each report their financial results separately, we also include information in this report on a segment, or line-of-business, basis.  The Regulated companies' segments include the electric distribution segment, the natural gas distribution segment and the electric transmission segment.  The electric distribution segment includes the generation businesses of PSNH and WMECO.  The Regulated companies' segments represented substantially all of NU's total consolidated revenues for years ended December 31, 2012 and 2011.  

MERGER WITH NSTAR

On April 10, 2012, NU completed its merger with NSTAR (Merger).  Pursuant to the terms and conditions of the Agreement and Plan of Merger, as amended, NSTAR was merged with and into a wholly owned subsidiary of NU, which was subsequently renamed NSTAR LLC.  NU’s consolidated financial statements include the results of operations of NSTAR LLC and its subsidiaries for the period after April 10, 2012.

ELECTRIC DISTRIBUTION SEGMENT

General

NU’s electric distribution segment consists of the distribution businesses of CL&P, NSTAR Electric, PSNH and WMECO, which are engaged in the distribution of electricity to retail customers in Connecticut, eastern Massachusetts, New Hampshire and western Massachusetts, respectively, plus the regulated electric generation businesses of PSNH and WMECO.  

The following table shows the sources of 2012 electric franchise retail revenues for NU’s electric distribution companies, collectively, based on categories of customers, including the electric franchise retail revenues of NSTAR Electric from the date of merger, April 10, 2012, through December 31, 2012:

2

(Thousands of Dollars, except percentages)		2012		% of Total
Residential	$	2,731,951		52
Commercial		1,563,709		30
Industrial		753,974		14
Streetlighting and Railroads		40,952		1
Miscellaneous and Eliminations		130,137		3
Total Retail Electric Revenues	$	5,220,723		100%

A summary of our distribution companies’ retail electric GWh sales and percentage changes for 2012, as compared to 2011, is as follows:

		2012 (1)		2011		Percentage Change
Residential		19,719		14,766		33.5%
Commercial		24,117		14,301		68.6%
Industrial		5,462		4,418		23.6%
Other		420		327		28.6%
Total		49,718		33,812		47.0%

⁽¹⁾

NU retail electric sales include the sales of NSTAR Electric from the date of merger, April 10, 2012, through December 31, 2012.

Actual retail electric sales for CL&P, NSTAR Electric and WMECO decreased in 2012, as compared to 2011, due primarily to the warmer than normal weather in the first quarter of 2012, as compared to colder than normal weather in the first quarter of 2011, while actual retail electric sales for PSNH were 0.1 percent higher than last year.  In 2012, heating degree days were 11 percent lower in Connecticut and western Massachusetts, 7 percent lower in the Boston metropolitan area, and 9 percent lower in New Hampshire, as compared to 2011.  On a weather normalized basis (based on 30-year average temperatures), the average NU combined consolidated total retail electric sales decreased 0.2 percent in 2012, as compared to 2011, assuming NSTAR Electric had been part of the NU combined electric distribution system for all periods under consideration.  We believe these decreases were due primarily to increased conservation efforts among all our customer classes and the continued installation of distributed generation at our commercial and industrial customers’ facilities.  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 annual level of baseline distribution delivery service revenues of $125.4 million that it is able to recover.  This effectively breaks the relationship between sales volume and revenues recognized.

Major Storms

On August 28, 2011, Tropical Storm Irene caused extensive damage to our distribution system.  Approximately 800,000 CL&P, PSNH and WMECO customers were without power at the peak of the outages, with approximately 670,000 of those customers in Connecticut.  Approximately 500,000 customer outages occurred on the NSTAR Electric distribution system in its aftermath.

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 CL&P, PSNH and WMECO’s 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 western 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; and the most severe in WMECO's history.  The storm also caused approximately 200,000 customer outages on the NSTAR Electric distribution system.  

On October 29, 2012, Hurricane Sandy caused extensive damage to our electric distribution system across all three states.  Approximately 1.5 million of our 3.1 million electric distribution customers were without power during or following the storm, with approximately 850,000 of those customers in Connecticut, approximately 472,000 in Massachusetts, and approximately 137,000 in New Hampshire.

As of December 31, 2012, deferred storm restoration costs related to these major storms that are deferred for future recovery at CL&P, NSTAR Electric, PSNH, and WMECO were as follows:

(Millions of Dollars)		Tropical Storm Irene		October Snowstorm		Hurricane Sandy		Total
CL&P		$ 108.6		$ 173.0		$ 159.9		$ 441.5
NSTAR Electric		21.9		13.9		27.8		63.6
PSNH		6.8		15.5		12.1		34.4
WMECO		3.2		23.3		4.2		30.7
Total		$ 140.5		$ 225.7		$ 204.0		$ 570.2

3

On February 8, 2013, a blizzard caused damage to the electric delivery systems of CL&P and NSTAR Electric.  We have estimated that approximately 71,000 and 350,000 of CL&P and NSTAR Electric's distribution customers, respectively, were without power during or following the storm.  We believe that this storm will cost between $100 million to $120 million, with approximately 90 percent of those costs relating to NSTAR Electric.  Management expects the costs to meet the criteria for specific cost recovery in Connecticut and Massachusetts and, as a result, does not expect the storm to have a material impact on the results of operations of CL&P or NSTAR Electric.  Each operating company will seek recovery of these anticipated deferred storm costs through its applicable regulatory recovery process.

ELECTRIC DISTRIBUTION – CONNECTICUT

THE CONNECTICUT LIGHT AND POWER COMPANY

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, 2012, CL&P furnished retail franchise electric service to approximately 1.2 million customers in 149 cities and towns in Connecticut, covering an area of 4,400 square miles.  CL&P does not own any electric generation facilities.  

The following table shows the sources of CL&P’s 2012 electric franchise retail revenues based on categories of customers:

	CL&P
(Thousands of Dollars, except percentages)		2012		% of Total
Residential	$	1,263,845		58
Commercial		711,337		32
Industrial		126,165		6
Streetlighting and Railroads		21,283		1
Miscellaneous		70,012		3
Total Retail Electric Revenues	$	2,192,642		100%

A summary of CL&P’s retail electric GWh sales and percentage changes for 2012, as compared to 2011, is as follows:

		2012		2011		Percentage Change
Residential		9,978		10,092		(1.1)%
Commercial		9,414		9,525		(1.2)%
Industrial		2,426		2,414		0.5 %
Other		291		284		2.3 %
Total		22,109		22,315		(0.9)%

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

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.

The distribution rates established by the PURA for CL&P are comprised of the following:

·

GSC charge (the electric generation services component), which recovers energy-related costs incurred as a result of providing electric generation service supply to all customers that have not migrated to competitive energy suppliers.  The GSC charge is adjusted periodically and reconciled semi-annually in accordance with the directives of PURA.  Expense/revenue reconciliation amounts are recovered in subsequent rates.

4

·

FMCC charge, which recovers any costs imposed by the FERC as part of the New England Standard Market Design, including locational marginal pricing, locational installed capacity payments, any cost approved by PURA to reduce FMCC charges (with conditions) and reliability must run contracts.  The FMCC charge is adjusted periodically and reconciled semi-annually in accordance with the directives of PURA.  Expense/revenue reconciliation amounts are recovered in subsequent rates.

·

SBC charge, established to fund expenses for the public education outreach program, costs associated with various hardship and low income programs, a program to compensate municipalities for losses in property tax revenue due to decreases in the value of electric generating facilities resulting directly from electric industry restructuring, displaced worker protection costs, unfunded storage and disposal costs for spent nuclear fuel generated before January 1, 2000, and decommissioning fund contributions.  Any element of the SBC charge may be revised by PURA as the need arises.  The SBC charge is reconciled annually to actual costs incurred, with any difference refunded to, or recovered from, customers.

·

CTA charge, which pays the principal and interest on RRBs as well as the reasonable and necessary costs related to the RRBs financing.  The CTA charge is also assessed to recover stranded costs associated with electric industry restructuring as well as various IPP contracts that were not funded with the proceeds of the RRBs. The CTA charge is reconciled annually to actual costs incurred, with any difference refunded to, or recovered from, customers.

·

The Renewable Energy Investment Fund charge, which is used to promote investment in renewable energy sources.  Funds collected by this charge are deposited into the Renewable Energy Investment Fund and administered by Connecticut Innovations, Incorporated.  The Renewable Energy Investment Fund charge is set by statute and is currently 0.1 cent per kWh.  

·

C&LM charge, established to implement cost-effective energy conservation programs and market transformation initiatives.  

·

Transmission adjustment clause, which reconciles on a semi-annual basis the transmission revenues billed to customers against the transmission costs of acquiring such services, to recover 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 consisting of three generation projects 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.

CL&P, jointly with UI, has entered into three CfDs (each having a 80 percent to 20 percent sharing mechanism as described above), with developers of peaking generation units approved by the PURA (Peaker CfDs).  These units have a total of approximately 500 MW of peaking capacity.  The Peaker CfDs pay the developer the difference between capacity, forward reserve and energy market revenues and a cost-of-service payment stream for 30 years.  The ultimate cost or benefit to CL&P under these contracts will depend on the costs of plant construction and operation and the prices that the projects receive for capacity and other products in the ISO-NE markets.  CL&P's portion of the amounts paid or received under the Peaker CfDs will be recoverable from or refunded to CL&P's customers.  

On June 30, 2010, PURA issued a final order in CL&P’s most recent retail distribution rate case approving distribution rates and establishing CL&P’s authorized distribution regulatory ROE at 9.4 percent.  

On March 13, 2012, NU and NSTAR reached a comprehensive settlement agreement with both the Connecticut Attorney General and the Connecticut Office of Consumer Counsel related to the Merger.  The settlement agreement covered a variety of matters, including a CL&P base distribution rate freeze until December 1, 2014.  The settlement agreement also provided for a $25 million rate credit to CL&P customers and the establishment of a $15 million fund for energy efficiency and other initiatives to be disbursed at the direction of the DEEP.  CL&P also agreed to forego rate recovery of $40 million of deferred storm costs associated with restoration activities following Tropical Storm Irene and the October 2011 snowstorm.  On April 2, 2012, the PURA approved the settlement agreement and the Merger.

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 for the first half of 2013, and 70 percent of expected load for the second half of 2013.  CL&P intends to purchase 10 percent of the SS load for the second half of 2013.  None of the SS load for 2014 has been procured.  CL&P’s contracts for its LRS loads extend through the second quarter of 2013, and CL&P intends to purchase 10 percent of the LRS load for the third quarter of 2013.

5

ELECTRIC DISTRIBUTION – MASSACHUSETTS

NSTAR ELECTRIC COMPANY

WESTERN MASSACHUSETTS ELECTRIC COMPANY

The electric distribution businesses of NSTAR Electric and WMECO consist primarily of the purchase, delivery and sale of electricity to residential, commercial and industrial customers within their respective franchise service territories.  As of December 31, 2012, NSTAR Electric furnished retail franchise electric service to approximately 1.1 million customers in Boston and 80 surrounding cities and towns in Massachusetts, including Cape Cod and Martha’s Vineyard, covering an area of 1,702 square miles.  WMECO provides retail franchise electric service to approximately 207,000 retail customers in 59 cities and towns in the western region of Massachusetts, covering an area of 1,500 square miles.  Neither NSTAR Electric nor WMECO owns any fossil or hydro-electric generating facilities, and each purchases its respective energy requirements from competitive suppliers.  

In 2009, WMECO was authorized by the DPU 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.  In connection with the Attorney General settlement agreement (as defined below) that approved the Merger in Massachusetts, WMECO committed to increase its solar generation capacity to 8 MW.  WMECO is continuing to evaluate sites suitable for development of the remaining 3.9 MW of capacity.  WMECO will sell all energy and other products from its solar generation facilities into the ISO-NE market.  NSTAR Electric does not own any solar generating facilities, but agreed to issue a request for proposals to enter into long-term contracts for 10 megawatts of solar power in connection with the Attorney General settlement agreement that approved the Merger in Massachusetts.  NSTAR Electric has entered in two contracts for 5 MW of capacity, which contracts are still pending approval at the DPU.  

The following table shows the sources of the 2012 electric franchise retail revenues of NSTAR Electric and WMECO based on categories of customers:

		NSTAR Electric					WMECO
(Thousands of Dollars, except percentages)		2012		% of Total		2012				% of Total
Residential	$	1,000,038		44		$		213,494		55
Commercial		1,101,575		48				123,651		32
Industrial		94,130		4				40,207		10
Streetlighting and Railroads		13,047		1				3,780		1
Miscellaneous		85,885		3				5,973		2
Total Retail Electric Revenues	$	2,294,675		100%		$		387,105		100%

A summary of NSTAR Electric’s and WMECO’s retail electric GWh sales and percentage changes for 2012, as compared to 2011, is as follows:

		NSTAR Electric						WMECO
		2012		2011		Percentage Change		2012		2011		Percentage Change
Residential		6,741		6,727		0.2 %		1,517		1,533		(1.0)%
Commercial		12,987		13,211		(1.7)%		1,485		1,474		0.7 %
Industrial		1,353		1,418		(4.6)%		663		669		(0.9)%
Other		128		146		(12.2)%		18		19		(5.7)%
Total		21,209		21,502		(1.4)%		3,683		3,695		(0.3)%

Rates

NSTAR Electric and WMECO are each 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.  The present general rate structure for both NSTAR Electric and WMECO 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 customers of each of NSTAR Electric and WMECO are entitled to choose their energy suppliers, while NSTAR Electric or WMECO, as the case may be, remains their distribution company.  Both NSTAR Electric and WMECO purchase power from competitive suppliers for, and pass through the cost to, their respective customers who do not choose a competitive energy supplier (basic service).  Basic service charges are adjusted and reconciled on an annual basis.  Most of the residential and small commercial and industrial customers of NSTAR Electric and WMECO have continued to buy their power from NSTAR Electric or WMECO, as the case may be, at basic service rates.  Most large commercial and industrial customers have switched to a competitive energy supplier.

6

The Cape Light Compact, an inter-governmental organization consisting of the 21 towns and two counties on Cape Cod and Martha’s Vineyard, serves 200,000 customers through the delivery of energy efficiency programs, effective consumer advocacy, competitive electricity supply and green power options.  NSTAR Electric continues to provide electric service to these customers including the delivery of power, meter reading, billing, and customer service.

NSTAR Electric continues to supply approximately 40 percent of its customer load at basic service rates while the other 60 percent of its customer load has migrated to competitive energy suppliers.  WMECO continues to supply approximately 49 percent of its customer load at basic service rates while the other 51 percent of its customer load has migrated to competitive energy suppliers.  Because customer migration is limited to energy supply service, it has no impact on the delivery business or operating income of NSTAR and WMECO.

The distribution rates established by the DPU for NSTAR Electric and WMECO are comprised of the following:

·

A distribution charge, which includes a fixed customer charge and a demand and/or energy charge to collect the costs of building and expanding the infrastructure to deliver power to its destination, as well as ongoing operating costs.  The distribution charge also includes the recovery, on a fully reconciling basis, of certain DPU-approved safety and reliability program costs, a Pension and PBOP Rate Adjustment Mechanism (PAM) to recover incremental pension and PBOP benefit costs, a reconciling rate adjustment mechanism to recover costs associated with the residential assistance adjustment clause, a net-metering reconciliation surcharge to collect the lost revenues and credits associated with net-metering facilities installed by customers, and an Energy Efficiency Reconciling Factor (EERF) to recover energy efficiency program costs and lost base revenues in addition to those charges recovered in the energy conservation charge.

·

A basic service charge represents the collection of energy costs, including costs related to charge-offs of uncollected energy costs, through DPU-approved rate mechanisms.  Electric distribution companies in Massachusetts are required to obtain and resell power to retail customers through basic service for those who choose not to buy energy from a competitive energy supplier.  Basic service rates are reset every six months (every three months for large commercial and industrial customers).  The price of basic service is intended to reflect the average competitive market price for electric power.  Additionally, the DPU has authorized NSTAR Electric to recover the cost of its Dynamic Pricing Smart Grid Pilot Program through the basic service charge.

·

A transition charge represents costs to be collected primarily from previously held investments in generating plants, costs related to existing above-market power contracts, and contract costs related to long-term power contracts buy-outs.

·

A transmission charge to recover the costs of transporting electricity over high voltage lines from generating plants to substations, including costs allocated by ISO-NE to maintain the wholesale electric market.

·

An energy conservation charge represents a legislatively-mandated charge to collect costs for energy efficiency programs.

·

A renewable energy charge represents a legislatively-mandated charge to collect the costs to support the development and promotion of renewable energy projects.

Rate Settlement Agreement

On February 15, 2012, NU and NSTAR reached comprehensive settlement agreements with the Massachusetts Attorney General (Attorney General settlement agreement) and the DOER related to the Merger.  The Attorney General settlement agreement covered a variety of rate-making and rate design issues, including a base distribution rate freeze through 2015 for NSTAR Electric and WMECO, a rate credit of $15 million to customers of NSTAR Electric and a rate credit of $3 million to customers of WMECO.  The settlement agreement reached with the DOER covered the same rate-making and rate design issues as the Attorney General's settlement agreement, as well as a variety of matters impacting the advancement of Massachusetts clean energy policy established by the Green Communities Act and Global Warming Solutions Act. On April 4, 2012, the DPU approved the settlement agreements and the Merger.

NSTAR Electric is operating under a DPU-approved Rate Settlement Agreement (Rate Settlement Agreement) that was scheduled to expire on December 31, 2012.  As noted above, the rates under the Rate Settlement Agreement are subject to a base distribution rate freeze through 2015 pursuant to the Attorney General settlement agreement.  Pursuant to a 2008 DPU order, Massachusetts electric utilities must adopt rate structures that decouple the volume of energy sales from the utility’s revenues in their next rate case.  The exact timing of NSTAR Electric’s next rate case has not yet been determined, but it will not be before 2015.

In WMECO’s January 31, 2011 rate decision, the DPU approved 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 rates under the January 31, 2011 rate decision are subject to a base distribution rate freeze through 2015 pursuant to the Attorney General settlement agreement .

NSTAR Electric and WMECO are each subject to service quality (SQ) metrics that measure safety, reliability and customer service, and must pay to customers any charges incurred for failure to meet such metrics.  Neither NSTAR Electric nor WMECO will be required to

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pay an assessment charge for its 2012 performance results as both companies performed at or above target for all of their respective SQ metrics in 2012.

Sources and Availability of Electric Power Supply

As noted above, neither NSTAR Electric nor WMECO owns any generation assets (other than WMECO’s recently constructed solar generation), and both companies purchase their respective energy requirements from a variety of competitive sources through requests for proposals issued periodically, consistent with DPU regulations.  NSTAR Electric and WMECO enter into supply contracts for basic service for 50 percent of their respective residential and small commercial and industrial customers twice a year for twelve month terms.  Both NSTAR Electric and WMECO enter into supply contracts for basic service for 100 percent of large commercial and industrial customers every three months.

ELECTRIC DISTRIBUTION – NEW HAMPSHIRE

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE

PSNH’s distribution business consists primarily of the generation, delivery and sale of electricity to its residential, commercial and industrial customers.  As of December 31, 2012, PSNH furnished retail franchise electric service to approximately 500,000 retail customers in 211 cities and towns in New Hampshire, covering an area of 5,628 square miles. 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 business includes the activities of its generation business.

The Clean Air Project, a wet flue gas desulphurization system (Scrubber), was constructed and placed in service by PSNH at its Merrimack Station in September 2011.  The cost of the Scrubber is expected to 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 completed remaining project construction activities in 2012 and the final cost of the project was approximately $421 million.

The Clean Air Project was placed in service and began operations nearly two years before the statutory deadline of July 1, 2013.  Tests to date indicate that the Scrubber reduces emissions of SO₂ and mercury from Merrimack Station by over 90 percent, which is well in excess of state and federal requirements.  Notwithstanding the Clean Air Project's environmental successes well in advance of the statutory deadline, competitors and environmental groups continue to challenge PSNH's right to recover the costs of this legally-mandated project.  In particular, TransCanada, a Canadian energy company that is pursuing the transcontinental Keystone XL pipeline across the United States and is a participant in the U.S. competitive electricity market, and the Conservation Law Foundation, an environmental group which initially supported the law requiring installation of the Scrubber and which formally notified PSNH that it intended to sue PSNH under the Clean Air Act for not installing such emissions control technology, both now claim PSNH was imprudent for pursuing the Clean Air Project.  PSNH is vigorously defending its constitutionally protected right to recover the costs of the Clean Air Project, which were invested to comply with the express mandates of state law.

The following table shows the sources of PSNH’s 2012 electric franchise retail revenues based on categories of customers:

	PSNH
(Thousands of Dollars, except percentages)		2012		% of Total
Residential	$	511,036		54
Commercial		313,201		33
Industrial		82,141		9
Streetlighting and Railroads		6,061		1
Miscellaneous		33,948		3
Total Retail Electric Revenues	$	946,387		100%

A summary of PSNH’s retail electric GWh sales and percentage changes for 2012, as compared to 2011, is as follows:

		2012		2011		Percentage Change
Residential		3,138		3,141		(0.1)%
Commercial		3,315		3,315		0.0 %
Industrial		1,345		1,336		0.7 %
Other		23		23		(1.0)%
Total		7,821		7,815		0.1 %

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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. New Hampshire 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 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 2012, approximately 9.4 percent of all of PSNH’s customers (approximately 44 percent of load), mostly large commercial and industrial customers, had switched to competitive energy suppliers.  This was an increase from 2011, when 2.6 percent of customers (approximately 36 percent of load) 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.  On April 27, 2012, PSNH filed its proposed Alternative Default Energy Service Rate that addresses customer migration, with an effective date of July 1, 2012.  The proposal, if implemented, would result in no impact to earnings and would allow for an increased contribution to fixed costs for all ES customers.  Hearings were held on October 18, 2012 and November 26, 2012.  A final decision is expected in the first quarter of 2013.

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.  

The distribution rates established by the NHPUC for PSNH are comprised of the following:

·

ES charge, which recovers PSNH’s generation and purchased power costs from customers on a current basis and allows for an ROE of 9.81 percent on its generation investment.  

·

SCRC, which 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.

·

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

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.  On December 28, 2012, the NHPUC issued orders approving PSNH’s requests to adjust its ES and SCRC rates effective with service rendered on and after January 1, 2013.  The orders approve an increase to the ES billing rate to reflect projected costs for 2013 and a decrease to the SCRC billing rate to reflect the full amortization of RRBs as of May 1, 2013.  The impact to customers that purchase energy from PSNH is a net increase of 1.287 cents per kWh in total rates.

On June 28, 2010, the NHPUC approved a joint settlement of PSNH's rate case.  Under the approved settlement, if PSNH's 12-month rolling average ROE for distribution exceeds 10 percent, amounts over the 10 percent level are to be allocated 75 percent to customers and 25 percent to PSNH.  Additionally, the settlement provided that the authorized regulatory ROE on distribution plant would continue at the previously allowed level of 9.67 percent, and also permitted PSNH to file a request to collect certain exogenous costs and step increases on an annual basis.  In 2012, PSNH filed for a step increase and a change in its accrual to its major storm reserve fund.  On June 27, 2012, the NHPUC approved an annualized distribution rate increase of $7.1 million effective July 1, 2012, for the step increase.  Additionally, PSNH was allowed a $3.5 million increase in the annual accrual to its major storm reserve fund effective July 1, 2012.

On November 22, 2011, the NHPUC opened a docket to review the Clean Air Project including the establishment of temporary rates for near-term recovery of Clean Air Project costs, a prudence review of PSNH's overall construction program, and establishment of permanent rates for recovery of prudently incurred Clean Air Project costs. On April 10, 2012, the NHPUC issued an order authorizing temporary rates, effective April 16, 2012, which recover a significant portion of the Clean Air Project costs, including a return on equity. The docket will continue for a comprehensive prudence review of the Clean Air Project and the establishment of a permanent rate. The temporary rates will remain in effect until a permanent rate allowing full recovery of all prudently incurred costs is approved. At that time,

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the NHPUC will reconcile recoveries collected under the temporary rates with final approved rates.  PSNH expects hearings to commence in this proceeding on or about the third quarter of 2013.  PSNH believes that its actions related to Clean Air Project construction will be deemed prudent. The project was completed for $421 million, approximately $36 million below budget, and has reduced mercury and sulfur emissions by more than 90 percent.  On September 6, 2012, a consultant for the NHPUC filed a report with the NHPUC concluding that PSNH had effectively managed the Clean Air Project.

Sources and Availability of Electric Power Supply

During 2012, approximately 59 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 41 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 2013 in a similar manner.  Included in the 59 percent above are PSNH’s 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.

NATURAL GAS DISTRIBUTION SEGMENT

General

NU’s natural gas distribution segment consists of the distribution businesses of NSTAR Gas and Yankee Gas, which are engaged in the distribution of natural gas to retail customers in eastern Massachusetts and Connecticut, respectively.  

The following table shows the sources of the 2012 natural gas franchise retail revenues of NSTAR Gas and Yankee Gas based on categories of customers:

		NSTAR Gas(1)					Yankee Gas
(Thousands of Dollars, except percentages)		2012		% of Total		2012				% of Total
Residential	$	212,428		63		$		194,110		52
Commercial		110,493		33				118,124		32
Industrial		14,243		4				61,767		16
Total Retail Natural Gas Revenues	$	337,164		100%		$		374,001		100%

⁽¹⁾

NSTAR Gas’ revenue for the full-year ended December 31, 2012, has been provided for comparative purposes only.

A summary of NSTAR Gas’ and Yankee Gas’ retail firm natural gas sales and percentage changes in million cubic feet for 2012, as compared to 2011, is as follows:

		NSTAR Gas(1)						Yankee Gas
		2012		2011		Percentage Change		2012		2011		Percentage Change
Residential		18,385		20,595		(10.7)%		12,488		13,508		(7.6)%
Commercial		19,095		19,662		(2.9)%		16,567		17,175		(3.5)%
Industrial		5,205		5,226		(0.4)%		15,787		16,197		(2.5)%
Total		42,685		45,483		(6.2)%		44,842		46,880		(4.3)%
Total, Net of Special Contracts (2)								39,087		38,197		2.3 %

⁽¹⁾

NSTAR Gas’ sales data for the full-year ended December 31, 2012 compared to 2011 has been provided for comparative purposes only.

⁽²⁾

Special contracts are unique to the Yankee Gas 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 our retail electric sales, but have benefitted from lower natural gas prices and customer growth across all three customer classes.  In 2012, excluding the impact of NSTAR Gas sales, actual sales decreased, as compared to 2011, due primarily to the warmer than normal weather in the first quarter of 2012, as compared to colder than normal weather in the first quarter of 2011.  On a weather normalized basis, Yankee Gas’ 2012 sales increased due primarily to customer growth, lower cost of natural gas, the migration of interruptible customers switching to firm service rates, and the addition of gas-fired distributed generation in Yankee Gas’ service territory.

On a weather-normalized basis, the average NU combined consolidated total firm natural gas sales increased 2.7 percent in 2012, as compared to 2011, assuming NSTAR Gas had been part of the NU combined natural gas distribution system for all periods under consideration.

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NSTAR GAS COMPANY

NSTAR Gas distributes natural gas to approximately 272,000 customers in 51 communities in central and eastern Massachusetts covering 1,067 square miles.  Total throughput (sales and transportation) in 2012 was approximately 60.5 Bcf.  NSTAR 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 NSTAR Gas.  

Rates

NSTAR Gas generates revenues primarily through the sale and/or transportation of natural gas. Gas sales and transportation services are divided into two categories: firm, whereby NSTAR Gas must supply gas and/or transportation services to customers on demand; and interruptible, whereby NSTAR Gas may, generally during colder months, temporarily discontinue service to high volume commercial and industrial customers. Sales and transportation of gas to interruptible customers have no impact on NSTAR Gas’ operating income because a substantial portion of the margin for such service is returned to its firm customers as rate reductions.

The Attorney General settlement agreement that approved the Merger provided for a rate freeze through 2015 and a rate credit of $3 million to NSTAR Gas customers.

Retail natural gas delivery and supply rates are established by the DPU and are comprised of:

·

A distribution charge consisting of a fixed customer charge and a demand and/or energy charge that collects the costs of building and expanding the natural gas infrastructure to deliver natural gas supply to its customers. This also includes collection of ongoing operating costs;

·

A seasonal cost of gas adjustment clause (CGAC) that collects natural gas supply costs, pipeline and storage capacity costs, costs related to charge-offs of uncollected energy costs and working capital related costs. The CGAC is reset every six months. In addition, NSTAR Gas files interim changes to its CGAC factor when the actual costs of natural gas supply vary from projections by more than 5 percent; and

·

A local distribution adjustment clause (LDAC) that collects energy efficiency program costs, environmental costs, PAM related costs, and costs associated with the residential assistance adjustment clause.  The LDAC is reset annually and provides for the recovery of certain costs applicable to both sales and transportation customers.

NSTAR Gas purchases financial contracts based on NYMEX natural gas futures in order to reduce cash flow variability associated with the purchase price for approximately one-third of its natural gas purchases.  These purchases are made under a program approved by the Massachusetts Department of Public Utilities in 2006.  This practice attempts to minimize the impact of fluctuations in prices to NSTAR Gas’ firm gas customers.  These financial contracts do not procure gas supply.  All costs incurred or benefits realized when these contracts are settled are included in the CGAC.

Sources and Availability of Natural Gas Supply

NSTAR Gas maintains a flexible resource portfolio consisting of natural gas supply contracts, transportation contracts on interstate pipelines, market area storage and peaking services.  NSTAR Gas purchases transportation, storage, and balancing services from Tennessee Gas Pipeline Company and Algonquin Gas Transmission Company, as well as other upstream pipelines that transport gas from major producing regions in the U.S., including Gulf Coast, Mid-continent, and Appalachian Shale supplies to the final delivery points in the NSTAR Gas service area.  NSTAR Gas purchases all of its natural gas supply from a firm portfolio management contract with a term of one year, which has a maximum quantity of approximately 139,500 MMBtu/day.

In addition to the firm transportation and natural gas supplies mentioned above, NSTAR Gas utilizes contracts for underground storage and LNG facilities to meet its winter peaking demands.  The LNG facilities, described below, are located within NSTAR Gas’ distribution system and are used to liquefy and store pipeline gas during the warmer months for vaporization and use during the heating season.  During the summer injection season, excess pipeline capacity and supplies are used to deliver and store natural gas in market area underground storage facilities located in the New York and Pennsylvania region.  Stored natural gas is withdrawn during the winter season to supplement flowing pipeline supplies in order to meet firm heating demand.  NSTAR Gas has firm underground storage contracts and total storage capacity entitlements of approximately 6.6 Bcf.

A portion of the storage of natural gas supply for NSTAR Gas during the winter heating season is provided by Hopkinton, a wholly-owned subsidiary of NSTAR LLC.  The facilities consist of an LNG liquefaction and vaporization plant and three above-ground cryogenic storage tanks in Hopkinton, Massachusetts having an aggregate capacity of 3.0 Bcf of liquefied natural gas.  NSTAR Gas also has access to facilities in Acushnet, Massachusetts that include additional storage capacity of 0.5 Bcf and additional vaporization capacity.

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Based on information currently available regarding projected growth in demand and estimates of availability of future supplies of pipeline natural gas, NSTAR Gas believes that participation in planned and anticipated pipeline expansion projects will be required in order for it to meet current and future sales growth opportunities.

YANKEE GAS SERVICES COMPANY

Yankee Gas operates the largest natural gas distribution system in Connecticut as measured by number of customers (approximately 212,000 customers in 71 cities and towns), and size of service territory (2,187 square miles).  Total throughput (sales and transportation) in 2012 was approximately 51 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.  

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.

Retail natural gas delivery and supply rates are established by the PURA and are comprised of:

·

A distribution charge consisting of a fixed customer charge and a demand and/or energy charge that collects the costs of building and expanding the natural gas infrastructure to deliver natural gas supply to its customers. This also includes collection of ongoing operating costs;

·

Purchased Gas Adjustment (PGA) clause, which allows Yankee Gas to recover the costs of the procurement of natural gas for its firm and seasonal customers.  Differences between actual natural gas costs and collection amounts on August 31st of each year are deferred and then recovered or returned to customers during the following year.  Carrying charges on outstanding balances are calculated using Yankee Gas' weighted average cost of capital in accordance with the directives of the PURA; and

·

Conservation Adjustment Mechanism (CAM), which allows 100 percent recovery of conservation costs through this mechanism, with a return.  The reconciliation process produces deferrals for future recovery or refund in future customer rates each year.

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.

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 Yankee Gas 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.  Based on information currently available regarding projected growth in demand and estimates of availability of future supplies of pipeline natural gas, Yankee Gas believes that its present sources of natural gas supply are adequate to meet existing load and allow for future growth in sales.  

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ELECTRIC TRANSMISSION SEGMENT

General

CL&P, NSTAR Electric, 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 businesses of CL&P, NSTAR Electric, 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 50 basis points for joining a 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, NSTAR Electric earns between 11.64 percent and 12.64 percent on its major transmission projects, and WMECO earns 12.89 percent on the Massachusetts portion of GSRP.

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, NSTAR Electric, 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, which would be effective September 30, 2011 through December 31, 2012.  In response, the New England transmission owners filed testimony and analysis based on standard FERC methodology and precedent, demonstrating that the base ROE of 11.14 percent remained just and reasonable.

On May 3, 2012, the FERC issued an order establishing hearing and settlement procedures for the complaint.  The settlement proceedings were subsequently terminated, as the parties had reached an impasse in their efforts to reach a settlement.  In August 2012, the FERC trial judge assigned to the complaint established a schedule for the trial phase of the proceedings.  Complainant testimony supporting a base ROE of 9 percent was filed on October 1, 2012.  Additional testimony was filed on October 1, 2012 by a group of Massachusetts municipal electric companies, which recommended a base ROE of 8.2 percent.  The New England transmission owners filed testimony and analysis on November 20, 2012, demonstrating they believe that the current base ROE continues to be just and reasonable.  On January 18, 2013, the FERC trial staff filed testimony and analysis recommending a base ROE of 9.66 percent based on the midpoint of their analysis with a range of reasonableness of 6.82 percent to 12.51 percent.  The New England transmission owners criticized trial staff's analysis in responsive testimony filed on February 12, 2013.  Complainants' final testimony is due February 27, 2013.  Hearings on this complaint are scheduled for May 2013 and a trial judge’s recommended decision is due in September 2013. A decision from FERC commissioners is expected in 2014.  Refunds to customers, if any, as a result of a reduction in the NU transmission companies’ base ROE would be retroactive to October 1, 2011.

On December 27, 2012, several additional parties filed a separate complaint concerning the New England transmission owners' ROE with the FERC.  This new complaint seeks to reduce the New England transmission owner’s base transmission ROE effective January 1, 2013, and to consolidate this new complaint with the joint complaint filed on September 30, 2011.  The New England transmission owners have asked the FERC to reject this new complaint, and the FERC has not yet acted on it.

As of December 31, 2012, CL&P, NSTAR Electric, PSNH, and WMECO had approximately $2.1 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 $2.1 million.  We cannot at this time predict the ultimate outcome of this proceeding or the estimated impact on CL&P’s, NSTAR Electric’s, PSNH’s, or WMECO’s respective financial position, results of operations or cash flows.

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FERC Order No. 1000:  On October 25, 2012, ISO-NE and a majority of the New England transmission owners, including  CL&P, NSTAR Electric, PSNH and WMECO, made a comprehensive compliance filing as required by FERC Order No. 1000 and Order No. 1000-A, issued on July 21, 2011 and May 17, 2012, respectively.  The compliance filing first seeks to preserve the existing reliability planning process in New England, based on FERC’s previous approval of transmission owners’ rights under the Transmission Operating Agreement with ISO-NE, and the superiority of the current planning process, which has resulted in major transmission construction, large reliability benefits and reduction of market costs.  The filing also contains a new process for public policy transmission planning that incorporates opportunities for competing, non-incumbent projects and cost allocation among the supporting states.  In mid-January 2013, ISO-NE and the majority of New England transmission owners filed answers to various stakeholders that submitted protests to the compliance filing.  We cannot predict the final outcome or impact on us; however implementation of FERC’s goals in New England, including within our service territories, may expose us to competition for construction of transmission projects, additional regulatory considerations, and potential delay with respect to future transmission projects.

Transmission Projects

NEEWS:  GSRP, a project that involves the construction of 115 kV and 345 kV overhead lines by CL&P and WMECO from Ludlow, Massachusetts to Bloomfield, Connecticut, is the first, largest and most complicated project within the NEEWS family of projects.  The $718 million project is expected to be fully placed in service in late 2013.  As of December 31, 2012, the project was approximately 93 percent complete and we have placed $298 million in service.  

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.  All siting applications have been filed by CL&P and National Grid.  On January 2, 2013, the Connecticut Siting Council issued a final decision and order approving the Connecticut portion of the project.  Decisions in Rhode Island and Massachusetts are expected between the end of 2013 and early 2014.  The $218 million project is expected to be placed in service in late 2015.  

Included as part of NEEWS are associated reliability related projects, approximately $70 million of which have been placed in service and approximately $30 million of which are in various phases of construction and will continue to go into service through 2013.  

Through December 31, 2012, CL&P and WMECO had capitalized $212 million and $518.1 million, respectively, in costs associated with NEEWS, of which $79.4 million and $183.4 million, respectively, were capitalized in 2012.    

Greater Hartford Central Connecticut Project (GHCC):  In August 2012, ISO-NE presented its preliminary needs analysis for the GHCC to the ISO-NE Planning Advisory Committee.  The results showed severe thermal overloads and voltage violations in each of the four study areas now and in the near future.  A combination of 345 kV and 115 kV transmission solutions are being considered to address these reliability concerns and a set of preferred solutions are expected to be identified by ISO-NE in 2013.  Approximately $300 million has been included in our five-year capital program for future projects being identified to enhance these reliability concerns, which have recently been confirmed by ISO-NE.

Cape Cod Reliability Projects:  Transmission projects serving Cape Cod in the Southeastern Massachusetts (SEMA) reliability region consist of an expansion and upgrade of NSTAR Electric's existing transmission infrastructure including construction of a new 345 kV transmission line that will cross the Cape Cod Canal (The Lower SEMA Transmission Project) as well as a new 115kV transmission line and other 115kV upgrades in the center of Cape Cod.  All regulatory and licensing and permitting is complete for the Lower SEMA Transmission Project.  Construction commenced in September 2012 and is expected to be completed by mid-2013.  The total estimated construction cost for the Cape Cod projects is approximately $150 million.

Northern Pass:  Northern Pass is NPT's 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.  Effective April 10, 2012, as a result of the merger, NUTV owned 100 percent of NPT.  NPT has identified a new route in the northern-most part of the project’s route where PSNH did not own any rights of way.  We expect to file the new route with the DOE in the first quarter of 2013, and we believe that NPT will be completed in early 2017.

We estimate the costs of the Northern Pass transmission project will be approximately $1.2 billion (including capitalized AFUDC).

Greater Boston Reliability and Boston Network Improvements:  As a result of continued analysis of the transmission needs to enhance system reliability and improve capacity in eastern Massachusetts, NSTAR Electric expects to implement a series of new transmission initiatives over the next five years.  We have included $479 million in our five-year capital program related to these initiatives.

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 2012, our transmission rate base was approximately $4.2 billion, including approximately $2.2 billion at CL&P, $960 million at NSTAR Electric, $412 million at PSNH, and $620 million at WMECO.

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CAPITAL EXPENDITURES

We project capital expenditures of approximately $5 billion from 2013 through 2015.  Of the $5 billion, we expect to invest approximately $2.5 billion in our electric and natural gas distribution segments, including our generation businesses, and $2.3 billion in our electric transmission segment.  In addition, we project capital expenditures of approximately $1.6 billion from 2016 through 2017 in our electric transmission segment.

FINANCING

Our credit facilities and indentures require that NU parent and certain of its subsidiaries, including CL&P, NSTAR Electric, NSTAR Gas, NSTAR LLC, 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.    

As of December 31, 2012, approximately $730 million of NU's long-term debt will be paid in the next 12 months, consisting of $550 million for NU parent, $55 million for WMECO, and $125 million for CL&P.  

NUCLEAR DECOMMISSIONING

General

CL&P, NSTAR Electric, 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, NSTAR Electric, 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, NSTAR Electric, PSNH and WMECO in the Yankee Companies are set forth below:

		CL&P		NSTAR Electric		PSNH		WMECO		Total
CYAPC		34.5%		14.0%		5.0%		9.5%		63.0%
YAEC		24.5%		14.0%		7.0%		7.0%		52.5%
MYAPC		12.0%		4.0%		5.0%		3.0%		24.0%

Our share of the obligations to support the Yankee Companies under FERC-approved contracts is the same as the ownership percentages above.  As a result of the Merger, we consolidate the assets and obligations of CYAPC and YAEC on our consolidated balance sheet.

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 NSTAR Electric, NSTAR Gas and WMECO.

Environmental Regulation

We are subject to various federal, state and local requirements with respect to water quality, air quality, toxic substances, hazardous waste and other environmental matters.  Additionally, 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 was fully operational by 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.  The final cost of the project was approximately $421 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.  

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Water Quality Requirements

The Clean Water Act requires every “point source” discharger of pollutants into navigable waters to obtain a National Pollutant Discharge Elimination System (NPDES) permit from the 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 maintaining 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.  In its filed comments, PSNH stated that the data and studies supplied to the EPA demonstrates the fact that a closed-cycle cooling system is not warranted.  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 there would be 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.  Previously referred to as 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 two units at Merrimack Station, Newington Station and the two coal units at Schiller Station. 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 incremental controls may be required for the two coal fired units at Schiller Station.  To date, the financial impact of this potential control has not been determined.

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 2009 through 2011 are shown below.

	2011		2010		2009
Total CO2-e emissions (excludes CO2  from biomass and biofuels)	2,984		3,976		3,390

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.

Each of the states in which we do business also has Renewable Portfolio Standards (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 2012, the total RPS obligation was 13 percent and it will ultimately reach 26.5 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 typically sold to other energy suppliers or load carrying entities and the net proceeds from the sale of these RECs are credited back to customers.

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Similarly, Connecticut's RPS statute requires increasing percentages of the electricity sold to retail customers to have direct ties to renewable sources.  In 2012, the total RPS obligation was 16 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 2012, the requirement was 16.6 percent, and will ultimately reach 27.1 percent in 2020.  NSTAR Electric and WMECO are permitted to recover any costs incurred in complying with RPS from its customers through rates.  WMECO also owns renewable solar generation resources.  The RECs generated from WMECO’s solar units are sold to other energy suppliers and the proceeds from these sales are credited back to customers.

Hazardous Materials Regulations

Prior to the last quarter of the 20th 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, 2012, 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 $39.4 million, representing 77 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 former MGP sites that have a reserve balance of $34.5 million of the total $39.4 million as of December 31, 2012.

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.  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 electric and magnetic fields (EMF) associated with electric transmission and distribution facilities and appliances and wiring in buildings and homes.  Although weak health risk associations reported in some epidemiology studies remain unexplained, most researchers, as well as numerous scientific review panels, considering all significant EMF epidemiology and laboratory studies, have concluded that the available body of scientific information does not support the conclusion that EMF affects human health.

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

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” that 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 greenhouse gas 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 SF₆ 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.  These could include federal “cap and trade” laws, carbon taxes, fuel and energy taxes, or regulations requiring additional capital expenditures at our generating facilities.  We expect that any costs of these rules and regulations would be recovered from customers.

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Connecticut, New Hampshire and Massachusetts are each members of the Regional Greenhouse Gas Initiative (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 2012.

PSNH anticipates that its generating units will emit between two million and four million tons of CO₂ per year, depending on the capacity factor and the utilization of the plant, excluding emissions from the operation of PSNH’s Northern Wood Power Project.  New Hampshire legislation provides up to 1.5 million banked CO₂ allowances per year for PSNH’s fossil fueled electric generating plants during the 2012 through 2014 compliance period.  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.  Current legislation provides a portion of the RGGI auction proceeds in excess of $1 per allowance will be refunded to customers.

Because none of NU’s other subsidiaries, CL&P, NSTAR Electric or WMECO, currently owns any generating assets (other than two solar photovoltaic facilities owned by WMECO, which do not emit CO₂), none of them is required to acquire CO₂ allowances.  However, the CO₂ allowance costs borne by the generating facilities that are utilized by wholesale suppliers to satisfy energy supply requirements to CL&P, NSTAR Electric and WMECO will likely be included in the overall wholesale rates charged, which costs are then recoverable from customers.

Federal greenhouse gas legislation has stalled under the current administration.  Recently, climate change law has been discussed as an initiative that will be moved forward in the current Congress.  However, even without legislation, we can expect additional regulations from the EPA that could impact NU.  

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.  PSNH is currently involved with the early stages of relicensing at its Eastman Falls Hydro Station, which is comprised of two units, totaling 6.5 MW.

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, 2012, we employed a total of approximately 8,842 employees, excluding temporary employees, of which 1,787 were employed by CL&P, 1,204 were employed by PSNH, 348 were employed by WMECO, and 1,619 employees employed by NSTAR Electric & Gas Corporation provided services to NSTAR Electric.  Approximately 47.8 percent of our employees are members of the International Brotherhood of Electrical Workers, the Utility Workers Union of America or The United Steelworkers, and are covered by 13 collective bargaining 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, NSTAR Electric’s, PSNH's and WMECO's Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to those reports may be reviewed.  Printed copies of these reports may be obtained free of charge by writing to our Investor Relations Department at Northeast Utilities, 56 Prospect Street, Hartford, CT 06103.

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Item 1A.

Risk Factors

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 Merger may present certain material risks to the Company’s business and operations.

The Merger, described in Item 1, Business, may present certain risks to our business and operations including, among other things, risks that:

·

We may be unable to successfully integrate the businesses and workforces of NSTAR with our businesses and workforces;

 

·

Conditions, terms, obligations or restrictions relating to the Merger imposed on us by regulatory authorities may adversely affect our business and operations;

·

We may be unable to avoid potential liabilities and unforeseen increased expenses or delays associated with integration plans;

 

·

We may be unable to successfully manage the complex integration of systems, technology, networks and other assets in a manner that minimizes any adverse impact on customers, vendors, suppliers, employees and other constituencies;

·

We may experience inconsistencies in each companies’ standards, controls, procedures and policies.

Accordingly, there can be no assurance that the Merger will result in the realization of the full benefits of synergies, innovation and operational efficiencies that we currently expect, that these benefits will be achieved within the anticipated timeframe or that we will be able to fully and accurately measure any such synergies.

Cyber breaches, acts of war or terrorism, or grid disturbances could negatively impact our business.

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.

Acts of war or terrorism could target our generation, 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.  

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.  

Any such cyber breaches, acts of war or terrorism, or grid disturbances 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.

Our goodwill is valued and recorded at an amount that, if impaired and written down, could adversely affect our future operating results and total capitalization.

We have a significant amount of goodwill on our consolidated balance sheet.  The carrying value of goodwill represents the fair value of an acquired business in excess of identifiable assets and liabilities as of the acquisition date.  As of December 31, 2012, goodwill totaled $3.5 billion, of which $3.2 billion was attributable to the acquisition of NSTAR in April 2012.  Total goodwill represented approximately 38 percent of our $9.2 billion of shareholders’ equity and approximately 12 percent of our total assets of $28.3 billion.  We perform an analysis of our goodwill balances to test for impairment on an annual basis or whenever events occur or circumstances change that would indicate a potential for impairment.  A determination that goodwill is deemed to be impaired would result in a non-cash charge that could materially adversely affect our results of operations and total capitalization.

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

Severe weather, such as Tropical Storm Irene in August 2011, the October 29, 2011 snowstorm, Hurricane Sandy in October 2012, and the February 2013 blizzard, 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.  

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Tropical Storm Irene, the October 29, 2011 snowstorm, and Hurricane Sandy caused significant damage to our transmission and distribution systems.  As a result, along with previously deferred costs from other storms, we have recorded approximately $548 million (approximately $414 million at CL&P) for estimated restoration costs as regulatory assets as of December 31, 2012, 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.

NU and its utility subsidiaries are exposed to significant reputational risks, which make them vulnerable to increased regulatory oversight or other sanctions.

Because utility companies, including our electric and natural gas utility subsidiaries, have large consumer customer bases, they are subject to adverse publicity focused on the reliability of their distribution services and the speed with which they are able to respond to electric outages, natural gas leaks and similar interruptions caused by storm damage or other unanticipated events.  Adverse publicity of this nature could harm the reputations of NU and its subsidiaries, and may make state legislatures, utility commissions and other regulatory authorities less likely to view NU and its subsidiaries in a favorable light, and may cause NU and its subsidiaries to be subject to less favorable legislative and regulatory outcomes or increased regulatory oversight.  Unfavorable regulatory outcomes can include more stringent laws and regulations governing our operations, such as reliability and customer service quality standards or vegetation management requirements, as well as fines, penalties or other sanctions or requirements.  The imposition of any of the foregoing could have a material adverse effect on business, results of operations, cash flow and financial condition of NU and each of its utility subsidiaries.

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 and natural gas, 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; other unanticipated operations and maintenance expenses and liabilities; and potential claims for property damage or personal injuries beyond the scope of our insurance coverage.  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 could 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.

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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.

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.

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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.  

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, NSTAR Electric 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, NSTAR Electric 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 may increase the cost to the remaining customers of energy produced by PSNH generation assets.

The competitiveness of PSNH’s ES rates are sensitive to the cost of fuels, most notably natural gas, and customer load.  Recently, PSNH’s ES rate has been higher than competitive energy prices offered to some customers. Further increases may occur as the costs associated with the Clean Air Project are fully phased into rates. Customers remaining on PSNH’s ES rate may experience an increase in cost due to the lower base over which to recover PSNH's fixed generation costs. Any such increase may in turn cause further migration and further impact PSNH’s ES rate.  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.

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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 $222 million in 2012 and expect to make an approximate $285 million contribution in 2013.  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 commercial paper program, 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 repay borrowings from NU parent, and/or NU parent’s ability to access its commercial paper program 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 NSTAR Electric), and obligations to trade creditors.  Additionally, the Regulated companies could retain their free cash flow to fund their capital expenditures in lieu of receiving equity contributions from NU parent.  Should the Regulated companies not be able to pay dividends or repay funds due to NU parent, or if NU parent cannot access its commercial paper programs 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.

Item 1B.

Unresolved Staff Comments

We do not have any unresolved SEC staff comments.  

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Item 2. Properties
Transmission and Distribution System
As of December 31, 2012, NU and our electric operating subsidiaries owned the following:
		Electric		Electric
NU		Distribution		Transmission
Number of substations owned		557		60
Transformer capacity (in kVa)		41,504,000		17,827,000
Overhead lines (distribution in pole miles and
transmission in circuit miles)		51,988		3,835
Capacity range of overhead transmission lines (in kV)				69 to 345
Underground lines (distribution in conduit bank miles and
transmission in cable miles)		12,656		677
Capacity range of underground transmission lines (in kV)				69 to 345

			CL&P				NSTAR Electric				PSNH				WMECO
			Distribution		Transmission		Distribution		Transmission		Distribution		Transmission		Distribution		Transmission
Number of substations owned			212		19		138		20		163		13		44		8
Transformer capacity (in kVa)			18,487,000		3,117,000		11,374,000		9,575,000		7,626,000		3,868,000		4,017,000		1,267,000
Overhead lines (distribution in
	pole miles and transmission
	in circuit miles)		18,375		1,625		16,570		708		13,253		1,010		3,790		492
Capacity range of overhead
	transmission lines (in kV)				69 to 345				115 to 345				115 to 345				69 to 345
Underground lines (distribution
	in conduit bank miles and
	transmission in cable miles)		1,154		403		9,508		243		1,704		1		290		30
Capacity range of underground
	transmission lines (in kV)				69 to 345				115 to 345				115				115

									NSTAR
			NU			CL&P			Electric			PSNH			WMECO
Underground and overhead
	line transformers in service		683,514			337,727			130,787			167,523			47,477
Aggregate capacity (in kVa)			49,357,003			28,398,407			10,111,403			6,995,487			3,851,706

Electric Generating Plants

As of December 31, 2012, 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		935,343
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				1,148,800

*

Claimed capability represents winter ratings as of December 31, 2012.  The combined nameplate capacity of the generating plants is approximately 1,200 MW.

As of December 31, 2012, 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 2012.

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Natural Gas Distribution System

As of December 31, 2012, Yankee Gas owned 28 active gate stations, 203 district regulator stations, and 3,265 miles of natural gas main pipeline.  Yankee Gas also owns a 1.2 Bcf LNG facility in Waterbury, Connecticut.  

As of December 31, 2012, NSTAR Gas owned 21 active gate stations, 145 district regulator stations, and 3,185 miles of natural gas main pipeline.  NSTAR Gas and Hopkinton own a satellite vaporization plant and above ground cryogenic storage tanks.  In addition, Hopkinton owns a liquefaction and vaporization plant.  Combined, the tanks have an aggregate storage capacity equivalent to 3.5 Bcf of natural gas.

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 under Connecticut law 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.  Connecticut law prohibits an electric distribution company from owning or operating generation assets.  However, under "An Act Concerning Energy Independence," enacted in 2005, CL&P is permitted 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, under "An Act Concerning Electricity and Energy Efficiency," enacted in 2007, an electric distribution company, such as CL&P, is permitted to purchase an existing electric generating plant located in Connecticut that is offered for sale, subject to prior approval from the PURA and a determination by the PURA that such purchase is in the public interest.  Finally, Connecticut law also 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.

NSTAR ELECTRIC AND NSTAR GAS.  Through their charters, which are unlimited in time, NSTAR Electric and NSTAR Gas have the right to engage in the business of delivering and selling electricity and natural gas within their respective service territories, and have powers incidental thereto and are entitled to all the rights and privileges of and subject to the duties imposed upon electric and natural gas companies under Massachusetts laws.  The locations in public ways for electric transmission and distribution lines and gas distribution pipelines are obtained from municipal and other state authorities who, in granting these locations, act as agents for the state. In some cases the actions of these authorities are subject to appeal to the DPU.  The rights to these locations are not limited in time and are subject to the action of these authorities and the legislature.  Under Massachusetts law, with the exception of municipal-owned utilities, no other entity may provide electric or gas delivery service to retail customers within NSTAR’s service territory without the written consent of NSTAR Electric and/or NSTAR Gas. This consent must be filed with the DPU and the municipality so affected.

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 NSTAR Electric.  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.

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.  

PSNH is also subject to certain regulatory oversight by the Maine Public Utilities Commission and the Vermont Public Service Board.

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

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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 applicable to NSTAR Electric (described above) is also applicable to WMECO.

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

In 1998, the Yankee Companies (CYAPC, YAEC and MYAPC) filed separate complaints against the DOE in the Court of Federal Claims seeking monetary damages resulting from the DOE's failure to begin accepting spent nuclear fuel for disposal by January 31, 1998 pursuant to the terms of the 1983 spent fuel and high level waste disposal contracts between the Yankee Companies and the DOE (DOE Phase I Damages).  In a ruling released on October 4, 2006, the Court of Federal Claims held that the DOE was liable for damages to CYAPC for $34.2 million through 2001, YAEC for $32.9 million through 2001 and MYAPC for $75.8 million through 2002.  

In December 2006, the DOE appealed the ruling, and the Yankee Companies filed cross-appeals.  The Court of Appeals issued its decision on August 7, 2008, effectively agreeing with the trial court's findings as to the liability of the DOE but disagreeing with the method that the trial court used to calculate damages.  The Court of Appeals vacated the decision and remanded the case for new findings consistent with its decision.  

On September 7, 2010, the trial court issued its decision following remand, and judgment on the decision was entered on September 9, 2010.  The judgment 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 on November 8, 2010.  Briefs were filed and oral arguments in the appeal of the remanded case occurred on November 7, 2011.  On May 18, 2012, the U.S. Court of Appeals for the Federal Circuit issued a unanimous panel decision in favor of the Yankee Companies upholding the trial court's awards to each company in the remanded cases, and increasing YAEC damages by approximately $17 million to cover certain wet pool operating expenses.  On August 1, 2012, the DOE filed a petition asking the U.S. Court of Appeals for the Federal Circuit to reconsider its unanimous panel decision in favor of the Yankee Companies upholding the trial court's awards to each company in the remanded cases.  On September 5, 2012, the U.S. Court of Appeals for the Federal Circuit denied the DOE’s petition.  The decisions became final and non-appealable and interest on the judgments began to accrue on or about December 5, 2012, as the DOE elected not to file a petition for certiorari with the U.S. Supreme Court.  In late January 2013, the proceeds from the DOE Phase 1 Damages claim were received by CYAPC, in the amount of $39.6 million; YAEC, in the amount of $38.3 million; and MYAPC, in the amount of $81.7 million.  The funds were transferred to each Yankee Company’s respective decommissioning trust.  The final application of the proceeds for the benefit of customers of CL&P, NSTAR Electric, PSNH and WMECO will be determined following rate proceedings to be filed by the Yankee Companies at FERC in the second quarter of 2013.  Final FERC determinations are expected by the end of the third quarter of 2013.

In December 2007, the Yankee Companies each filed subsequent lawsuits against the DOE seeking recovery of actual damages incurred in the years following 2001 and 2002 related to the alleged failure of the DOE to provide for a permanent facility to store spent nuclear fuel generated in years after 2001 for CYAPC and YAEC and after 2002 for MYAPC (DOE Phase II Damages).  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 record is now closed, all post-trial briefing has been completed, and the case is awaiting the court decision.

The methodology for applying any DOE Phase II Damages that may be recovered from the DOE for the benefit of customers of CL&P, NSTAR Electric, PSNH and WMECO will be addressed in the same FERC rate proceedings.

2.

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, 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 N.H. Air Resources Council, and the N.H. Site Evaluation Committee, all of which have been denied.  PSNH believes this suit is without merit and intends to defend it vigorously.  On

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September 27, 2012, the federal court dismissed portions of CLF’s suit pertaining to the installation of activated carbon injection and the electrostatic precipitators.  An additional motion to dismiss the remaining counts is still pending.

3.

Other Legal Proceedings

For further discussion of legal proceedings, see Item 1, Business:  "- Electric Distribution Segment," "- Natural Gas Distribution Segment" and  "- Electric Transmission Segment," 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, electric and magnetic fields, 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, 2013.  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		43		Vice President, Controller and Chief Accounting Officer.
Gregory B. Butler		55		Senior Vice President, General Counsel and Secretary.
Christine M. Carmody*		50		Senior Vice President-Human Resources of NUSCO and NSTAR Electric & Gas.
James J. Judge		57		Executive Vice President and Chief Financial Officer.
Thomas J. May		65		President and Chief Executive Officer.
David R. McHale		52		Executive Vice President and Chief Administrative Officer.
Joseph R. Nolan, Jr.*		49		Senior Vice President-Corporate Relations of NUSCO and NSTAR Electric & Gas.
Leon J. Olivier		64		Executive Vice President and Chief Operating Officer.

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

Jay S. Buth.  Mr. Buth became Vice President, Controller and Chief Accounting Officer of NU, CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO, Yankee Gas, NUSCO and NSTAR Electric & Gas upon completion of the Merger.  Previously, Mr. Buth was Vice President-Accounting and Controller of NU, CL&P, PSNH, WMECO, Yankee Gas and NUSCO from June 2009 through the completion of the Merger.  From June 2006 through January 2009, Mr. Buth was the Vice President and Controller for New Jersey Resources Corporation, an energy services holding company that provides natural gas and wholesale energy services, including transportation, distribution and asset management.

Gregory B. Butler.  Mr. Butler became Senior Vice President, General Counsel and Secretary of NU and Senior Vice President and General Counsel of NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas upon completion of the Merger.  He has served as Senior Vice President and General Counsel of CL&P, PSNH, WMECO, Yankee Gas and NUSCO since March 9, 2006.  Mr. Butler was elected a Director of NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas upon completion of the Merger.  He has served as a Director of NUSCO since November 27, 2012, and of CL&P, PSNH, WMECO and Yankee Gas since April 22, 2009.  Previously Mr. Butler served as Senior Vice President and General Counsel of NU from December 1, 2005 to April 2012.  Mr. Butler became a Trustee of the NSTAR Foundation effective upon completion of the Merger.  He has served as a Director of Northeast Utilities Foundation, Inc. since December 1, 2002.  

Christine M. Carmody.  Ms. Carmody became Senior Vice President-Human Resources of NUSCO upon completion of the Merger and of CL&P, PSNH, WMECO and Yankee Gas effective November 27, 2012.  She has served as Senior Vice President-Human Resources of NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas since August 1, 2008.  Ms. Carmody was elected a Director of CL&P, PSNH, WMECO and Yankee Gas upon completion of the Merger, and of NSTAR Electric, NSTAR Gas, NUSCO and NSTAR Electric & Gas effective November 27, 2012.  Previously, Ms. Carmody served as Vice President-Organizational Effectiveness of NSTAR, NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas from June 2006 to August 2008.  Ms. Carmody became a Director of Northeast Utilities Foundation, Inc. effective upon completion of the Merger.  She has served as a Trustee of the NSTAR Foundation since August 1, 2008.

James J. Judge.  Mr. Judge became Executive Vice President and Chief Financial Officer of NU, CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO, Yankee Gas, NUSCO and NSTAR Electric & Gas upon completion of the Merger.  Mr. Judge was elected a Director of CL&P, PSNH, WMECO, Yankee Gas and NUSCO upon completion of the Merger.  He has served as a Director of NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas since September 27, 1999.  Previously, Mr. Judge served as Senior Vice President and Chief Financial Officer of NSTAR, NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas from 1999 until April 2012.  Mr. Judge became Treasurer and a Director of Northeast Utilities Foundation, Inc. effective upon completion of the Merger.  He has served as a Trustee of the NSTAR Foundation since December 12, 1995.  

Thomas J. May.  Mr. May became President and Chief Executive Officer and a Trustee of NU, Chairman and a Director of CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO and Yankee Gas, and Chairman, President and Chief Executive Officer and a Director

27

of NUSCO upon completion of the Merger.  He has been President and Chief Executive Officer of NSTAR Electric & Gas since January 1, 2002.  Mr. May has served as a Director of NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas (or their predecessor companies) since September 27, 1999.  Previously, Mr. May served as Chairman, President and Chief Executive Officer and a Trustee of NSTAR, and as Chairman, President and Chief Executive Officer of NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas until the closing of the Merger.  He served as Chairman, Chief Executive Officer and a Trustee since NSTAR was formed in 1999, and was elected President in 2002.  Mr. May became a Director of Northeast Utilities Foundation, Inc. upon completion of the Merger.  He has served as a Trustee of the NSTAR Foundation since August 18, 1987.  

David R. McHale.  Mr. McHale became Executive Vice President and Chief Administrative Officer of NU, CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO, Yankee Gas, NUSCO and NSTAR Electric & Gas upon completion of the Merger.  Mr. McHale has served as a Director of NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas since November 27, 2012, of PSNH, WMECO, Yankee Gas and NUSCO since January 1, 2005, and of CL&P since January 15, 2007.  Previously, Mr. McHale served as Executive Vice President and Chief Financial Officer of NU, CL&P, PSNH, WMECO, Yankee Gas and NUSCO from January 2009 to April 2012, and Senior Vice President and Chief Financial Officer of NU, CL&P, PSNH, WMECO, Yankee Gas and NUSCO from January 2005 to December 2008.  Mr. McHale became a Trustee of the NSTAR Foundation upon completion of the Merger.  He has served as a Director of Northeast Utilities Foundation, Inc. since January 1, 2005.

Joseph R. Nolan, Jr.  Mr. Nolan became Senior Vice President-Corporate Relations of NUSCO, NSTAR Electric & Gas, NSTAR Electric and NSTAR Gas upon completion of the Merger.  He became Senior Vice President-Corporate Relations of CL&P, PSNH, WMECO and Yankee Gas effective November 27, 2012.  Mr. Nolan was elected a Director of CL&P, PSNH, WMECO and Yankee Gas upon completion of the Merger, and of NSTAR Electric, NSTAR Gas, NUSCO and NSTAR Electric & Gas effective November 27, 2012.  Previously, Mr. Nolan served as Senior Vice President-Customer & Corporate Relations of NSTAR, NSTAR Electric, NSTAR Gas and NSTAR Electric and Gas from 2006 until the closing of the Merger.  Mr. Nolan became a Director of Northeast Utilities Foundation, Inc. upon completion of the Merger.  He has served as a Trustee of the NSTAR Foundation since October 1, 2000.  

Leon J. Olivier.  Mr. Olivier has served as Executive Vice President and Chief Operating Officer of NU and NUSCO since May 13, 2008, and of NSTAR Electric & Gas since the completion of the Merger.  He became Chief Executive Officer of NSTAR Electric and NSTAR Gas upon completion of the Merger.  Mr. Olivier has served as Chief Executive Officer of CL&P, PSNH, WMECO and Yankee Gas since January 15, 2007.  Mr. Olivier was elected a Director of NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas effective November 27, 2012, of PSNH, WMECO and Yankee Gas effective January 17, 2005, and of CL&P effective September 10, 2001.  Previously, Mr. Olivier served as Executive Vice President-Operations of NU from February 13, 2007 to May 12, 2008.  Mr. Olivier became a Trustee of the NSTAR Foundation upon completion of the Merger.  He has served as a Director of Northeast Utilities Foundation, Inc. since April 1, 2006.  

Item 4.

Mine Safety Disclosures

Not applicable.

PART II

Item 5.

Market for the Registrants' Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

(a)

Market Information and (c) Dividends

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 of our common shares and the dividends declared, for the past two years, by quarter, are shown below.

Year		Quarter		High			Low			Dividends Declared
2012		First		$	37.64		$	33.48		$	0.294
		Second			39.09			34.84			0.343
		Third			40.86			36.68			0.343
		Fourth			40.38			37.53			0.343
2011		First		$	35.13		$	31.19		$	0.275
		Second			36.47			33.31			0.275
		Third			35.87			30.02			0.275
		Fourth			36.40			30.80			0.275

Information with respect to dividend restrictions for us, CL&P, NSTAR Electric, 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.   

28

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

During 2012 and 2011, CL&P approved and paid $100.5 million and $243.2 million, respectively, of common stock dividends to NU.

Since April 10, 2012, NSTAR Electric approved and paid $159.9 million of common stock dividends to NSTAR LLC.

During 2012 and 2011, PSNH approved and paid $90.7 million and $58.8 million, respectively, of common stock dividends to NU.

During 2012 and 2011, WMECO approved and paid $9.4 million and $26.3 million, respectively, of common stock dividends to NU.

(b)

Holders

As of January 31, 2013, there were 49,487 registered common shareholders of our company on record.  As of the same date, there were a total of 332,767,098 common shares issued.

(c)

Securities Authorized for Issuance Under Equity Compensation Plans

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.

(d)

Performance Graph

As allowed under Exchange Act Rule 14c-3 (17 CFR 240.14c-3), we provide the five-year cumulative performance graph annually, accompanying our Definitive Proxy Statement pursuant to section 14(a) of the Securities Exchange Act of 1934.   

(e)

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The following table discloses purchases of shares of our common stock made by us or on our behalf for the periods shown below.

29

Item 6.				Selected Consolidated Financial Data
NU Selected Consolidated Financial Data (Unaudited)
(Thousands of Dollars, except percentages and common  share information)					2012 (a)			2011			2010			2009			2008
Balance Sheet Data:
	Property, Plant and Equipment, Net				$	16,605,010		$	10,403,065		$	9,567,726		$	8,839,965		$	8,207,876
	Total Assets					28,302,824			15,647,066			14,472,601			14,057,679			13,988,480
	Total Capitalization (b)					17,356,112			9,078,321			8,627,985			8,253,323			7,293,960
	Obligations Under Capital Leases (b)					11,071			12,358			12,236			12,873			13,397
Income Statement Data:
	Operating Revenues				$	6,273,787		$	4,465,657		$	4,898,167		$	5,439,430		$	5,800,095
	Net Income					533,077			400,513			394,107			335,592			266,387
	Net Income Attributable to Noncontrolling Interests					7,132			5,820			6,158			5,559			5,559
	Net Income Attributable to Controlling Interest				$	525,945		$	394,693		$	387,949		$	330,033		$	260,828
Common Share Data:
	Basic Earnings Per Common Share:
		Net Income Attributable to Controlling Interest			$	1.90		$	2.22		$	2.20		$	1.91		$	1.68
	Diluted Earnings Per Common Share:
		Net Income Attributable to Controlling Interest			$	1.89		$	2.22		$	2.19		$	1.91		$	1.67
	Weighted Average Common Shares Outstanding:
		Basic				277,209,819			177,410,167			176,636,086			172,567,928			155,531,846
		Diluted				277,993,631			177,804,568			176,885,387			172,717,246			155,999,240
	Dividends Declared Per Common Share				$	1.32		$	1.10		$	1.03		$	0.95		$	0.83
	Market Price - Closing (high) (c)				$	40.57		$	36.31		$	32.05		$	26.33		$	31.15
	Market Price - Closing (low) (c)				$	33.53		$	30.46		$	24.78		$	19.45		$	19.15
	Market Price - Closing (end of year) (c)				$	39.08		$	36.07		$	31.88		$	25.79		$	24.06
	Book Value Per Share (end of year)				$	29.41		$	22.65		$	21.60		$	20.37		$	19.38
	Tangible Book Value Per Share (end of year) (d)				$	18.21		$	21.03		$	19.97		$	18.74		$	17.54
	Rate of Return Earned on Average Common Equity (%) (e)					7.9			10.1			10.7			10.2			8.8
	Market-to-Book Ratio (end of year) (f)					1.3			1.6			1.5			1.3			1.2
Capitalization:
	Total Equity					53	%		44	%		44	%		44	%		41	%
	Preferred Stock, not subject to mandatory redemption					1			1			1			1			2
	Long-Term Debt (b)					46			55			55			55			57
						100	%		100	%		100	%		100	%		100	%
(a)		The 2012 results include the operations of NSTAR from the date of the merger, April 10, 2012, through December 31, 2012.
(b)		Includes portions due within one year, but excludes RRBs for Capitalization and Long-Term Debt.
(c)		Market price information reflects closing prices as reflected by the New York Stock Exchange.
(d)		Common Shareholders' Equity adjusted for goodwill and intangibles divided by total common shares outstanding.
(e)		Net Income Attributable to Controlling Interest divided by average Common Shareholders' Equity.
(f)		The closing market price divided by the book value per share.
CL&P Selected Consolidated Financial Data (Unaudited)
(Thousands of Dollars)					2012			2011			2010			2009			2008
Operating Revenues					$	2,407,449		$	2,548,387		$	2,999,102		$	3,424,538		$	3,558,361
Net Income						209,725			250,164			244,143			216,316			191,158
Cash Dividends on Common Stock						100,486			243,218			217,691			113,848			106,461
Property, Plant and Equipment, Net						6,152,959			5,827,384			5,586,504			5,340,561			5,089,124
Total Assets						9,142,088			8,791,396			8,255,192			8,364,564			8,336,118
Rate Reduction Bonds						-			-			-			195,587			378,195
Long-Term Debt (a)						2,862,790			2,583,753			2,583,102			2,582,361			2,270,414
Preferred Stock Not Subject to Mandatory Redemption						116,200			116,200			116,200			116,200			116,200
Obligations Under Capital Leases (a)						9,960			10,715			10,613			10,956			11,207
(a)		Includes portions due within one year, but excludes RRBs for Long-Term Debt.
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.

30

NU Selected Consolidated Sales Statistics
		2012 (a)			2011			2010			2009			2008
Revenues:  (Thousands)
Residential	$	2,731,951		$	2,091,270		$	2,336,078		$	2,569,278		$	2,525,635
Commercial		1,563,709			1,201,091			1,303,841			1,462,786			1,607,224
Industrial		753,974			252,878			268,598			297,854			399,753
Wholesale		357,223			350,413			506,475			445,261			545,127
Streetlighting and Railroads		40,952			35,283			42,387			33,035			38,522
Miscellaneous and Eliminations		130,137			47,485			(29,878)			128,118			24,673
Total Electric		5,577,946			3,978,420			4,427,501			4,936,332			5,140,934
Natural Gas		572,857			430,799			434,277			449,571			577,390
Total - Regulated Companies		6,150,803			4,409,219			4,861,778			5,385,903			5,718,324
Other and Eliminations		122,984			56,438			36,389			53,527			81,771
Total	$	6,273,787		$	4,465,657		$	4,898,167		$	5,439,430		$	5,800,095
Regulated Companies - Sales:  (GWh)
Residential		19,719			14,766			14,913			14,412			14,509
Commercial		24,117			14,301			14,506			14,474			14,885
Industrial		5,462			4,418			4,481			4,423			5,149
Wholesale		2,154			1,020			3,423			4,183			3,576
Streetlighting and Railroads		420			327			330			336			340
Total		51,872			34,832			37,653			37,828			38,459
Regulated Companies - Customers:  (Average)
Residential		2,711,407			1,710,342			1,704,197			1,696,756			1,700,207
Commercial		355,385			193,505			192,266			189,265			190,067
Industrial		8,279			7,083			7,150			7,207			7,342
Streetlighting, Railroads and Wholesale		15,004			5,735			6,292			7,548			4,605
Total Electric		3,090,075			1,916,665			1,909,905			1,900,776			1,902,221
Natural Gas		483,770			207,753			205,885			206,438			204,834
Total		3,573,845			2,124,418			2,115,790			2,107,214			2,107,055
(a) The 2012 results include the operations of NSTAR from the date of the merger, April 10, 2012, through December 31, 2012.

CL&P Selected Consolidated Sales Statistics
		2012			2011			2010			2009			2008
Revenues:  (Thousands)
Residential	$	1,263,845		$	1,345,290		$	1,597,754		$	1,840,750		$	1,811,845
Commercial		711,337			732,968			821,872			935,586			1,042,077
Industrial		126,165			126,783			144,463			151,839			190,723
Wholesale		214,807			278,751			441,660			386,034			484,843
Streetlighting and Railroads		21,283			25,177			32,084			22,638			28,710
Miscellaneous		70,012			39,418			(38,731)			87,691			163
Total	$	2,407,449		$	2,548,387		$	2,999,102		$	3,424,538		$	3,558,361
Sales:  (GWh)
Residential		9,978			10,092			10,196			9,848			9,913
Commercial		9,414			9,525			9,716			9,705			9,993
Industrial		2,426			2,414			2,467			2,427			2,945
Wholesale		1,155			1,592			3,040			3,434			3,637
Streetlighting and Railroads		291			284			286			286			294
Total		23,264			23,907			25,705			25,700			26,782
Customers:  (Average)
Residential		1,103,397			1,100,740			1,096,576			1,093,229			1,094,991
Commercial		104,323			103,975			103,166			101,814			102,464
Industrial		3,301			3,331			3,359			3,381			3,613
Streetlighting, Railroads and Wholesale		4,266			4,260			4,366			5,307			2,883
Total		1,215,287			1,212,306			1,207,467			1,203,731			1,203,951

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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 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 Interest of each business by the weighted average diluted NU common shares outstanding for the period.  The discussion below also includes non-GAAP financial measures referencing our 2012, 2011, and 2010 earnings and EPS excluding certain impacts related to NU's merger with NSTAR, a 2011 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, and certain non-recurring benefits from the settlement of tax issues in 2010.  We use these non-GAAP financial measures to evaluate and to provide details of earnings results by business and to more fully compare and explain our 2012, 2011 and 2010 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 Interest, we believe that the non-GAAP presentation is more representative of our financial performance and provides additional and useful information to readers of this report in analyzing historical and future performance by business.  These non-GAAP financial measures should not be considered as an alternative to reported Net Income Attributable to Controlling Interest or EPS determined in accordance with GAAP as an indicator 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 Interest are included under "Financial Condition and Business Analysis – Overview – Consolidated" in Management's Discussion and Analysis, herein.  

Financial Condition and Business Analysis

Merger with NSTAR:  

On April 10, 2012, NU and NSTAR completed our merger.  Pursuant to the terms and conditions of the Agreement and Plan of Merger, as amended (the Merger Agreement), NSTAR merged into NSTAR LLC, becoming a wholly-owned subsidiary of NU.  Unless otherwise noted, the results of NSTAR LLC and its subsidiaries, hereinafter referred to as "NSTAR," are included from the date of merger, April 10, 2012, through December 31, 2012 throughout this Management's Discussion and Analysis of Financial Condition and Results of Operations.

The transaction was structured as a merger of equals in a tax-free exchange of shares.  Pursuant to the Merger Agreement, NU issued to NSTAR shareholders 1.312 NU common shares for each issued and outstanding NSTAR common share.  As a result, NU issued approximately 136 million common shares to the NSTAR shareholders.  

Executive Summary

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

Results and Outlook:

·

We earned $525.9 million, or $1.89 per share, in 2012, compared with $394.7 million, or $2.22 per share, in 2011.  Excluding after-tax merger-related costs of $107.6 million, or $0.39 per share, we earned $633.5 million, or $2.28 per share, in 2012.  Excluding after-tax 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 2011 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 earnings results in 2012 were due primarily to the inclusion of NSTAR effective April 10, 2012 as well as higher transmission segment earnings as a result of increased investments in the transmission infrastructure.

·

The addition of NSTAR effective April 10, 2012 provided an earnings contribution of $182.9 million in 2012.  Due to the timing of the merger closing, NSTAR results for the first three months of 2012 are not reflected in NU’s 2012 results.

·

Our transmission segment earned $249.7 million, or $0.90 per share, in 2012, compared with $199.6 million, or $1.12 per share, in 2011.

·

Our electric distribution segment, which includes generation, earned $292.3 million, or $1.04 per share, in 2012, compared with $189.1 million, or $1.06 per share, in 2011.  The 2012 results include $51.1 million, or $0.19 per share, of after-tax merger settlement agreement costs and the 2011 results include the CL&P storm fund reserve.

32

·

Our natural gas distribution segment earned $30.8 million, or $0.11 per share, in 2012, compared with $31.7 million, or $0.18 per share, in 2011.  The 2012 results include $2.1 million, or $0.01 per share, of after-tax merger settlement agreement costs.

·

NU parent and other companies recorded net losses of $46.9 million, or $0.16 per share, in 2012, compared with net losses of $25.7 million, or $0.14 per share, in 2011.  The 2012 and 2011 results include $54.4 million, or $0.19 per share, and $11.3 million, or $0.06 per share, respectively, of after-tax merger costs.

·

We project capital expenditures of approximately $5 billion from 2013 through 2015.  Of the $5 billion, we expect to invest approximately $2.5 billion in our electric and natural gas distribution segments, and $2.3 billion in our electric transmission segment.  In addition, we project capital expenditures of approximately $1.6 billion from 2016 through 2017 in our electric transmission segment.

Legislative, Regulatory, Policy and Other Items:

·

On June 15, 2012, Connecticut enacted the "Enhancing Emergency Preparedness and Response Act," which is intended to enhance the state’s emergency preparedness and response in the event of natural disasters.  Among numerous provisions, the bill required the PURA to establish emergency performance standards for utilities and allows the PURA to levy penalties for failure to meet those standards.  

·

On August 1, 2012, efforts to settle a complaint filed at FERC by various New England parties concerning the base ROE earned by New England transmission owners ended without a settlement.  Soon thereafter, litigation began before a FERC trial judge.  In the fourth quarter of 2012, additional testimony and complaints were filed.  On January 18, 2013, the FERC trial staff filed testimony and analysis recommending a base ROE of 9.66 percent based on the midpoint of their analysis with a range of reasonableness of 6.82 percent to 12.51 percent.  Hearings are scheduled for May 2013, a trial judge’s ruling is due in September 2013, and a FERC decision is expected in 2014.

·

On August 1, 2012, PURA issued a final decision in the investigation of CL&P’s performance related to both Tropical Storm Irene and the October 2011 snowstorm.  The decision concluded that CL&P was deficient and inadequate in its preparation, response, and communication to both storms, and identified certain penalties that could be imposed on CL&P during its next rate case.  However, PURA will consider and weigh the extent to which CL&P has taken steps to improve current practices in future storm response in determining any potential penalties.  We believe such steps to improve current storm preparation and response practices have been successfully executed in recent storms, and that CL&P's response to these 2011 storms was prudent and consistent with industry standards, and that it is probable that it will be able to recover its deferred costs.

·

On August 3, 2012, Massachusetts Governor Patrick signed into law "An Act Relative to Competitively Priced Electricity in the Commonwealth."  The Act establishes distribution rate case requirements for both electric and natural gas utility companies, as well as limiting settlement agreements, establishes new timing on rate case proceedings, and establishes requirements for all distribution companies to enter into additional long-term renewable energy distribution contracts.  

·

On August 6, 2012, Massachusetts Governor Patrick signed into law "An Act relative to emergency service response of public utility companies" to help improve utility companies’ emergency response and communication, as well as indicate how any assessed penalties will be provided to customers.  

·

On October 29, 2012, Hurricane Sandy caused extensive damage to our electric distribution system across all three states resulting in deferred storm restoration costs of $204 million.  Approximately 1.5 million of our 3.1 million electric distribution customers were without power during or following the storm.  We believe the storm restoration costs meet the criteria for specific cost recovery in each state in which we operate and, as a result, we do not expect the storm to have a material impact on our results of operations.

·

On December 11, 2012, in separate orders issued by the DPU, NSTAR Electric and WMECO received penalties of $4.1 million and $2 million, respectively, related to the investigation into the electric utilities’ responses to Tropical Storm Irene and the October 2011 snowstorm.  The DPU stated that NSTAR Electric failed to communicate and prioritize restoration efforts in both storms and WMECO failed to prioritize restoration efforts in the October snowstorm.  On December 28, 2012, NSTAR Electric and WMECO each filed appeals arguing the DPU penalties should be vacated.  While we believe NSTAR Electric and WMECO should ultimately prevail upon appeal, we are unable to conclusively state that a favorable outcome is probable.

·

On January 16, 2013, PURA approved the $300 million plan CL&P filed on July 9, 2012 to improve the resiliency of the CL&P electric distribution system.  The plan is consistent with the terms of the Connecticut settlement agreement among NU, NSTAR, and various Connecticut state agencies.

·

On February 8, 2013, a blizzard caused damage to the electric delivery systems of CL&P and NSTAR Electric.  We have estimated that approximately 71,000 and 350,000 of CL&P and NSTAR Electric's distribution customers, respectively, were without power during or following the storm.  We believe that this storm will cost between $100 million to $120 million, with approximately 90 percent of those costs relating to NSTAR Electric.  We expect the storm restoration costs to meet the criteria for specific cost

33

recovery in each state in which we operate and, as a result, we do not expect the storm to have a material impact on our results of operations.

·

On February 19, 2013, Connecticut issued a final comprehensive energy strategy (strategy).  The strategy includes a series of policy proposals that aim to expand energy choices, including natural gas, improve environmental conditions, create clean energy jobs, and enhance the quality of life for customers in the state.  Many of the recommendations in the strategy will require actions by the PURA and potentially the legislature.

·

NPT has identified a new route in the northern-most part of the project’s route where PSNH did not own any rights of way.  We expect to file the new route with the DOE in the first quarter of 2013, and we believe that NPT will be completed in early 2017.  We estimate the costs of the Northern Pass transmission project will be approximately $1.2 billion.  

Liquidity:

·

Cash and cash equivalents totaled $45.7 million as of December 31, 2012, compared with $6.6 million as of December 31, 2011, while cash capital expenditures totaled $1.5 billion in 2012, compared with $1.1 billion in 2011.

·

Cash flows provided by operating activities in 2012 totaled $1.05 billion, compared with operating cash flows of $901.1 million in 2011 (amounts are net of RRB payments).  The improved cash flows were due primarily to the addition of NSTAR, which contributed $450.8 million of operating cash flows (net of RRB payments) to NU since the date of the merger, April 10, 2012. Offsetting the favorable NSTAR cash flow impact was an increase in storm restoration costs, NUSCO Pension Plan cash contributions, 2012 customer bill credits and NU Parent merger transaction cost payments.

·

In 2012, we issued $850 million of new long-term debt consisting of $400 million by NSTAR Electric, $300 million by NU Parent, and $150 million by WMECO.  These new issuances were used primarily to repay $716.8 million of existing long-term debt, of which $663 million matured in 2012 ($400 million at NSTAR Electric and $263 million at NU Parent) and WMECO’s tax-exempt PCRBs of $53.8 million scheduled to mature in 2028.  Additionally, CL&P remarketed $62 million of tax-exempt PCRBs in April 2012 and redeemed $116.4 million of tax-exempt PCRBs in October 2012.  As of December 31, 2012, approximately $730 million of NU's current liabilities relate to long-term debt that will be paid in the next 12 months.  

·

On March 26, 2012, CL&P entered into a five-year $300 million unsecured revolving credit facility.  The credit facility is intended to finance short-term borrowings that CL&P incurred to fund costs of restoring power following Tropical Storm Irene and the October 2011 snowstorm.  As of December 31, 2012, CL&P had $89 million in borrowings outstanding under this credit facility.

·

On July 25, 2012, NU and certain of its subsidiaries jointly entered into a five-year $1.15 billion revolving credit facility, and NSTAR Electric entered into a five-year $450 million revolving credit facility.  The new facilities expire on July 25, 2017 and will be used primarily to backstop NU’s $1.15 billion commercial paper program and NSTAR Electric’s $450 million commercial paper program.  As of December 31, 2012, NU and NSTAR Electric had $1.15 billion and $276 million in borrowings outstanding under their respective commercial paper programs.

·

On January 15, 2013, CL&P issued $400 million of 2.5 percent first mortgage bonds that will mature on January 15, 2023.  The proceeds, net of issuance costs, were used to repay CL&P’s revolving credit facility borrowings of $89 million and $305.8 million of its commercial paper program borrowings.

·

On February 5, 2013, our Board of Trustees approved a common dividend payment of $0.3675 per share, payable March 28, 2013 to shareholders of record as of March 1, 2013.  The dividend represented an increase of 7.1 percent over the $0.343 per share quarterly dividend paid in December 2012.

34

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 Interest and diluted EPS, for 2012, 2011 and 2010 is as follows:  

		For the Years Ended December 31,
		2012 (1)						2011						2010
(Millions of Dollars, Except Per Share Amounts)		Amount			Per Share			Amount			Per Share			Amount			Per Share
Net Income Attributable to Controlling Interest (GAAP)		$	525.9		$	1.89		$	394.7		$	2.22		$	387.9		$	2.19
Regulated Companies		$	626.0		$	2.25		$	438.3		$	2.46		$	384.0		$	2.16
NU Parent and Other Companies			7.5			0.03			(14.4)			(0.08)			(2.4)			(0.00)
Non-GAAP Earnings			633.5			2.28			423.9			2.38			381.6			2.16
Merger and Related Costs (after-tax)			(107.6)			(0.39)			(11.3)			(0.06)			(9.4)			(0.06)
Storm Fund Reserve			-			-			(17.9)			(0.10)			-			-
Non-Recurring Tax Settlements			-			-			-			-			15.7			0.09
Net Income Attributable to Controlling Interest (GAAP)		$	525.9		$	1.89		$	394.7		$	2.22		$	387.9		$	2.19

⁽¹⁾

Results include the operations of NSTAR from the date of merger, April 10, 2012, through December 31, 2012.  

The after-tax merger and related costs for 2012 consisted of the following charges:

·

Transaction and integration-related costs of $34 million at NU parent related to investment advisory fees, attorney fees, and consulting costs;

·

Change in control costs and other compensation costs of $13.5 million at NU parent and NSTAR;

·

A $23.6 million charge at CL&P related to the Connecticut settlement agreement, pursuant to which CL&P agreed to forego recovery of $40 million (pre-tax) of deferred storm restoration costs associated with Tropical Storm Irene and the October 2011 snowstorm;

·

A $14.8 million charge at CL&P for customer bill credits related to the Connecticut settlement agreement;

·

An aggregate of $12.8 million of charges at NSTAR Electric, NSTAR Gas, and WMECO for customer bill credits related to the Massachusetts settlement agreement; and

·

An $8.9 million charge at NU parent for the establishment of a fund to advance Connecticut energy goals related to the Connecticut settlement agreement.

Excluding the impacts of the 2012 and 2011 merger and related settlement agreement costs and the 2011 storm fund reserve, our 2012 earnings increased by $209.6 million, as compared to 2011, due primarily to the inclusion of NSTAR effective April 10, 2012, and higher transmission segment earnings as a result of increased investments in the transmission infrastructure.  On an earnings per share basis, the 2012 NSTAR earnings contribution of $182.9 million ($204.5 million in non-GAAP earnings) was partially offset by the issuance of approximately 136 million common shares to close the merger.  Offsetting these favorable earnings impacts were lower retail electric and firm natural gas sales due primarily to significantly milder weather in the first quarter of 2012, compared with the first quarter of 2011, higher pension and healthcare costs, higher depreciation and property taxes.

Regulated Companies:  Our Regulated companies consist of the electric distribution, natural gas distribution, and transmission segments.  Generation activities of PSNH and WMECO are included in our electric distribution segment.  A summary of our segment earnings for 2012, 2011 and 2010 is as follows:

		For the Years Ended December 31,
(Millions of Dollars)		2012 (1)			2011			2010
Net Income - Regulated Companies (GAAP)		$	572.8		$	420.4		$	384.0
Electric Distribution		$	343.4		$	207.0		$	173.5
Transmission			249.7			199.6			177.8
Natural Gas Distribution			32.9			31.7			32.7
Net Income - Regulated Companies (Non-GAAP)			626.0			438.3			384.0
Merger Settlement Agreement Costs (after-tax) (2)			(53.2)			-			-
Storm Fund Reserve (3)			-			(17.9)			-
Net Income - Regulated Companies (GAAP)		$	572.8		$	420.4		$	384.0

⁽¹⁾

Results include NSTAR Electric and NSTAR Gas earnings from the date of merger, April 10, 2012, through December 31, 2012.

⁽²⁾

Merger settlement agreement costs are attributable to the electric distribution segment ($51.1 million) and the natural gas distribution segment ($2.1 million).

⁽³⁾

The storm fund reserve is attributable to the electric distribution segment.

35

The higher 2012 transmission segment earnings, as compared to 2011, were due primarily to the inclusion of the NSTAR Electric transmission business and increased investments in the transmission infrastructure, including GSRP, which is under construction in western Massachusetts and northern Connecticut.  

Our electric distribution segment earned $292.3 million in 2012, compared with $189.1 million in 2011.  Excluding the impacts of the 2012 merger settlement agreement costs and the 2011 storm fund reserve, our electric distribution segment earned $343.4 million in 2012 and $207 million in 2011.  The higher earnings were due primarily to the addition of NSTAR Electric.  Excluding $10.9 million of after-tax merger settlement agreement costs, which related to customer bill credits, NSTAR Electric’s distribution business earned $150.2 million from April 10, 2012 through December 31, 2012.  For further information regarding NSTAR Electric’s earnings, see "Results of Operations – NSTAR Electric Company and Subsidiaries – Earnings Summary" in this Management's Discussion and Analysis of Financial Condition and Results of Operations.  Offsetting this favorable earnings impact was lower retail revenue, which was primarily the result of warmer than normal weather in the first quarter of 2012 as compared to colder than normal weather in the first quarter of 2011.  In addition, our electric distribution segment had higher pension and employee benefit costs, higher depreciation and property taxes, and the DPU October snowstorm penalty ($2 million pre-tax) imposed on WMECO in December 2012, partially offset by the favorable impacts of the CL&P and PSNH 2010 distribution rate case decisions.  As a result of these decisions, the CL&P rates increased effective July 1, 2011, which resulted in a full year favorable impact to earnings in 2012, while the PSNH rates increased effective July 1, 2012.

Our natural gas distribution segment earned $30.8 million in 2012, compared with $31.7 million in 2011.  Excluding the impact of the merger settlement agreement costs, our natural gas distribution segment earned $32.9 million in 2012.  The higher earnings were due primarily to the addition of NSTAR Gas’ results.  Excluding $2.1 million of after-tax merger settlement agreement costs, which related to customer bill credits, NSTAR Gas’ earnings were $6.6 million from April 10, 2012 through December 31, 2012.  Offsetting this favorable earnings impact was a decrease in total firm natural gas sales, which was primarily the result of warmer than normal weather in the first quarter of 2012 as compared to colder than normal weather in the first quarter of 2011, and higher pension expense, depreciation and property taxes.  These costs were partially offset by lower operations and maintenance costs as well as the favorable impact of the Yankee Gas 2011 rate case decision resulting in the additional increase to annualized rates effective July 1, 2012.

A summary of our retail electric GWh sales and percentage changes, as well as changes in CL&P, NSTAR Electric, PSNH and WMECO retail electric GWh sales, and our firm natural gas sales and percentage changes in million cubic feet, as well as changes in Yankee Gas and NSTAR Gas’ sales in million cubic feet, for 2012, as compared to 2011, is as follows:

		For the Year Ended December 31, 2012 Compared to 2011
		Sales (GWh)				Percentage
NU – Electric		2012 (1)		2011		Increase
Residential		19,719		14,766		33.5%
Commercial		24,117		14,301		68.6%
Industrial		5,462		4,418		23.6%
Other		420		327		28.6%
Total		49,718		33,812		47.0%

		For the Year Ended December 31, 2012 Compared to 2011
		CL&P		NSTAR Electric (2)		PSNH		WMECO
Electric		Percentage Increase/ (Decrease)		Percentage Increase/ (Decrease)		Percentage Increase/ (Decrease)		Percentage Increase/ (Decrease)
Residential		(1.1)%		0.2 %		(0.1)%		(1.0)%
Commercial		(1.2)%		(1.7)%		0.0 %		0.7 %
Industrial		0.5 %		(4.6)%		0.7 %		(0.9)%
Other		2.3 %		(12.2)%		(1.0)%		(5.7)%
Total		(0.9)%		(1.4)%		0.1 %		(0.3)%

⁽¹⁾

NU retail electric sales include the sales of NSTAR Electric from the date of merger, April 10, 2012, through December 31, 2012.

⁽²⁾

Results for NSTAR Electric represent its standalone retail electric sales for the year ended December 31, 2012 and 2011.

36

		For the Year Ended December 31, 2012 Compared to 2011
		Sales (million cubic feet)				Percentage
NU – Firm Natural Gas		2012 (1)		2011		Increase
Residential		22,535		13,508		66.8%
Commercial		27,906		17,175		62.5%
Industrial		19,453		16,197		20.1%
Total		69,894		46,880		49.1%
Total, Net of Special Contracts (2)		64,140		38,197		67.9%

		For the Year Ended December 31, 2012 Compared to 2011
		Yankee Gas		NSTAR Gas (3)
Firm Natural Gas		Percentage Increase/ (Decrease)		Percentage Decrease
Residential		(7.6)%		(10.7)%
Commercial		(3.5)%		(2.9)%
Industrial		(2.5)%		(0.4)%
Total		(4.3)%		(6.2)%
Total, Net of Special Contracts (2)		2.3 %

⁽¹⁾

NU firm natural gas sales include the sales of NSTAR Gas from the date of merger, April 10, 2012, through December 31, 2012.

⁽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.

⁽³⁾

NSTAR Gas’ sales data for the year ended December 31, 2012 compared to 2011 has been provided for comparative purposes only.

Weather and, to a lesser extent, fluctuations in fuel costs, conservation measures, and economic conditions affect sales to our customers.  Industrial sales are less sensitive to temperature variations than residential and commercial sales.  Weather impacts electric sales primarily during the summer and natural gas sales during the winter in our service territories (natural gas sales are more sensitive to temperature variations than electric sales).  Customer heating or cooling usage may not directly correlate with historical levels or with the level of degree-days that occur, particularly when weather patterns experienced are consistently colder or warmer.  In addition, our electric and natural gas businesses are sensitive to variations in daily weather, are highly influenced by New England’s seasonal weather variations, and are susceptible to damage from major storms and other natural events and disasters that could adversely affect our ability to provide energy.

Our consolidated retail electric and firm natural gas sales were higher in 2012, as compared to 2011, due to the inclusion of NSTAR Electric and NSTAR Gas sales, respectively, from the date of merger, April 10, 2012, through December 31, 2012.  

Actual retail electric sales for CL&P, NSTAR Electric and WMECO decreased in 2012, as compared to 2011, due primarily to the warmer than normal weather in the first quarter of 2012, as compared to colder than normal weather in the first quarter of 2011, while actual retail electric sales for PSNH were 0.1 percent higher than last year.  In 2012, heating degree days were 11 percent lower in Connecticut and western Massachusetts, 7 percent lower in the Boston metropolitan area, and 9 percent lower in New Hampshire, as compared to 2011.  On a weather normalized basis (based on 30-year average temperatures), the average NU combined consolidated total retail electric sales decreased 0.2 percent in 2012, as compared to 2011, assuming NSTAR Electric had been part of the NU combined electric distribution system for all periods under consideration.  We believe these decreases were due primarily to increased conservation efforts among all our customer classes and the continued installation of distributed generation at our commercial and industrial customers’ facilities.  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 annual level of baseline distribution delivery service revenues of $125.4 million that it is able to recover.  This effectively breaks the relationship between sales volume and revenues recognized.

Our firm natural gas sales are subject to many of the same influences as our retail electric sales, but have benefitted from lower natural gas prices and customer growth across all three customer classes.  In 2012, excluding the impact of NSTAR Gas sales, actual sales decreased, as compared to 2011, due primarily to the warmer than normal weather in the first quarter of 2012, as compared to colder than normal weather in the first quarter of 2011.  On a weather normalized basis, Yankee Gas’ 2012 sales increased due primarily to customer growth, lower cost of natural gas, the migration of interruptible customers switching to firm service rates, and the addition of gas-fired distributed generation in Yankee Gas’ service territory.

On a weather-normalized basis, the average NU combined consolidated total firm natural gas sales increased 2.7 percent in 2012, as compared to 2011, assuming NSTAR Gas had been part of the NU combined natural gas distribution system for all periods under consideration.

37

NU Parent and Other Companies:  NU parent and other companies (which includes our competitive businesses held by NU Enterprises and, from April 10, 2012, NSTAR LLC) recorded net losses of $46.9 million in 2012, compared with net losses of $25.7 million in 2011.  Excluding the impact of the 2012 and 2011 merger and related settlement agreement costs, NU parent and other companies recorded earnings of $7.5 million and net losses of $14.4 million, respectively.  The NU parent merger and related settlement agreement costs primarily included fees paid to investment advisors and attorneys, a charge for the establishment of a fund to advance Connecticut energy goals related to the Connecticut settlement agreement, and change in control costs and other compensation costs.  Excluding merger and related settlement agreement costs, improved results were due primarily to lower interest expense, a lower effective tax rate and the inclusion of NSTAR Communications.

Major Storm Restoration Costs:  A storm must meet certain criteria specific to each state and utility company to be declared a major storm.  Once a storm is declared major, all qualifying expenses incurred during storm restoration efforts, if deemed prudent, are deferred and recovered from customers in future periods.  In Connecticut, qualifying storm restoration costs must exceed $5 million for a storm to be declared as a major storm.  In Massachusetts, qualifying storm costs must exceed $1 million for NSTAR Electric and $300,000 for WMECO and an emergency response plan must be initiated for a storm to be declared a major storm.  In New Hampshire, (1) at least 10 percent of customers must be without power with at least 200 concurrent locations requiring repairs (trouble spots), or (2) at least 300 concurrent trouble spots must be reported for a storm to be declared a major storm.

On October 29, 2012, Hurricane Sandy caused extensive damage to our electric distribution system across all three states resulting in deferred storm restoration costs of $204 million ($159.9 million for CL&P, $27.8 million for NSTAR Electric, $12.1 million for PSNH, and $4.2 million for WMECO).  Approximately 1.5 million of our 3.1 million electric distribution customers were without power during or following the storm, with approximately 850,000 of those customers in Connecticut, approximately 472,000 in Massachusetts, and approximately 137,000 in New Hampshire.  We expect the storm restoration costs to meet the criteria for specific cost recovery in Connecticut, Massachusetts, and New Hampshire and, as a result, we do not expect the storm to have a material impact on the results of operations of CL&P, NSTAR Electric, PSNH or WMECO.  Each operating company will seek recovery of these deferred storm restoration costs through its applicable regulatory recovery process.

Liquidity

Consolidated:  Cash and cash equivalents totaled $45.7 million as of December 31, 2012, compared with $6.6 million as of December 31, 2011.  

On March 22, 2012, NU parent issued $300 million of 18-month floating rate Series D Senior Notes with a maturity date of September 20, 2013 and a coupon rate based on the three-month LIBOR rate plus a credit spread of 75 basis points, which resets every three months.  As of December 31, 2012, the interest rate on these notes was 1.059 percent.  The proceeds, net of issuance costs, were used to repay the NU parent $263 million Series A Senior Notes that matured on April 1, 2012, to repay short-term borrowings and for other general corporate purposes.  

On March 22, 2012, the FERC approved CL&P's application requesting to increase its total short-term borrowing capacity from a maximum of $450 million to a maximum of $600 million through December 31, 2013.

On March 26, 2012, CL&P entered into a five-year $300 million unsecured revolving credit facility.  The credit facility is intended to finance short-term borrowings that CL&P incurred to fund costs of restoring power following Tropical Storm Irene and the October 2011 snowstorm.  Under this new facility, CL&P can borrow either on a short-term or a long-term basis subject to any necessary regulatory approval, and may borrow at prime rates or LIBOR-based rates, plus an applicable margin based on the higher of S&P’s or Moody’s credit ratings.  As of December 31, 2012, CL&P had $89 million in borrowings outstanding under this credit facility.  The weighted-average interest rate on these borrowings as of December 31, 2012 was 3.325 percent.  

On April 2, 2012, CL&P remarketed $62 million of tax-exempt PCRBs that were subject to mandatory tender on that date.  The PCRBs, which mature on May 1, 2031, carry a coupon rate of 1.55 percent during the current three-year fixed-rate period, and are subject to mandatory tender for purchase on April 1, 2015.

On May 16, 2012, the FERC granted authorization to allow NSTAR Electric to issue total short-term debt securities in an aggregate principal amount not to exceed $655 million outstanding at any one time, effective October 23, 2012 through October 23, 2014.  

On July 25, 2012, NU, CL&P, NSTAR LLC, NSTAR Gas, PSNH, WMECO, and Yankee Gas jointly entered into a five-year $1.15 billion revolving credit facility.  The new facility replaced (1) the NSTAR LLC revolving credit facility of $175 million that served to backstop a commercial paper program utilized by NSTAR LLC and was scheduled to expire on December 31, 2012, (2) the NSTAR Gas revolving credit facility of $75 million that expired on June 8, 2012, and (3) the CL&P, PSNH, WMECO, and Yankee Gas joint $400 million and NU parent $500 million unsecured revolving credit facilities that were scheduled to expire on September 24, 2013.  The new facility expires on July 25, 2017.  We expect the new facility to be used primarily to backstop the $1.15 billion commercial paper program at NU, which commenced July 25, 2012.  As of December 31, 2012, NU had $1.15 billion in borrowings outstanding under this commercial paper program.  The weighted-average interest rate on these borrowings as of December 31, 2012 was 0.46 percent, which is generally based on money market rates.  As of December 31, 2012, there were inter-company loans of $987.5 million from NU to its subsidiaries ($405.1 million for CL&P, $63.3 million for PSNH, and $31.9 million for WMECO).  

38

On July 25, 2012, NSTAR Electric entered into a five-year $450 million revolving credit facility.  This new facility serves to backstop NSTAR Electric’s existing $450 million commercial paper program.  The new facility expires on July 25, 2017.  This new facility replaced a prior $450 million NSTAR Electric revolving credit facility that was scheduled to expire on December 31, 2012.  As of December 31, 2012, NSTAR Electric had $276 million in short-term borrowings outstanding under its commercial paper program, leaving $174 million of available borrowing capacity.  The weighted-average interest rate on these borrowings as of December 31, 2012 was 0.31 percent, which is generally based on money market rates.

On July 31, 2012, the DPU approved NSTAR Electric's application for a new two-year financing plan that provides for the issuance of long-term debt securities in an aggregate amount not to exceed $600 million prior to December 31, 2013.

On October 1, 2012, CL&P redeemed at par four different series of tax-exempt PCRBs totaling $116.4 million.  The PCRBs carried coupons that ranged from 5.85 percent to 5.95 percent and maturity dates that ranged from 2016 through 2028.  On October 1, 2012, WMECO redeemed at par $53.8 million of tax-exempt PCRBs.  The PCRBs had a maturity date of 2028 and a coupon of 5.85 percent.  

On October 4, 2012, WMECO issued at a premium $150 million of senior unsecured notes at a yield of 2.673 percent that will mature on September 15, 2021.  The senior unsecured notes are part of the same series of WMECO’s existing 3.5 percent coupon Series F Notes that were initially issued in September 2011.  As a result, the aggregate principal amount of WMECO’s outstanding Series F Notes now totals $250 million.  

On October 15, 2012, NSTAR Electric issued at a discount $400 million of 2.375 percent Debentures at a yield of 2.406 percent that will mature on October 15, 2022.  The proceeds, net of issuance costs, were used to pay $400 million of 4.875 percent Debentures that matured on October 15, 2012.

On January 15, 2013, CL&P issued $400 million of 2.5 percent first mortgage bonds that will mature on January 15, 2023.  The proceeds, net of issuance costs, were used to repay CL&P’s revolving credit facility borrowings of $89 million and $305.8 million of its commercial paper program borrowings.

NU, CL&P, NSTAR Electric, PSNH and WMECO use their available capital resources to fund their respective construction expenditures, meet debt requirements, pay costs, including storm-related costs, pay dividends and fund other corporate obligations, such as pension contributions.  The current growth in NU’s transmission construction expenditures utilizes a significant amount of cash for projects that have a long-term return on investment and recovery period.  In addition, NU’s Regulated companies operate in an environment where recovery of its electric and natural gas distribution construction expenditures takes place over an extended period of time.  This impacts the timing of the revenue stream designed to fully recover the total investment plus a return on the equity portion of the cost and related financing costs.  These factors have resulted in NU’s current liabilities exceeding current assets by approximately $1.4 billion, $268 million, $198 million and $60 million at NU, CL&P, NSTAR Electric and WMECO, respectively, as of December 31, 2012.

As of December 31, 2012, approximately $730 million of NU's current liabilities relates to long-term debt that will be paid in the next 12 months, consisting of $550 million for NU parent, $55 million for WMECO, and $125 million for CL&P.  NU, with its strong credit ratings, has several options available in the financial markets to repay or refinance these maturities with the issuance of new long-term debt.  NU, CL&P, NSTAR Electric, and WMECO will reduce their short-term borrowings with cash received from operating cash flows or with the issuance of new long-term debt, as deemed appropriate given our capital requirements and maintenance of our credit rating and profile.  Management expects the future operating cash flows of NU and its subsidiaries, along with the access to financial markets, will be sufficient to meet any future operating requirements and capital investment forecasted opportunities.

Cash flows provided by operating activities in 2012 totaled $1.05 billion, compared with operating cash flows of $901.1 million in 2011 and $832.6 million in 2010 (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 addition of NSTAR, which contributed $450.8 million of operating cash flows (net of RRB payments) to NU since the date of the merger, April 10, 2012.  Offsetting the favorable NSTAR cash flow impact was an increase of $100.6 million in cash disbursements made in 2012, compared to 2011, associated with CL&P, PSNH and WMECO storm restoration costs related to Tropical Storm Irene, the October 2011 snowstorm, and Hurricane Sandy, NUSCO Pension Plan cash contributions of $197.4 million in 2012, compared to $143.6 million in 2011, a total of $28 million of bill credits in 2012 to customers of CL&P and WMECO related to the merger, and $27 million in bill credits provided to CL&P residential customers in 2012 related to the October 2011 snowstorm.  In addition, there were approximately $42 million of NU parent transaction cost payments related to the merger.  The improved cash flows from 2010 to 2011 were due primarily to the impact of the CL&P and PSNH 2010 distribution rate case decisions that were effective July 1, 2010, 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 $143.6 million of Pension Plan cash contributions 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.  

39

A summary of the current credit ratings and outlooks by Moody's, S&P and Fitch for senior unsecured debt of NU parent, NSTAR Electric, 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+

Stable

BBB+

Stable

CL&P

A3

Stable

A

Stable

A

Stable

NSTAR Electric

A2

Stable

A-

Stable

A+

Stable

PSNH

A3

Stable

A

Stable

A

Stable

WMECO

Baa2

Stable

A-

Stable

A-

Stable

On February 14, 2013, S&P revised its criteria for rating utility first mortgage bonds, resulting in one-level upgrades of CL&P and PSNH first mortgage bonds by S&P.  

We paid common dividends of $375 million in 2012, compared with $194.6 million in 2011.  This reflects an increase of approximately 17 percent in our common dividend beginning in the second quarter of 2012 following an increase of approximately 7 percent in the first quarter of 2012.  On February 5, 2013, our Board of Trustees approved a common dividend payment of $0.3675 per share, payable March 28, 2013 to shareholders of record as of March 1, 2013.  The dividend represented an increase of 7.1 percent over the $0.343 per share quarterly dividend paid in December 2012.

In 2012, CL&P, NSTAR LLC, PSNH, and WMECO paid $100.5 million, $141 million, $90.7 million, and $9.4 million, respectively, in common dividends to NU parent.  Since April 10, 2012, NSTAR Electric and NSTAR Gas have paid $159.9 million and $12 million, respectively, in common dividends to NSTAR LLC.  NU parent made equity contributions to CL&P and WMECO of $25 million and $50 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, 2012, 2011 and 2010 is as follows:

		For the Years Ended December 31,
(Millions of Dollars)		2012 (1)			2011			2010
CL&P		$	449.1		$	424.9		$	380.3
NSTAR Electric			324.3			N/A			N/A
PSNH			203.9			241.8			296.3
WMECO			264.2			238.0			115.2
Natural Gas			148.7			98.2			82.5
NPT			33.5			24.9			7.5
Other			48.6			48.9			72.7
Total		$	1,472.3		$	1,076.7		$	954.5

⁽¹⁾

Cash capital expenditures include NSTAR from the date of merger, April 10, 2012, through December 31, 2012.  

The increase in our cash capital expenditures was the result of the addition of NSTAR’s capital expenditures, effective April 10, 2012, and higher transmission segment cash capital expenditures of $113.8 million, primarily at WMECO and CL&P.

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 $1.5 billion in 2012, $1.2 billion in 2011, and $1 billion in 2010.  These amounts included $43.1 million in 2012, $51.9 million in 2011, and $68.7 million in 2010, related to our corporate service companies, NUSCO and RRR.

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Transmission Business:  Transmission business capital expenditures increased by $189.6 million in 2012, compared with 2011, due primarily to increases at CL&P and WMECO related to the construction of GSRP and the addition of NSTAR Electric's capital expenditures since April 10, 2012.  A summary of transmission capital expenditures by company in 2012, 2011 and 2010 is as follows:  

		For the Years Ended December 31,
(Millions of Dollars)		2012 (1)			2011			2010
CL&P		$	182.5		$	128.6		$	107.2
NSTAR Electric			160.7			N/A			N/A
PSNH			55.7			68.1			49.1
WMECO			214.7			236.8			95.2
NPT			35.4			25.9			9.4
Total Transmission Segment		$	649.0		$	459.4		$	260.9

⁽¹⁾

Transmission capital expenditures include NSTAR Electric from the date of merger, April 10, 2012, through December 31, 2012.  

NEEWS:  GSRP, a project that involves the construction of 115 kV and 345 kV overhead lines by CL&P and WMECO from Ludlow, Massachusetts to Bloomfield, Connecticut, is the first, largest and most complicated project within the NEEWS family of projects.  The $718 million project is expected to be fully placed in service in late 2013.  As of December 31, 2012, the project was approximately 93 percent complete and we have placed $298 million in service.  

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.  All siting applications have been filed by CL&P and National Grid.  On January 2, 2013, the Connecticut Siting Council issued a final decision and order approving the Connecticut portion of the project.  Decisions in Rhode Island and Massachusetts are expected between the end of 2013 and early 2014.  The $218 million project is expected to be placed in service in late 2015.  

Included as part of NEEWS are associated reliability related projects, approximately $70 million of which have been placed in service and approximately $30 million of which are in various phases of construction and will continue to go into service through 2013.  

Through December 31, 2012, CL&P and WMECO had capitalized $212 million and $518.1 million, respectively, in costs associated with NEEWS, of which $79.4 million and $183.4 million, respectively, were capitalized in 2012.    

Greater Hartford Central Connecticut Project (GHCC):  In August 2012, ISO-NE presented its preliminary needs analysis for the GHCC to the ISO-NE Planning Advisory Committee.  The results showed severe thermal overloads and voltage violations in each of the four study areas now and in the near future.  A combination of 345 kV and 115 kV transmission solutions are being considered to address these reliability concerns and a set of preferred solutions are expected to be identified by ISO-NE in 2013.  Approximately $300 million has been included in our five-year capital program for future projects being identified to enhance these reliability concerns, which have recently been confirmed by ISO-NE.

Cape Cod Reliability Projects:  Transmission projects serving Cape Cod in the Southeastern Massachusetts (SEMA) reliability region consist of an expansion and upgrade of NSTAR Electric's existing transmission infrastructure including construction of a new 345 kV transmission line that will cross the Cape Cod Canal (The Lower SEMA Transmission Project) as well as a new 115kV transmission line and other 115kV upgrades in the center of Cape Cod.  All regulatory and licensing and permitting is complete for the Lower SEMA Transmission Project.  Construction commenced in September 2012 and is expected to be completed by mid-2013.  The total estimated construction cost for the Cape Cod projects is approximately $150 million.

Northern Pass:  Northern Pass is NPT's 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.  Effective April 10, 2012, as a result of the merger, NUTV owned 100 percent of NPT.  NPT has identified a new route in the northern-most part of the project’s route where PSNH did not own any rights of way.  We expect to file the new route with the DOE in the first quarter of 2013, and we believe that NPT will be completed in early 2017.  

We estimate the costs of the Northern Pass transmission project will be approximately $1.2 billion (including capitalized AFUDC).  

Greater Boston Reliability and Boston Network Improvements:  As a result of continued analysis of the transmission needs to enhance system reliability and improve capacity in eastern Massachusetts, NSTAR Electric expects to implement a series of new transmission initiatives over the next five years.  We have included $479 million in our five-year capital program related to these initiatives.

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Distribution Business:  A summary of distribution capital expenditures by company for 2012, 2011 and 2010 is as follows:

		For the Year Ended December 31,
(Millions of Dollars)		2012 (1)			2011			2010
CL&P:
Basic Business		$	69.2		$	166.6		$	126.2
Aging Infrastructure			177.8			112.3			104.0
Load Growth			65.8			59.6			75.2
Total CL&P			312.8			338.5			305.4
NSTAR Electric:
Basic Business			47.3			N/A			N/A
Aging Infrastructure			111.5			N/A			N/A
Load Growth			17.4			N/A			N/A
Total NSTAR Electric			176.2			N/A			N/A
PSNH:
Basic Business			25.3			47.7			41.2
Aging Infrastructure			50.2			25.3			19.5
Load Growth			20.2			25.8			23.1
Total PSNH			95.7			98.8			83.8
WMECO:
Basic Business			12.7			24.2			17.5
Aging Infrastructure			18.5			11.5			10.5
Load Growth			6.5			6.1			5.1
Total WMECO			37.7			41.8			33.1
Total - Electric Distribution (excluding Generation)			622.4			479.1			422.3
Total - Natural Gas			162.9			102.8			94.6
Other Distribution			0.1			1.0			2.0
Total Electric and Natural Gas			785.4			582.9			518.9
PSNH Generation:
Clean Air Project			22.0			101.1			149.7
Other			7.9			23.7			27.4
Total PSNH Generation			29.9			124.8			177.1
WMECO Generation			0.7			11.7			10.1
Total Distribution Segment		$	816.0		$	719.4		$	706.1

⁽¹⁾

Distribution capital expenditures include NSTAR Electric and NSTAR Gas from the date of merger, April 10, 2012, through December 31, 2012.  

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

Clean Air Project:  In June 2012, PSNH placed into service the last major elements of the Clean Air Project at Merrimack Station, a $421 million project that is utilizing wet scrubber technology to significantly reduce mercury and sulfur emissions from the station’s two coal units.  The scrubber has been operating since the end of September 2011 and has reduced mercury and sulfur emissions by more than 95 percent.

CL&P System Resiliency Plan:  On January 16, 2013, PURA approved the $300 million plan CL&P filed to improve the resiliency of its electric distribution system.  Consistent with the terms of the Connecticut settlement agreement, the plan includes vegetation management (both enhanced tree trimming and trimming on a shorter cycle), structural hardening (strengthening field structures through upgrades to the current structure design and material standards as well as upgrades to the poles and conductors), and electrical hardening (upgrading electrical distribution conductors and protective devices on overhead circuits).  CL&P expects to complete the plan in five years in two separate phases.  Phase 1 of the plan, which will be primarily focused on vegetation management, is estimated to cost $32 million in 2013 and $53 million in 2014.  Phase 2 of the plan is estimated to cost the remaining $215 million over the period from 2015 through 2017.

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Projected Capital Expenditures:  A summary of the projected capital expenditures for the Regulated companies' electric transmission business for 2013 through 2017 and for their distribution business for 2013 through 2015, including our corporate service companies' capital expenditures on behalf of the Regulated companies, is as follows:

	Year
(Millions of Dollars)	2013			2014			2015			2016			2017			2013-2017 Total
CL&P Transmission	$	193		$	243		$	157		$	135		$	89		$	817
NSTAR Electric Transmission		211			198			278			222			248			1,157
PSNH Transmission		92			147			102			63			15			419
WMECO Transmission		95			102			77			11			2			287
NPT		45			84			235			394			447			1,205
Total Transmission	$	636		$	774		$	849		$	825		$	801		$	3,885
Electric Distribution		670			648			635
Generation		30			30			34
Natural Gas		170			160			161
Total Distribution	$	870		$	838		$	830
Corporate Service Companies	$	84		$	62		$	55
Total	$	1,590		$	1,674		$	1,734

Actual capital expenditures could vary from the projected amounts for the companies and periods above.

FERC Regulatory Issues

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, NSTAR Electric, 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, which would be effective September 30, 2011 through December 31, 2012.  In response, the New England transmission owners filed testimony and analysis based on standard FERC methodology and precedent, demonstrating that the base ROE of 11.14 percent remained just and reasonable.

On May 3, 2012, the FERC issued an order establishing hearing and settlement procedures for the complaint.  The settlement proceedings were subsequently terminated, as the parties had reached an impasse in their efforts to reach a settlement.  In August 2012, the FERC trial judge assigned to the complaint established a schedule for the trial phase of the proceedings.  Complainant testimony supporting a base ROE of 9 percent was filed on October 1, 2012.  Additional testimony was filed on October 1, 2012 by a group of Massachusetts municipal electric companies, which recommended a base ROE of 8.2 percent.  The New England transmission owners filed testimony and analysis on November 20, 2012, demonstrating they believe that the current base ROE continues to be just and reasonable.  On January 18, 2013, the FERC trial staff filed testimony and analysis recommending a base ROE of 9.66 percent based on the midpoint of their analysis with a range of reasonableness of 6.82 percent to 12.51 percent.  Hearings on this complaint are scheduled for May 2013 and a trial judge’s recommended decision is due in September 2013.  A decision from FERC commissioners is expected in 2014.  Refunds to customers, if any, as a result of a reduction in the NU transmission companies’ base ROE would be retroactive to October 1, 2011.

On December 27, 2012, several additional parties filed a separate complaint concerning the New England transmission owners' base ROE with the FERC.  This new complaint seeks to reduce the New England transmission owner’s base transmission ROE effective January 1, 2013, and to consolidate this new complaint with the joint complaint filed on September 30, 2011.  The New England transmission owners have asked the FERC to reject this new complaint.  The FERC has not yet acted on this request.  

As of December 31, 2012, CL&P, NSTAR Electric, PSNH, and WMECO had approximately $2.1 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 $2.1 million.  We cannot at this time predict the ultimate outcome of this proceeding or the estimated impact on CL&P’s, NSTAR Electric’s, PSNH’s, or WMECO’s respective financial position, results of operations or cash flows.

FERC Order No. 1000:  On October 25, 2012, ISO-NE and a majority of the New England transmission owners, including  CL&P, NSTAR Electric, PSNH and WMECO, made a comprehensive compliance filing as required by FERC Order No. 1000 and Order No. 1000-A, issued on July 21, 2011 and May 17, 2012, respectively.  The compliance filing first seeks to preserve the existing reliability planning process in New England, based on FERC’s previous approval of transmission owners’ rights under the Transmission Operating Agreement with ISO-NE, and the superiority of the current planning process, which has resulted in major transmission construction, large reliability benefits and reduction of market costs.  The filing also contains a new process for public policy transmission planning that incorporates opportunities for competing, non-incumbent projects and cost allocation among the supporting states.  In mid-January 2013, ISO-NE and the majority of New England transmission owners filed answers to various stakeholders that submitted protests to the compliance filing.  We cannot predict the final outcome or impact on us; however implementation of FERC’s goals in New England, including within our service territories, may expose us to competition for construction of transmission projects, additional regulatory considerations, and potential delay with respect to future transmission projects.

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Regulatory Developments and Rate Matters

Federal:

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.  PSNH and other electric utility groups filed thousands of pages of comments contesting EPA’s draft permit requirements.  PSNH stated that the data and studies supplied to the EPA demonstrate the fact that a closed-cycle cooling system is not warranted.  The EPA does not have a set deadline to consider comments and to issue a final permit.  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 face similar permitting determinations.

Major Storms:

2013, 2012 and 2011 Major Storms:  On August 28, 2011, Tropical Storm Irene caused extensive damage to our distribution system.  Approximately 800,000 CL&P, PSNH and WMECO customers were without power at the peak of the outages, with approximately 670,000 of those customers in Connecticut.  Approximately 500,000 customer outages occurred on the NSTAR Electric distribution system in its aftermath.

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 CL&P, PSNH and WMECO’s 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 western 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; and the most severe in WMECO's history.  The storm also caused approximately 200,000 customer outages on the NSTAR Electric distribution system.  

On October 29, 2012, Hurricane Sandy caused extensive damage to our electric distribution system across all three states.  Approximately 1.5 million of our 3.1 million electric distribution customers were without power during or following the storm, with approximately 850,000 of those customers in Connecticut, approximately 472,000 in Massachusetts, and approximately 137,000 in New Hampshire.

As of December 31, 2012, deferred storm restoration costs related to these major storms that are deferred for future recovery at CL&P, NSTAR Electric, PSNH, and WMECO were as follows:

(Millions of Dollars)		Tropical Storm Irene		October Snowstorm		Hurricane Sandy		Total
CL&P		$ 108.6		$ 173.0		$ 159.9		$ 441.5
NSTAR Electric		21.9		13.9		27.8		63.6
PSNH		6.8		15.5		12.1		34.4
WMECO		3.2		23.3		4.2		30.7
Total		$ 140.5		$ 225.7		$ 204.0		$ 570.2

On February 8, 2013, a blizzard caused damage to the electric delivery systems of CL&P and NSTAR Electric.  We have estimated that approximately 71,000 and 350,000 of CL&P and NSTAR Electric's distribution customers, respectively, were without power during or following the storm.  We believe that this storm will cost between $100 million to $120 million, with approximately 90 percent of those costs relating to NSTAR Electric.  Management expects the costs to meet the criteria for specific cost recovery in Connecticut and Massachusetts and, as a result, does not expect the storm to have a material impact on the results of operations of CL&P or NSTAR Electric.  Each operating company will seek recovery of these anticipated deferred storm costs through its applicable regulatory recovery process.

The magnitude of these storms’ restoration costs and damages met the criteria for cost deferral in Connecticut, New Hampshire, and Massachusetts and as a result, the storms had no material impact on the results of operations of CL&P, NSTAR Electric, PSNH and WMECO.  As covered by the Connecticut settlement agreement, CL&P agreed to forego recovery of $40 million (pre-tax) of the deferred storm restoration costs associated with Tropical Storm Irene and the October 2011 snowstorm.  We believe our response to all storms was prudent and therefore we believe it is probable that CL&P, NSTAR Electric, PSNH and WMECO will be allowed to recover the deferred storm restoration costs.  Each operating company will seek recovery of its estimated deferred storm restoration costs through its applicable regulatory recovery process.  

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Connecticut:

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.  Effective January 1, 2013, the PURA approved a decrease to CL&P’s total average SS rate of approximately 4.5 percent and an increase to CL&P’s total average LRS rate of approximately 15.3 percent.  The energy supply portion of the total average SS rate decreased from 8.443 cents per kWh to 7.68 cents per kWh while the energy supply portion of the total average LRS rate increased from 6.06 cents per kWh to 7.679 cents per kWh.  These changes were due primarily to the market conditions for the procurement of energy.  CL&P is fully recovering from customers the costs of its SS and LRS services.

CTA and SBC Reconciliation:  On December 12, 2012, PURA approved CL&P’s 2011 CTA and SBC reconciliation as filed on March 30, 2012, which compared CTA and SBC revenues to revenue requirements.  Prospectively, PURA has required CL&P to include only the billed revenues when filing its future CTA and SBC reconciliations.  This adjustment to the filing will have no impact to CL&P’s financial position, results of operations or cash flows.  CL&P will file its 2012 CTA and SBC reconciliation in March 2013.

FMCC Filing:  Semi-annually, CL&P files with PURA its FMCC filing, which reconciles actual FMCC revenues and charges and GSC revenues and expenses, for the six-month period under consideration.  The filing identifies a total net over or under recovery, which includes the remaining uncollected or non-refunded portions from previous filings.  On February 22, 2013, CL&P filed with PURA its semi-annual FMCC filing for the period July 1, 2012 through December 31, 2012.  This filing also reflects the January 1, 2012 through June 30, 2012 amounts as approved by PURA in the previous semi-annual filing.  The filing identified a total net over recovery of $7.9 million for the period.  PURA has not established a schedule for review of this filing, however, 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.

Conservation Adjustment Mechanism:  On November 7, 2012, CL&P filed an application with PURA for the establishment of a CAM.  The CAM would collect the costs associated with expanded energy efficiency programs beyond that already collected through the statutory charge and the revenues lost because of the expanded energy efficiency programs.

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.  At the time, CL&P had 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 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.  In lieu of a decision from the Connecticut Supreme Court, the parties involved, including CL&P, agreed to resolve all issues associated with the 2004, 2005 and 2006 procurement fee and settle the matter.  On October 2, 2012, the PURA issued a decision approving the parties’ joint settlement agreement.  As a result of the joint settlement agreement, CL&P is allowed to retain $11.5 million of procurement incentives for the years 2004, 2005 and 2006.

PURA Storm Review:  On August 1, 2012, PURA issued a final decision in the investigation of CL&P’s performance related to both Tropical Storm Irene and the October 2011 snowstorm.  The decision concluded that CL&P was deficient and inadequate in its preparation, response, and communication in both storms, and identified certain penalties that could be imposed on CL&P during its next rate case, including a reduction in allowed regulatory ROE and the disallowance of certain deferred storm restoration costs.  However, PURA will consider and weigh the extent to which CL&P has taken steps in its restructuring of storm management and the establishment of new practices for execution in future storm response in determining any potential penalties.  We believe such steps to improve current storm preparation and response practices have been successfully executed in recent storms.  At this time, we cannot estimate the impact on CL&P’s financial position, results of operations or cash flows.  We continue to believe that CL&P's response to these 2011 storms was prudent and consistent with industry standards, and that it is probable that it will be able to recover its deferred costs.

System Resiliency Plan:  On January 16, 2013, PURA approved the $300 million plan CL&P filed on July 9, 2012 to improve the resiliency of the CL&P electric distribution system.  For further information, see "Business Development and Capital Expenditures – Distribution Business" in this Management's Discussion and Analysis.

PURA Establishment of Performance Standards for Electric and Gas Companies Docket:  On November 1, 2012, PURA issued its report to the Connecticut legislature concerning specific standards for acceptable performance for electric and gas companies under emergency situations.  Emergency situations were defined as more than 10 percent of electric customers and 1 percent of gas customers being without service for more than 48 consecutive hours.  The performance standards the electric and gas companies, including CL&P and Yankee Gas, were directed to incorporate into their emergency response plans (ERP), and implement into their operations, include (1) the National Incident Management System and utilization of the Incident Command System, (2) scalable action and trigger points for various levels of outages, (3) a damage assessment model and mode of delivery, (4) guidelines for setting

45

restoration priorities, (5) a description of how the utility will insure safety for the public and utility’s employees, (6) a storm matrix for various storm levels that identify the mutual aid and/or contractor resources necessary to restore customers within a prescribed period of time, (7) written communication protocols for timely and accurate information exchange between the EDC and a pre-determined list of state and local agencies and other utilities during emergency events, (8) training and drills/exercises to be conducted annually on a local level and every 3 years on a state-wide level, and (9) a written report to be filed with PURA within 60 days after the end of an event in order to assist in lessons learned and continual improvement.  Electric and gas companies, including CL&P and Yankee Gas, will be subject to penalties levied by PURA for failure to meet these performance standards.

Massachusetts:

Basic Service Rates:  Electric distribution companies in Massachusetts are required to obtain and resell power to retail customers through Basic Service for those customers who choose not to buy energy from a competitive energy supplier.  Basic Service rates are reset every six months (every three months for large commercial and industrial customers).  The price of Basic Service is intended to reflect the average competitive market price for electric power.  NSTAR Electric and WMECO fully recover their energy costs through DPU-approved regulatory rate mechanisms.

DPU Storm Penalties:  On December 11, 2012, in separate orders issued by the DPU, NSTAR Electric and WMECO received penalties related to the investigation into the electric utilities’ responses to Tropical Storm Irene and the October 2011 snowstorm.  The DPU ordered penalties of $4.1 million and $2 million for NSTAR Electric and WMECO, respectively, stating that NSTAR Electric failed to communicate and prioritize restoration efforts in both storms and WMECO failed to prioritize restoration efforts in the October snowstorm.  These penalties were ordered to be assessed in the form of customer credits in 2013.  On December 28, 2012, NSTAR Electric and WMECO each filed appeals with the SJC arguing the DPU penalties should be vacated.  In their filings, NSTAR Electric and WMECO stated that the DPU’s decision to assess the penalties was in error as the assessments were arbitrary and not supported by substantial evidence.  While we believe that NSTAR Electric and WMECO should ultimately prevail upon appeal, we are unable to conclusively state that a favorable outcome is probable.  Therefore, NSTAR Electric and WMECO recorded $4.1 million and $2 million, respectively, in pre-tax penalty charges as of December 31, 2012.

DPU Safety and Reliability Programs (CPSL):  Since 2006, NSTAR Electric has been recovering incremental costs related to the Double Pole Inspection, Replacement/Restoration and Transfer Program and the Underground Electric Safety Program, which included stray-voltage remediation, manhole inspections, repairs, and upgrades, in accordance with this DPU approved program.  Recovery of these CPSL costs is subject to review and approval by the DPU through a rate-reconciling mechanism.  From 2006 through December 31, 2011, cumulative costs associated with the CPSL program resulted in an incremental revenue requirement to customers of approximately $83 million.  These amounts included incremental operations and maintenance costs and the related revenue requirement for specific capital investments relative to the CPSL programs.

On May 28, 2010, the DPU issued an order on NSTAR Electric’s 2006 CPSL cost recovery filing (the May 2010 Order).  The May 2010 Order was the basis NSTAR Electric used for recognizing revenue for the CPSL programs.  On October 8, 2010, NSTAR Electric submitted a Compliance Filing with the DPU reconciling the cumulative CPSL program activity for the periods 2006 through 2009 in order to determine a proposed rate adjustment effective on January 1, 2011.  The DPU allowed the proposed rates for the CPSL programs to go into effect on that date, subject to final reconciliation of CPSL program costs through a future DPU proceeding.  NSTAR Electric updated the October 2010 filing with final activity through 2011 in February 2013.  

NSTAR Electric cannot predict the timing of any subsequent DPU order related to its CPSL filings for the period 2006 through 2011.  Therefore, NSTAR Electric continued to record its 2006 through 2011 revenues under the CPSL programs based on the May 2010 Order.  While we do not believe that any subsequent DPU order would result in revenue recognition that is materially different than the amounts already recognized, it is reasonably possible that an order could have a material impact on NSTAR Electric’s results of operations, financial position and cash flows.

The April 4, 2012 DPU-approved comprehensive merger settlement agreement with the Massachusetts Attorney General concerning the Merger stipulates that NSTAR Electric must incur a revenue requirement of at least $15 million per year for 2012 through 2015 in order to continue these programs.  CPSL revenues will end once NSTAR Electric has recovered its 2015-related CPSL costs.  Realization of these revenues is subject to maintaining certain performance metrics over the four-year period and DPU approval.  As of December 31, 2012, NSTAR Electric was in compliance with the performance metrics and has recognized the entire $15 million revenue requirement during 2012, which we believe is probable of approval from the DPU.

Basic Service Bad Debt Adder:  In accordance with a generic DPU order, electric utilities in Massachusetts recover the energy-related portion of bad debt costs in their Basic Service rates.  On February 7, 2007, NSTAR Electric filed its 2006 Basic Service reconciliation with the DPU proposing an adjustment related to the increase of its Basic Service bad debt charge-offs.  On June 28, 2007, the DPU issued an order approving the implementation of a revised Basic Service rate.  However, the DPU instructed NSTAR Electric to reduce distribution rates by an amount equal to the increase in its Basic Service bad debt charge-offs.  This adjustment to NSTAR Electric’s distribution rates would eliminate the fully reconciling nature of the Basic Service bad debt adder.

NSTAR Electric deferred the unrecovered costs associated with energy-related bad debt as a regulatory asset, which totaled approximately $34 million as of December 31, 2011, as NSTAR Electric had concluded that these costs were probable of recovery in future rates.  On June 18, 2010, NSTAR Electric filed an appeal of the DPU’s order with the SJC, which was heard by the SJC in

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December 2011.  On April 11, 2012, the SJC issued a procedural order waiving its standing 130-day rule for issuance of an order on the matter.  Due to the delay, NSTAR Electric concluded that while an ultimate outcome on the matter in its favor remained more likely than not, it could no longer be deemed probable.  As a result, NSTAR Electric recognized a reserve of $28 million ($17 million after-tax) as a charge to Operations and Maintenance in the first quarter of 2012 to reserve the related regulatory asset on its balance sheet.

On June 4, 2012, the SJC vacated the DPU's June 28, 2007 order and remanded the matter to the DPU for a "statement of reasons, including subsidiary findings, of its conclusion of law and relevant facts."  The continued uncertainty of the outcome of the DPU’s proceeding leaves NU and NSTAR Electric unable to conclude that it is probable that the previously reserved amount will ultimately be recovered and therefore NSTAR Electric will continue to maintain a reserve on this amount until the ultimate outcome is determined by the DPU.

Renewable Energy Contract:  On November 26, 2012, the DPU approved NSTAR Electric’s renewable energy contract with Cape Wind Associates, LLC, which has a term of 15 years, to purchase 129 MW of renewable energy from an offshore wind energy facility once it is constructed and placed in service.

New Hampshire:

Distribution Rates:  In 2012, PSNH filed for a step increase and a change in its accrual to its major storm reserve fund.  On June 27, 2012, the NHPUC approved an annualized distribution rate increase of $7.1 million, effective July 1, 2012, for the step increase.  Additionally, PSNH was allowed a $3.5 million increase in the annual accrual to its major storm reserve fund effective July 1, 2012.  

ES and SCRC Rates:  On December 12, 2012, PSNH filed an updated request to its September 28, 2012 preliminary request with the NHPUC to adjust its ES and SCRC rates effective with services rendered on and after January 1, 2013.  PSNH’s updated request proposed to increase the current ES billing rate to reflect projected costs for 2013 and to decrease the current SCRC billing rate to reflect the full amortization of RRBs at the end of April 2013.  The net impact to customers that purchase energy from PSNH is a net increase of 1.287 cents per kWh in total rates.  On December 28, 2012, the NHPUC approved the request.

ES Temporary Rates:  On November 22, 2011, the NHPUC opened a docket to review the Clean Air Project including the establishment of temporary rates for near-term recovery of Clean Air Project costs, a prudence review of PSNH's overall construction program, and establishment of permanent rates for recovery of prudently incurred Clean Air Project costs.  On April 10, 2012, the NHPUC issued an order authorizing temporary rates, effective April 16, 2012, which recover a significant portion of the Clean Air Project costs, including a return on equity.  The docket will continue for a comprehensive prudence review of the Clean Air Project and the establishment of a permanent rate.  The temporary rates will remain in effect until a permanent rate allowing full recovery of all prudently incurred costs is approved.  At that time, the NHPUC will reconcile recoveries collected under the temporary rates with final approved rates.   

The NHPUC had suspended the procedural schedule for the prudence review pending issuance of an order on preliminary substantive and procedural matters.  On December 24, 2012, the NHPUC issued an Order ruling on the requirement of PSNH to respond to a number of discovery requests that PSNH had objected to, and deciding that PSNH had legal authority to seek a variance from the Clean Air Project Mandate in the event of "economic infeasibility."  PSNH has sought rehearing of that December 24^th Order.  The NHPUC is considering PSNH’s rehearing request, and has again suspended the procedural schedule.  PSNH expects hearings to commence in this proceeding on or about the third quarter of 2013.  We cannot predict the outcome of the Clean Air Project prudence review, but believe all costs were incurred appropriately and are probable of recovery.

ES Filing:  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 April 27, 2012, PSNH filed its proposed Alternative Default Energy Rate that addresses customer migration, with an effective date of July 1, 2012.  The proposal, if implemented, would result in no impact to earnings and would allow for an increased contribution to fixed costs for all ES customers.  On May 24, 2012, the NHPUC suspended the effectiveness of the proposed rates pending hearings.  Hearings were held on October and November 2012 and a final decision is expected in the first quarter of 2013.

Default ES Rate:  On January 18, 2013, the NHPUC opened a docket to investigate market conditions affecting PSNH’s energy service rate, how PSNH will maintain just and reasonable rates in light of those conditions, and any impact of PSNH’s generation ownership on the New Hampshire competitive electric market.  The NHPUC noted that this proceeding will not undertake to determine whether continued ownership and operation of generation is in PSNH’s retail customers’ economic interest.  No schedule or procedural process has been established for this proceeding.

Legislative and Policy Matters

Federal:  

Moving Ahead for Progress in the 21st Century Act:  On July 6, 2012, President Obama signed the "Moving Ahead for Progress in the 21^st Century" Act, which included provisions that impact how minimum required contributions to qualified pension plans are calculated.  The legislation allows NU to use a higher discount rate to calculate the plan's funded target liability, resulting in lower cash contribution

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requirements.  We have evaluated the impact of the legislation on future cash contributions to the NUSCO and NSTAR Pension Plans and will continue to follow our policy to fund these plans on an annual basis that is at least equal to the amounts that will satisfy the federal requirements, as amended by this legislation.

2013 Legislation:  On January 2, 2013, President Obama signed into law the "American Taxpayer Relief Act of 2012," which extends certain tax rules allowing the accelerated deduction of depreciation from the "American Recovery and Reinvestment Act of 2009" to businesses through 2013.  This extended stimulus is expected to provide us with cash flow benefits of between $200 million to $250 million in 2013 and 2014.  We are still evaluating the other provisions of this legislation, which are not expected to have a significant impact on our financial position, results of operations or cash flows.  

Connecticut:

Enhancing Emergency Preparedness and Response Act:  On June 15, 2012, Connecticut enacted the "Enhancing Emergency Preparedness and Response Act," which is intended to enhance the state’s emergency preparedness and response in the event of natural disasters.  Among numerous provisions, the bill requires the PURA to establish emergency performance standards for utilities and allows the PURA to levy penalties of up to 2.5 percent of annual distribution revenues for failure to meet performance standards.  For further information, see "Regulatory Developments and Rate Matters – Connecticut" in this Management's Discussion and Analysis.

Comprehensive Energy Strategy:  On February 19, 2013, Connecticut issued a final comprehensive energy strategy (strategy).  The strategy includes a series of policy proposals that aim to expand energy choices, improve environmental conditions, create clean energy jobs, and enhance the quality of life for customers in the state.  It also includes a seven-year initiative for expanding natural gas use with a goal of providing nearly 300,000 utility customers with access to natural gas, building an estimated 900 miles of new natural gas mains, and estimates of capital costs to be incurred by natural gas utility companies to connect customers on or near natural gas mains.  In addition to natural gas expansion, the strategy also calls for a significant expansion of energy efficiency investment in Connecticut, a review of Connecticut’s Renewable Energy Portfolio Standards (possibly including Canadian hydroelectric generation as a qualifying resource), and investment in alternative fuel transportation.  Many of the recommendations in the strategy will require actions by the PURA and potentially the legislature.  As such, the full impact of the strategy is not reflected in our electric distribution, transmission or natural gas business segments five-year capital program.

Massachusetts:

Energy Act:  On August 3, 2012, Massachusetts Governor Patrick signed into law "An Act Relative to Competitively Priced Electricity in the Commonwealth" (Energy Act).  The more significant provisions of the Energy Act impacting our Massachusetts operating companies and customers are as follows:

·

Requires electric utility companies to file a distribution rate case every five years and natural gas companies every 10 years, limiting those companies to one settlement agreement in a 10-year period;

·

Extends the distribution rate case review period to 10 months;

·

Requires all distribution companies, through a competitive bidding process and subject to DPU approval, to enter into additional cost-effective long-term renewable energy contracts with terms of 10 to 20 years.  Electric utility companies will be allowed a remuneration of 2.75 percent of the annual payments under the contracts to compensate them for accepting the financial obligation of the contracts;

·

Orders the DPU to open a proceeding for each electric and natural gas utility company to identify reconciliation factors and establish cost recovery from each customer class under cost-based criteria; and

·

Allows electric utility or distribution companies to construct, own and operate no more than 25 MW of solar generation facilities, a decrease from the initial allowance of up to 50 MW of solar generation facilities, subject to DPU approval, and requires that construction be completed prior to June 30, 2015.

Storm Response Act:  On August 6, 2012, Massachusetts Governor Patrick signed into law "an act relative to emergency service response of public utility companies" (Storm Response Act), to help improve utility companies’ emergency response and communication.  The Storm Response Act codified certain emergency response plan (ERP) provisions, which require utility companies to submit an annual ERP for DPU review and approval.  The ERP will describe storm or emergency responsibilities of utility company employees, customer communication processes and systems, and deployment of resources.  The Storm Response Act also requires that all future financial penalties levied on utility companies by the DPU for violation of DPU storm and emergency service performance standards will be provided to customers, and that transmission companies performing vegetation management activities within a right-of-way comply with certain notification provisions.  We are currently evaluating this act and its potential impacts on NSTAR Electric’s, NSTAR Gas’ and WMECO’s financial positions, results of operations and cash flows; however, we do not expect the impacts to be material.  

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 the Audit Committee of our Board of Trustees significant matters relating to critical accounting policies.  Our critical accounting policies are

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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 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 3, "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.  Because customers are billed throughout the month based on pre-determined cycles rather than on a calendar month basis, an estimate of electricity or natural gas delivered to customers for which the customers have not yet been billed is calculated as of the balance sheet date.

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 sales 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 unbilled sales to the respective customer classes, then applying an estimated rate by customer class to those 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 1K, "Summary of Significant Accounting Policies - Revenues," to the consolidated financial statements.  

Pension and PBOP:  NUSCO and NSTAR Electric sponsor pension plans covering certain of our employees.  In addition, NUSCO and NSTAR Electric & Gas sponsor PBOP plans 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, 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 benefit expense (excluding SERP) for the Pension Plans was $234.9 million, $127.7 million and $80.4 million for the years ended December 31, 2012, 2011 and 2010, respectively.  The pre-tax net periodic benefit expense for the PBOP Plans was $72.3 million, $43.6 million and $41.6 million for the years ended December 31, 2012, 2011 and 2010, respectively.  NSTAR pension and PBOP expense is included in NU consolidated amounts from the date of the merger, April 10, 2012, through December 31, 2012.

We develop key assumptions for purposes of measuring liabilities as of December 31^st 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.  For the year ended December 31, 2012, our aggregate expected long-term rate of return assumptions of 8.25 percent on the NUSCO Pension and PBOP Plans and 7.30 percent for the NSTAR Pension and PBOP Plans were used to determine our Pension and PBOP expense.  For the forecasted 2013 pension

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and PBOP expense, our expected long-term rate of return of 8.25 percent for all plans was used, which reflects a change in target asset allocations within both the NUSCO and NSTAR Pension and PBOP Plans.

Discount Rate:  Payment obligations related to the Pension Plans and PBOP Plans are discounted at interest rates applicable to the expected timing of each plan’s 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 4.24 percent for the NUSCO Pension Plan, 4.13 percent for the NSTAR Pension Plan, 4.04 percent for the NUSCO PBOP Plans and 4.35 percent for the NSTAR PBOP Plan as of December 31, 2012.

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, 2012 and 2011 for the NUSCO Pension Plan and 4 percent for the NSTAR Pension Plan as of December 31, 2012, which reflects our current expectation of future salary increases, including consideration of the levels of increases built into collective bargaining agreements.  

Actuarial Determination of Expense:  Pension and PBOP expense is determined by our actuaries and consists 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 for the NUSCO Pension and PBOP Plans by applying our assumed rate of return to a four-year rolling average of plan asset 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, 2012, investment gains and losses that remain to be reflected in the calculation of plan assets over the next four years were losses of $224.4 million and gains of $0.7 million for the NUSCO Pension Plan and PBOP Plans, 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.  As of December 31, 2012, the net unrecognized actuarial losses on the NUSCO Pension and PBOP Plan liabilities were $1.1 billion and $176.5 million, respectively.  For the NSTAR Pension and PBOP Plans, the entire difference between the actual and expected return on plan assets as of December 31, 2012 is immediately reflected as a component of unrecognized actuarial gains or losses to be amortized over the estimated average future service period of the employees.  As of December 31, 2012, the net unrecognized actuarial losses on the NSTAR Pension and PBOP Plan liabilities were approximately $724 million and $176 million, respectively.

Forecasted Expenses and Expected Contributions:  Based upon the assumptions and methodologies discussed above, we estimate that the combined expense for the Pension and PBOP Plans will be $241 million and $46 million, respectively, in 2013.  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 NUSCO PBOP Plans at the amount of PBOP expense excluding any curtailments and the NSTAR PBOP Plan at an amount that approximates benefit payments.  NU's policy is to fund the Pension Plans annually in an amount at least equal to an amount that will satisfy the federal requirements. NU made contributions to the NUSCO Pension Plan totaling $197.4 million in 2012, of which $87.7 million was contributed by PSNH.  NSTAR Electric contributed $25 million to the NSTAR Pension Plan in 2012.  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 94.8 percent and 100.2 percent as of January 1, 2012 for the NUSCO Pension Plan and NSTAR Pension Plan, respectively.  We currently estimate that aggregate contributions of $285 million to the Pension Plans will be made in 2013.  Fluctuations in the average discount rate used to calculate expected contributions to the Pension Plans can have a significant impact on the amounts.  

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

		Pension Plan Cost						PBOP Plan Cost
(Millions of Dollars)		As of December 31,
Assumption Change			2012			2011		2012			2011
NU Consolidated
Lower long-term rate of return		$	15.0		$	10.3		$	3.1		$	1.3
Lower discount rate		$	22.0		$	14.2		$	6.7		$	2.3
Higher compensation increase		$	10.4		$	6.5			N/A			N/A
NSTAR Plans
Lower long-term rate of return		$	4.8			N/A		$	1.7			N/A
Lower discount rate		$	6.8			N/A		$	4.1			N/A
Higher compensation increase		$	3.6			N/A			N/A			N/A

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Changes in pension and PBOP costs would not impact net income for the NSTAR Plans as their expenses are fully recovered in rates, which reconcile each year relative to the change in costs.

Health Care Cost:  For the NUSCO PBOP Plans, the health care cost trend rate assumption is 7 percent, subsequently decreasing by 50 basis points per year to an ultimate rate of 5 percent in 2017.  For the NSTAR PBOP Plan, the health care cost trend rate is 7.10 percent, subsequently decreasing to an ultimate rate of 4.50 percent in 2024.  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 $8.9 million in 2012, with a $126.5 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:  We recorded approximately $3.2 billion of goodwill associated with the merger with NSTAR on April 10, 2012.  NU had existing goodwill of $0.3 billion related to Yankee Gas.  NU has identified its reporting units for purposes of allocating goodwill as Electric Distribution, Electric Transmission and Natural Gas Distribution.  Our reporting units for purposes of allocating and testing goodwill are consistent with our operating segments underlying our reportable segments.  Electric Distribution and Electric Transmission reporting units include values for the respective components of CL&P, NSTAR Electric, PSNH and WMECO.  The Natural Gas reporting unit includes the carrying values of NSTAR Gas and Yankee Gas.  

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 carrying 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 performed an impairment analysis as of October 1, 2012 for the Electric Distribution, Electric Transmission and Natural Gas Distribution reporting units.  We determined that the fair value of the reporting units substantially exceeded the carrying values and no impairment exists.  In performing the evaluation, we estimated the fair values of the reporting units and compared them to the carrying values of the reporting units, including goodwill.  We estimated the fair values of the reporting units using a discounted cash flow approach and a market approach that analyzed company information and market transactions.  This evaluation requires the input of several critical assumptions, including cash flow projections, operating cost escalation rates, rates of return, future growth rates, a risk-adjusted discount rate, long-term earnings and merger multiples of comparable companies.

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 the reporting unit’s 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.

The 2012 goodwill impairment analysis resulted in a significant excess of fair value of our reporting units over the carrying value.  The estimated fair value of our reporting units is sensitive to changes in assumptions, such as discount rates, peer company financial results, recent market transactions and forecasted cash flows.  

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, non-tax deductible expenses, or 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.  

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Accounting for Environmental Reserves:  Environmental reserves are accrued when assessments indicate 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 remediation options (ranging from no action required 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, the extent of our responsibility or the extent of remediation required, recently enacted laws and regulations or a change in cost estimates due to certain economic factors.  

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

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 our 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, the marketable securities held in CYAPC's and YAEC's nuclear decommissioning trusts, 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 on market risk, see Item 7A, "Quantitative and Qualitative Disclosures about Market Risk," included in this Annual Report on Form 10-K.

For further information on derivative contracts and marketable securities, see Note 1I, "Summary of Significant Accounting Policies - Derivative Accounting," Note 5, "Derivative Instruments," and Note 6, "Marketable Securities," to the consolidated financial statements.

Other Matters

Accounting Standards Recently Adopted:  For information regarding new accounting standards, see Note 1C, "Summary of Significant Accounting Policies – Recently Adopted Accounting Standards," to the consolidated financial statements.

Contractual Obligations and Commercial Commitments:  Information regarding our contractual obligations and commercial commitments as of December 31, 2012 is summarized annually through 2017 and thereafter as follows: