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, 2013
	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.  [   ]

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, 2013) was $13,224,337,788 based on a closing sales price of $42.02 per share for the 314,715,321 common shares outstanding on June 30, 2013.  

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	315,434,940 shares
The Connecticut Light and Power Company Common stock, $10.00 par value NSTAR Electric Company Common Stock, $1.00 par value	6,035,205 shares 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

ii

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

2013 FORM 10-K ANNUAL REPORT

TABLE OF CONTENTS

iii

NORTHEAST UTILITIES AND SUBSIDIARIES

THE CONNECTICUT LIGHT AND POWER COMPANY

NSTAR ELECTRIC COMPANY AND SUBSIDIARY

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY

WESTERN MASSACHUSETTS ELECTRIC COMPANY

SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES

LITIGATION REFORM ACT OF 1995

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

·

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

·

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

·

actions or inaction of 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,

·

fluctuations in weather patterns,

·

changes in laws, regulations or regulatory policy,

·

changes in levels or 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.

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NORTHEAST UTILITIES AND SUBSIDIARIES

THE CONNECTICUT LIGHT AND POWER COMPANY

NSTAR ELECTRIC COMPANY AND SUBSIDIARY

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY

WESTERN MASSACHUSETTS ELECTRIC COMPANY

PART I

Item 1.

Business

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

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 subsidiary, NU Enterprises, which is included in its Parent and other companies’ results of operations.

NU, CL&P, NSTAR Electric, PSNH and WMECO each report their financial results separately.  We also include information in this report on a segment basis for NU.  NU recognizes three reportable segments, which are electric distribution, electric transmission and natural gas distribution.  NU’s electric distribution segment includes the generation businesses of PSNH and WMECO.  These three segments represented substantially all of NU's total consolidated revenues for the years ended December 31, 2013 and 2012.  CL&P, NSTAR Electric, PSNH and WMECO do not report separate business segments.   

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 and its subsidiaries became wholly-owned subsidiaries of NU.  NU’s consolidated financial statements include the results of operations of NSTAR and its subsidiaries (NSTAR) 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.  

2

The following table shows the sources of 2013 electric franchise retail revenues for NU’s electric distribution companies, collectively, based on categories of customers:

(Thousands of Dollars, except percentages)		2013		% of Total
Residential	$	3,073,181		52
Commercial(1)		2,387,535		31
Industrial		339,917		16
Other and Eliminations		56,547		1
Total Retail Electric Revenues	$	5,857,180		100%

⁽¹⁾   Commercial retail electric revenue includes Streetlighting and Railroad retail revenue.

A summary of our distribution companies’ retail electric GWh sales and percentage changes for 2013, as compared to 2012, is as follows:

		2013		2012(1)		Percentage Change
Residential		21,896		21,374		2.4 %
Commercial (2)		27,787		27,647		0.5 %
Industrial		5,648		5,787		(2.4)%
Total		55,331		54,808		1.0 %

⁽¹⁾

Results include retail electric sales of NSTAR Electric for all of 2012 for comparative purposes only.  

⁽²⁾

 Commercial retail electric GWh sales include Streetlighting and Railroad retail sales.

Our 2013 consolidated retail electric sales were higher, as compared to 2012, due primarily to colder weather in the first and fourth quarters of 2013.  The 2013 retail electric sales for CL&P, NSTAR Electric and PSNH increased while they remained unchanged for WMECO, as compared to 2012, due primarily to colder weather in the first and fourth quarters of 2013.  In 2013, heating degree days were 17 percent higher in Connecticut and western Massachusetts, 16 percent higher in the Boston metropolitan area, and 15 percent higher in New Hampshire, and cooling degree days were 7 percent lower in Connecticut and western Massachusetts, 2 percent higher in the Boston metropolitan area, and 9 percent lower in New Hampshire, as compared to 2012.  On a weather-normalized basis (based on 30-year average temperatures), 2013 retail electric sales for CL&P and PSNH increased, while they decreased for NSTAR Electric and WMECO, as compared to 2012.  The 2013 weather-normalized NU consolidated total retail electric sales remained relatively unchanged, as compared to 2012.

For WMECO, fluctuations in retail electric sales do not impact earnings due to the DPU-approved revenue decoupling mechanism.  Under this decoupling mechanism, WMECO has an overall fixed annual level of distribution delivery service revenues of $132.4 million, comprised of customer base rate revenues of $125.4 million and a baseline low income discount recovery of $7 million.  These two mechanisms effectively break the relationship between sales volume and revenues recognized.

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, 2013, 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 2013 electric franchise retail revenues based on categories of customers:

	CL&P
(Thousands of Dollars, except percentages)		2013		% of Total
Residential	$	1,294,160		58
Commercial(1)		780,585		35
Industrial		129,557		6
Other		18,671		1
Total Retail Electric Revenues	$	2,222,973		100%

⁽¹⁾    Commercial retail electric revenue includes Streetlighting and Railroad retail revenue.

3

A summary of CL&P’s retail electric GWh sales and percentage changes for 2013, as compared to 2012, is as follows:

		2013		2012		Percentage Change
Residential		10,314		9,978		3.4 %
Commercial(1)		9,770		9,705		0.7 %
Industrial		2,320		2,426		(4.4)%
Total		22,404		22,109		1.3 %

⁽¹⁾    Commercial retail electric GWh sales include Streetlighting and Railroad retail sales.

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 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 56 percent of its customer load at SS or LRS rates while the other 44 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 rates established by the PURA for CL&P are comprised of the following:

·

An electric generation services charge, 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.  This charge is adjusted periodically and reconciled semi-annually in accordance with the directives of PURA.

·

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 to maintain such infrastructure.  

·

A federally-mandated congestion charge, or FMCC, 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, and any costs approved by PURA to reduce these charges.  This charge also recovers costs associated with CL&P’s system resiliency program.  This charge is adjusted periodically and reconciled semi-annually in accordance with the directives of PURA.

·

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

·

A competitive transition charge, assessed to recover stranded costs associated with electric industry restructuring such as various IPP contracts.  This charge is reconciled annually to actual costs incurred and reviewed by PURA, with any difference refunded to, or recovered from, customers.

·

A system benefits charge established to fund expenses 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; and unfunded storage and disposal costs for spent nuclear fuel generated before 1983.  This charge is reconciled annually to actual costs incurred and reviewed by PURA, with any difference refunded to, or recovered from, customers.  

·

A 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.  The Renewable Energy Investment Fund charge is set by statute and is currently 0.1 cent per kWh.

·

A conservation charge, comprised of a statutory rate established to implement cost-effective energy conservation programs and market transformation initiatives, plus a conservation adjustment mechanism charge to recover the residual energy efficiency spending associated with the expanded energy efficiency costs directed by the Comprehensive Energy Strategy Plan for Connecticut.

4

Expense/revenue reconciliation amounts for the electric generation services charge and the FMCC are recovered in subsequent rates.

CL&P, jointly with UI, has entered into four CfDs for a total of approximately 787 MW of capacity consisting of three electric generation units 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 generation units 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 through the FMCC charge.  The amounts of these payments are subject to changes in capacity and forward reserve prices that the projects receive in the ISO-NE capacity markets.

In 2008, CL&P entered into three CfDs with developers of peaking generation units approved by the PURA (Peaker CfDs). These units have a total of approximately 500 MW of peaking capacity. As directed by the PURA, CL&P and UI have entered into a sharing agreement, whereby CL&P is responsible for 80 percent and UI for 20 percent of the net costs or benefits of these CfDs. 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 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 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.

On September 19, 2013, CL&P, along with another Connecticut utility, signed long-term commitments, as required by regulation, to purchase approximately 250 MW of wind power from a Maine wind farm and 20 MW of solar power from sites in Connecticut, at a combined average price of less than $0.08 per kWh. On October 23, 2013, PURA issued a final decision accepting the contracts. The two projects are expected to be operational by the end of 2016.

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 one year 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 wholesale suppliers for firm requirements service for 70 percent of its SS loads for the first half of 2014, and has energy contracts in place to self-supply the remaining 30 percent for the first half of 2014.  For the second half of 2014, CL&P has 50 percent of its SS load under contract with various wholesale suppliers for firm requirements service and energy contracts in place to self-supply 10 percent.  CL&P intends to purchase 20 to 30 percent of the SS load for the second half of 2014 from wholesale suppliers for firm requirements service and will self-supply the remainder needed.  None of the SS load for 2015 has been procured.  CL&P has contracts in place for its LRS loads through the second quarter of 2014, and CL&P intends to purchase 100 percent of the LRS load for the third and fourth quarter of 2014 from wholesale suppliers for firm requirements service.

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, 2013, NSTAR Electric furnished retail franchise electric service to approximately 1.2 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 third party 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.  On September 4, 2013, the DPU approved WMECO's proposal to build a third solar generation facility and expand its solar energy portfolio from 6 MW to 8 MW.  On October 22, 2013, WMECO announced it would install a 3.9 MW solar generation facility on a site in East Springfield, Massachusetts.  The facility is expected to be completed in mid-2014 with an estimated cost of approximately $15 million.  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 enter into long-term contracts for 10 megawatts of solar power in connection with the Department of Energy Resources settlement agreement that approved the Merger in Massachusetts.  NSTAR Electric has entered in two contracts for 5 MW of capacity,

5

which were approved by the DPU in May, 2013.  However these contracts were terminated on November 6, 2013 by mutual agreement of the parties.  NSTAR Electric expects to meet its merger commitment by issuing a request for proposals to enter into long-term contracts for additional renewable solar generation.  

The following table shows the sources of the 2013 electric franchise retail revenues of NSTAR Electric and WMECO based on categories of customers:

		NSTAR Electric				WMECO
(Thousands of Dollars, except percentages)		2013		% of Total		2013			% of Total
Residential	$	1,066,673		45		$	228,632		57
Commercial(1)		1,181,678		25			131,763		33
Industrial		98,130		29			41,218		10
Other		17,092		1			(882)		-
Total Retail Electric Revenues	$	2,363,573		100%		$	400,731		100%

⁽¹⁾    Commercial retail electric revenue includes Streetlighting and Railroad retail revenue.

A summary of NSTAR Electric’s and WMECO’s retail electric GWh sales and percentage changes for 2013, as compared to 2012, is as follows:

		NSTAR Electric						WMECO
		2013		2012		Percentage Change		2013		2012		Percentage Change
Residential		6,831		6,741		1.3 %		1,544		1,517		1.7 %
Commercial(1)		13,163		13,115		0.4 %		1,496		1,503		(0.4)%
Industrial		1,312		1,353		(3.0)%		643		663		(3.0)%
Total		21,306		21,209		0.5 %		3,683		3,683		- %

⁽¹⁾    Commercial retail electric GWh sales include Streetlighting and Railroad retail sales.

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 and construction and operation of 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.

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 46 percent of its customer load at basic service rates while the other 54 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 rates established by the DPU for NSTAR Electric and WMECO are comprised of the following:

·

A basic service charge that represents the collection of energy costs, including costs related to charge-offs of uncollected energy costs.  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).  Additionally, the DPU has authorized NSTAR Electric to recover the cost of its Dynamic Pricing Smart Grid Pilot Program through the basic service charge.  Basic service costs are reconciled annually.

6

·

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.

·

For WMECO, a revenue decoupling adjustment, that reconciles distribution revenue, on an annual basis, to the amount of distribution revenue approved by the DPU in its last rate case.

·

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

·

A transition charge that 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.

·

Reconciling adjustment charges that recover certain DPU-approved costs, including a pension and PBOP rate to recover incremental pension and PBOP benefit costs, a  residential assistance adjustment factor to recover the cost of low income discounts, a net-metering surcharge to collect the lost revenue and credits associated with net-metering facilities installed by customers, a storm recovery charge to collect certain storm related costs, and an energy efficiency reconciliation factor to recover energy efficiency program costs and lost base revenues in addition to those charges recovered in the energy efficiency charge.  In addition to these adjustments, NSTAR Electric has a reconciling adjustment charge that collects certain safety and reliability program costs and costs related to its Smart Grid pilot program, while WMECO has a reconciling adjustment charge that recovers costs associated with certain solar projects owned and operated by WMECO.

·

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

·

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

Rate Settlement Agreement

On February 15, 2012, NU and NSTAR reached comprehensive settlement agreements with the Massachusetts Attorney General (Attorney General’s settlement agreement) and the DOER related to the merger.  The Attorney General’s 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.  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 energy policies.

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.  WMECO is currently decoupled and NSTAR Electric will propose decoupling in its 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.

NSTAR Electric and WMECO are each subject to service quality (SQ) metrics that measure safety, reliability and customer service and could be required to pay to customers a SQ charge of up to 2.5 percent of annual transmission and distribution revenues for failing to meet such metrics.  Neither NSTAR Electric nor WMECO will be required to pay a SQ charge for its 2013 performance as each company achieved results at or above target for all of its respective SQ metrics in 2013.

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, 2013, 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.  PSNH completed remaining project construction activities in 2012 and the final cost of the project was approximately $421 million.

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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.

Prudent Scrubber costs are allowed to be recovered through PSNH's ES rates under New Hampshire law.  In November 2011, the NHPUC opened a docket to review the Clean Air Project.  For information about this docket, see "Regulatory Developments and Rate Matters – New Hampshire – Clean Air Project Prudence Proceeding" in the accompanying Management’s Discussion and Analysis.

The following table shows the sources of PSNH’s 2013 electric franchise retail revenues based on categories of customers:

	PSNH
(Thousands of Dollars, except percentages)		2013		% of Total
Residential	$	483,716		56
Commercial (1)		293,509		34
Industrial		71,012		8
Other		21,665		2
Total Retail Electric Revenues	$	869,902		100%

⁽¹⁾    Commercial retail electric revenue includes Streetlighting and Railroad retail revenue.

A summary of PSNH’s retail electric GWh sales and percentage changes for 2013, as compared to 2012, is as follows:

		2013		2012		Percentage Change
Residential		3,208		3,138		2.2%
Commercial (1)		3,357		3,338		0.6%
Industrial		1,373		1,345		2.1%
Total		7,938		7,821		1.5%

⁽¹⁾    Commercial retail electric GWh sales include Streetlighting and Railroad retail sales.

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 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 2013, approximately 25 percent of all of PSNH’s customers (approximately 54 percent of load) had switched to competitive energy suppliers.  This was an increase from 2012, when 9 percent of customers (approximately 44 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 have not chosen a third party supplier, predominantly residential and small commercial 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 April 8, 2013, the NHPUC issued an order conditionally approving a PSNH settlement with OCA and PUC staff for an Alternative Default Energy (ADE) pilot program rate which was designed to address customer migration.  The NHPUC condition was accepted by the Settling Parties and incorporated into the initial implementation of Rate ADE in mid-2013.  The pilot program results in no impact to earnings and allows for an increased contribution to fixed costs for all ES customers.  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 the customers on third party supply may migrate back to PSNH.

On January 18, 2013, the NHPUC opened a docket to investigate market conditions affecting PSNH’s ES 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.  On July 15, 2013, the NHPUC accepted from the NHPUC Staff a "Report on Investigation into Market Conditions, Default Service Rate, Generation Ownership and Impact on the Competitive Electricity Market."  The report recommended that the NHPUC examine whether default service rates remain sustainable on a going forward basis, define "just and reasonable" with respect to default service in the context of competitive retail markets, analyze the current and expected value of PSNH’s generating units, and identify means to mitigate and address stranded cost recovery.  

On September 18, 2013, the NHPUC issued a Request for Proposal to hire a valuation expert to determine the value of PSNH's generation assets and entitlements.  On October 16, 2013, the State of New Hampshire Legislative Oversight Committee on Electric

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Utility Restructuring (Oversight Committee) requested that the NHPUC conduct an analysis to determine whether it is now in the economic interest of PSNH’s retail customers for PSNH to divest its interest in generation plants.  On November 1, 2013, the Oversight Committee asked for a preliminary report on the findings by April 1, 2014 that would include at a minimum the NHPUC Staff’s position, the analysis of the valuation expert, and any recommendations for legislation that may be needed concerning divestiture or otherwise related to this issue.  A valuation expert has been hired and the investigation is currently ongoing.  At this time, we cannot predict the outcome of this review.  Our current PSNH generation rate base totals approximately $760 million.  We continue to believe all costs and generation investments are probable of recovery.

On June 28, 2010, the NHPUC approved a joint settlement of PSNH's distribution 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 a defined series of step increases.  In 2013, PSNH filed for a distribution rate step increase.  On June 27, 2013, the NHPUC approved an increase to rates of $12.6 million, effective July 1, 2013.  The increase consists primarily of $7.7 million related to net plant additions and a $5 million increase to the current level of funding for the Major Storm Cost reserve.  

The rates established by the NHPUC for PSNH include the following:

·

An energy charge for customers who are not taking power from competitive energy suppliers.  The default energy service charge, or ES rate, is charged to customers who have never chosen competitive energy supply.  This charge recovers the costs of PSNH’s generation as well as purchased power and includes the NHPUC allowed ROE of 9.81 percent on PSNH’s generation investment.  Rate ADE is charged to certain customers who have returned to PSNH from competitive energy supply.  This rate allows PSNH to recover the forecast marginal cost of energy plus an adder for fixed costs.

·

A distribution charge, which includes an energy and/or demand-based charge to recover costs related to the maintenance and operation of PSNH’s infrastructure to deliver power to its destination, as well as power restoration and service costs.  This includes a customer charge to collect the cost of providing service to a customer; such as the installation, maintenance, reading and replacement of meters and maintaining accounts and records.  

·

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

·

A stranded cost recovery charge (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 had 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 the life of the RRBs.  The costs of the RRBs, which were retired on May 1, 2013, were recovered through the SCRC rate.

·

A system benefits charge which funds energy efficiency programs for all customers as well as assistance programs for residential customers within certain income guidelines.

·

An electricity consumption tax which is a state mandated tax on energy consumption.

The energy charge and SCRC rates change semi-annually and are reconciled annually.  Expense/revenue reconciliation amounts for the energy charge and SCRC are recovered in subsequent rates.  The Rate ADE reconciliation amount is incorporated into the ES reconciliation.

Sources and Availability of Electric Power Supply

During 2013, approximately 68 percent of PSNH’s load was met through its own generation, long-term power supply provided pursuant to orders of the NHPUC, and contracts with third parties.  The remaining 32 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 2014 in a similar manner.  Included in the 68 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.

2013, 2012 and 2011 Major Storms

Over the past three years, CL&P, NSTAR Electric, PSNH and WMECO each experienced significant storms, including Tropical Storm Irene, the October 2011 snowstorm, Storm Sandy, and the February 2013 blizzard.  As a result of these storms, each electric utility company suffered damage to its distribution and transmission systems, which caused customer outages and required the incurrence of costs to repair significant damage and restore customer service.  

The magnitude of these storm restoration costs met the criteria for cost deferral in Connecticut, Massachusetts, and New Hampshire.  As a result, the storms had no material impact on the results of operations of CL&P, NSTAR Electric, PSNH and WMECO.  We believe our response to each of these 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 electric utility company is seeking recovery of its deferred storm restoration costs through its applicable regulatory recovery process.  

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CL&P 2013 Storm Filing:  In March 2013, CL&P filed a request with PURA for approval to recover storm restoration costs associated with five major storms, all of which occurred in 2011 and 2012.  CL&P's deferred storm restoration costs associated with these major storms totaled $462 million.  Of that amount, approximately $414 million is subject to recovery in rates after giving effect to CL&P’s agreement to forego the recovery of $40 million of previously deferred storm restoration costs as well as an existing storm reserve fund balance of approximately $8 million.  During the second half of 2013, the PURA proceeded with the storm recovery review issuing discovery, holding hearings and ultimately on February 3, 2014, issuing a draft decision on the level of storm costs recovery.

In its draft decision, the PURA approved recovery of $365 million of deferred storm restoration costs and ordered CL&P to capitalize approximately $18 million of the deferred storm restoration costs as utility plant, which will be included in depreciation expense in future rate proceedings.  PURA will allow recovery of the $365 million with carrying charges in CL&P’s distribution rates over a six year period beginning December 1, 2014.  The remaining costs were either disallowed or are probable of recovery in future rates and did not have a material impact on CL&P’s financial position, results of operations or cash flows.  The final decision is expected from PURA in the first quarter of 2014.

NSTAR Electric 2013 Storm Filing:  On December 30, 2013, the DPU approved NSTAR Electric’s request to recover storm restoration costs, plus carrying costs, related to Tropical Storm Irene and the October 2011 snowstorm.  The DPU approved recovery of $34.2 million of the $38 million requested costs.  NSTAR Electric will recover these costs, plus carrying costs, in its distribution rates over a five-year period that commenced on January 1, 2014.

PSNH Major Storm Cost Reserve:  On June 27, 2013, the NHPUC approved an increase to PSNH’s distribution rates effective July 1, 2013 that included a $5 million increase to the current level of funding for the major storm cost reserve.

WMECO SRRCA Mechanism:  WMECO has an established Storm Reserve Recovery Cost Adjustment (SRRCA) mechanism to recover the restoration costs associated with its major storms.  Effective January 1, 2012, WMECO began recovering the restoration costs of Tropical Storm Irene and other storms that took place prior to August 2011.  On August 30, 2013, WMECO submitted its 2013 Annual SRRCA filing to begin recovering the restoration costs associated with the October 2011 snowstorm and Storm Sandy.  On December 20, 2013, the DPU approved the 2013 Annual SRRCA filing for effect on January 1, 2014, subject to further review and reconciliation.

2013, 2012 and 2011 Major Storm Deferrals:  As of December 31, 2013, the storm restoration costs deferred for recovery from customers for major storms that occurred during 2013, 2012 and 2011 at CL&P, NSTAR Electric, PSNH, and WMECO were as follows:

(Millions of Dollars)		2012 and 2011		2013		Total
CL&P		$ 365.0		$ 28.8		$ 393.8
NSTAR Electric		61.3		63.6		124.9
PSNH		33.7		5.3		39.0
WMECO		35.3		-		35.3
Total		$ 495.3		$ 97.7		$ 593.0

ELECTRIC TRANSMISSION SEGMENT

General

Each of CL&P, NSTAR Electric, PSNH and WMECO owns and maintains transmission facilities that are part of an interstate power transmission grid over which electricity is transmitted throughout New England.  Each of CL&P, NSTAR Electric, PSNH and WMECO, and most other New England utilities, are parties to a series of agreements that provide for coordinated planning and operation of the region's transmission facilities and the rules by which they acquire transmission services.  Under these arrangements, ISO-NE, a non-profit corporation whose board of directors and staff are independent of all market participants, serves as the regional transmission organization of the New England transmission system.  

Wholesale Transmission Revenues

A summary of NU’s wholesale transmission revenues is as follows:

(Millions of Dollars)		2013
CL&P	$	506.1
NSTAR Electric		253.6
PSNH		102.5
WMECO		116.5
Total Wholesale Transmission Revenues	$	978.7

Wholesale Transmission Rates

Wholesale transmission revenues are recovered through FERC approved formula rates.  Transmission revenues are collected from New England customers, the majority of which are distribution customers of CL&P, NSTAR Electric, PSNH and WMECO.  The

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transmission rates provide for the annual reconciliation and recovery or refund of estimated to actual costs.  The financial impacts of differences between actual and estimated costs are deferred for future recovery from, or refunded to, transmission customers.

FERC Base ROE Complaint

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 NETOs, 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 October 1, 2011.  In response, the NETOs filed testimony and analysis based on standard FERC methodology and precedent demonstrating that the base ROE of 11.14 percent remained just and reasonable.  The FERC set the case for trial before a FERC ALJ after settlement negotiations were unsuccessful in August 2012.

Hearings before the FERC ALJ were held in May 2013, followed by the filing of briefs by the complainants, the Massachusetts municipal electric utilities (late interveners to the case), the FERC trial staff and the NETOs.  The NETOs recommended that the current base ROE of 11.14 percent should remain in effect for the refund period (October 1, 2011 through December 31, 2012) and the prospective period (beginning when FERC issues its final decision).  The complainants, the Massachusetts municipal electric utilities, and the FERC trial staff each recommended a base ROE of 9 percent or below.

On August 6, 2013, the FERC ALJ issued an initial decision, finding that the base ROE in effect from October 2011 through December 2012 was not reasonable under the standard application of FERC methodology, but leaving policy considerations and additional adjustments to the FERC.  Using the established FERC methodology, the FERC ALJ determined that separate base ROEs should be set for the refund period and the prospective period.  The FERC ALJ found those base ROEs to be 10.6 percent and 9.7 percent, respectively.  The FERC may adjust the prospective period base ROE in its final decision to reflect movement in 10-year Treasury bond rates from the date that the case was filed (April 2013) to the date of the final decision.  The parties filed briefs on this decision with the FERC, and a decision from the FERC is expected in 2014.  Though NU cannot predict the ultimate outcome of this proceeding, in 2013 the Company recorded a series of reserves at its electric subsidiaries to recognize the potential financial impact from the FERC ALJ's initial decision for the refund period.  The aggregate after-tax charge to earnings totaled $14.3 million at NU, which represents reserves of $7.7 million at CL&P, $3.4 million at NSTAR Electric, $1.4 million at PSNH and $1.8 million at WMECO.

On December 27, 2012, several additional parties filed a separate complaint concerning the NETOs' base ROE with the FERC.  This complaint seeks to reduce the NETOs’ base ROE effective January 1, 2013, effectively extending the refund period for an additional 15 months, and to consolidate this complaint with the joint complaint filed on September 30, 2011.  The NETOs have asked the FERC to reject this complaint.  The FERC has not yet acted on this complaint, and management is unable to predict the ultimate outcome or estimate the impacts of this complaint on the financial position, results of operations or cash flows.

As of December 31, 2013, the CL&P, NSTAR Electric, PSNH, and WMECO aggregate shareholder equity invested in their transmission facilities was approximately $2.3 billion.  As a result, each 10 basis point change in the prospective period authorized base ROE would change annual consolidated earnings by an approximate $2.3 million.

Transmission Projects

NEEWS:  GSRP, the first, largest and most complicated project within the NEEWS family of projects was fully energized on November 20, 2013.  The project involved the construction of 115 kV and 345 kV overhead lines by CL&P and WMECO from Ludlow, Massachusetts to Bloomfield, Connecticut.  This transmission upgrade ensures the reliable flow of power in and around the southern New England area and enables access to less expensive generation, further reducing the risk of congestion costs impacting New England customers.  The project was fully energized ahead of schedule with a final cost of $676 million, $42 million under the $718 million estimated cost.  As of December 31, 2013, CL&P and WMECO have placed $628.2 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 the second major NEEWS project.  All siting applications have been filed by CL&P and National Grid.  The Connecticut and Rhode Island portions of the project have been approved and a siting approval decision in Massachusetts is expected in early 2014.  On February 12, 2014, the Army Corps of Engineers issued its permit enabling construction on the Connecticut portion of the project.  This is the final permit for the Connecticut portion of the project.  NU’s portion of the cost is estimated to be $218 million and the project is expected to be placed in service in late 2015.

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The Greater Hartford Central Connecticut Study (GHCC), which includes the reassessment of the Central Connecticut Reliability Project, continues to make progress.  The final need results, which were presented to the ISO-NE Planning Advisory Committee in November 2013, showed existing and worsening severe regional and local thermal overloads and voltage violations within and across each of the four study areas.  ISO-NE is expected to confirm the preferred transmission solutions in the first half of 2014, which are likely to include many 115 kV upgrades.  We continue to expect that the specific future projects being identified to address these reliability concerns will cost approximately $300 million and that the project will be placed in service in 2017.  

Included as part of NEEWS are associated reliability related projects, $90.8 million of which have been placed in service.  As of December 31, 2013, the remaining construction on the associated reliability related projects totaled $2.8 million, which is scheduled to be completed by mid-2014.   

Through December 31, 2013, CL&P and WMECO capitalized $252.8 million and $567 million, respectively, in costs associated with NEEWS, of which $40.8 million and $48.9 million, respectively, were capitalized in 2013.    

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 crosses the Cape Cod Canal and associated 115 kV upgrades in the center of Cape Cod (Lower SEMA Project) and related 115 kV projects (Mid-Cape Project).  The Lower SEMA Project line work was completed and placed into service in 2013.  The Mid-Cape Project is scheduled to be completed in 2017.  The aggregate estimated construction cost for the Cape Cod projects is expected to be approximately $150 million.  Through December 31, 2013, NSTAR Electric has invested $96 million in costs associated with the Cape Cod Reliability Projects, of which $61 million was capitalized in 2013.  

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.  The $1.4 billion project is subject to comprehensive federal and state public permitting processes and is expected to be operational by mid-2017.  On July 1, 2013, NPT filed an amendment to the DOE Presidential Permit Application for a proposed improved route in the northernmost section of the project area.  As of December 31, 2013, the DOE had completed its public scoping meeting process and the majority of its seasonal field work and environmental data collection.  NPT expects to file its state permit application in the fourth quarter of 2014 after the DOE’s draft Environmental Impact Statement (EIS) is received.  

NPT filed an amendment to the Transmission Services Agreement (TSA) with FERC on December 11, 2013, which was accepted by the FERC on January 13, 2014.  The TSA amendment that went into effect on February 14, 2014 extended certain deadlines to provide project flexibility and eliminated a penalty payment for termination of the project in the future.  

On December 31, 2013, NPT received ISO-NE approval under Section I.3.9 of the ISO tariff.  By approving the project’s Section I.3.9 application, ISO-NE determined that Northern Pass can reliably interconnect with the New England grid with no significant, adverse effect on the reliability or operating characteristics of the regional energy grid and its participants.  

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 expect projected costs to be approximately $440 million on these new 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 2013, our estimated transmission rate base was approximately $4.4 billion, including approximately $2.2 billion at CL&P, $1.1 billion at NSTAR Electric, $468 million at PSNH, and $597 million at WMECO.

NATURAL GAS DISTRIBUTION SEGMENT

The following table shows the sources of the 2013 natural gas franchise retail revenues of NSTAR Gas and Yankee Gas based on categories of customers:

		NSTAR Gas					Yankee Gas
(Thousands of Dollars, except percentages)		2013		% of Total		2013				% of Total
Residential	$	250,270		63		$		217,843		54
Commercial		132,730		33				129,788		32
Industrial		17,625		4				57,951		14
Total Retail Natural Gas Revenues	$	400,625		100%		$		405,582		100%

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A summary of NSTAR Gas’ and Yankee Gas’ retail firm natural gas sales and percentage changes in million cubic feet for 2013, as compared to 2012, is as follows:

		NSTAR Gas(1)						Yankee Gas
		2013		2012		Percentage Change		2013		2012		Percentage Change
Residential		21,911		18,385		19.2%		14,866		12,488		19.0%
Commercial		21,341		19,095		11.8%		18,874		16,567		13.9%
Industrial		5,773		5,205		10.9%		15,493		15,787		(1.9%)
Total		49,025		42,685		14.9%		49,233		44,842		9.8%
Total, Net of Special Contracts (2)								45,059		39,087		15.3%

⁽¹⁾

NSTAR Gas’ sales data for the full-year ended December 31, 2012 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 2013 consolidated firm natural gas sales are subject to many of the same influences as our retail electric sales, but have benefitted from favorable natural gas prices and customer growth across all three customer classes.  Our 2013 consolidated firm natural gas sales were higher, as compared to 2012, due primarily to colder weather in the first and fourth quarters of 2013.  The 2013 weather-normalized NU consolidated total firm natural gas sales increased 0.9 percent, as compared to 2012, due primarily to residential customer growth, an increase in natural gas conversions, the migration of interruptible customers switching to firm service rates, and the addition of gas-fired distributed generation, all of which was primarily in the Yankee Gas service territory.

NSTAR GAS

NSTAR Gas distributes natural gas to approximately 274,000 customers in 51 communities in central and eastern Massachusetts covering 1,067 square miles.  Total throughput (sales and transportation) in 2013 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.  

Predominantly all residential customers in the NSTAR Gas service territory buy gas supply and delivery from NSTAR Gas while all customers may choose their gas suppliers.  NSTAR Gas offers firm transportation service to all customers who purchase gas from sources other than NSTAR 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 NSTAR Gas can interrupt service during peak demand periods or at any other time to maintain distribution system integrity.

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 merger settlement agreement provided for a rate freeze through 2015.

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.

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NSTAR Gas is subject to SQ metrics that measure safety, reliability and customer service and could be required to pay to customers a SQ charge of up to 2.5 percent of annual distribution revenues for failing to meet such metrics.  NSTAR Gas will not be required to pay a SQ charge for its 2013 performance as it achieved results at or above target for all of its SQ metrics in 2013.

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 the Gulf Coast, Mid-continent region, 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 Yankee Energy Systems, Inc.  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.

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

Yankee Gas operates the largest natural gas distribution system in Connecticut as measured by number of customers (approximately 218,000 customers in 71 cities and towns), and size of service territory (2,187 square miles).  Total throughput (sales and transportation) in 2013 was approximately 55 Bcf.  Yankee Gas provides firm natural gas sales service to retail customers who require a continuous natural gas supply throughout the year, such as residential customers who rely on natural 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

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·

Conservation Adjustment Mechanism (CAM), which allows 100 percent recovery of conservation costs through this mechanism including program incentives to promote energy efficiency, as well as recovery of any lost revenues associated with implementation of energy conservation measures.  A reconciliation of CAM revenue to expenses is performed annually with any difference being recovered or refunded with carrying charges in future customer rates the following 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.

PROJECTED CAPITAL EXPENDITURES

We project to make capital expenditures of approximately $7.6 billion from 2014 through 2017.  Of the $7.6 billion, we expect to invest approximately $3.5 billion in our electric and natural gas distribution segments and $3.7 billion in our electric transmission segment.  In addition, we project to invest approximately $400 million for our corporate service companies.

FINANCING

Our credit facilities and indentures require that NU parent and certain of its subsidiaries, including CL&P, NSTAR Electric, NSTAR Gas, 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 of these companies currently are, and expect to remain, in compliance with these covenants.    

As of December 31, 2013, a total of $501.7 million of NU's long-term debt will be paid in the next 12 months, consisting of $150 million for CL&P, $301.7 million for NSTAR Electric and $50 million or PSNH.  

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.

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OTHER REGULATORY AND ENVIRONMENTAL MATTERS

General

We are regulated in virtually all aspects of our business by various federal and state agencies, including 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.  

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 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.

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.

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 2013, the total RPS obligation was 11.65 percent and it will ultimately reach 24.8 percent in 2025.  Energy suppliers, like PSNH, purchase RECs from producers that generate energy from a qualifying resource and use them to satisfy the RPS requirements.  PSNH also owns renewable sources and uses a portion of internally generated RECs and purchased RECs to meet its RPS obligations.  To the extent that PSNH is unable to purchase sufficient RECs, it makes up the difference between the RECs purchased and its total obligation by making an alternative compliance payment for each REC requirement for which PSNH is deficient.  The costs of both the RECs and alternative compliance payments are recovered by PSNH through its ES rates charged to customers.  

The RECs generated from PSNH’s Northern Wood Power Project, a wood-burning facility, are 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.

Similarly, Connecticut's RPS statute requires increasing percentages of the electricity sold to retail customers to have direct ties to renewable sources.  In 2013, the total RPS obligation was 17 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.

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Massachusetts’ RPS program also requires electricity suppliers to meet renewable energy standards.  For 2013, the requirement was 15.1 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 laws and regulations 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, 2013, 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 $35.4 million, representing 68 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 $31.4 million of the total $35.4 million as of December 31, 2013.  Predominantly all of these MGP costs are recoverable from customers through our rates.

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.

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.

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 respective generation 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

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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 that 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.

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.

EMPLOYEES

As of December 31, 2013, NU employed a total of 8,697 employees, excluding temporary employees, of which 1,566 were employed by CL&P, 1,025 were employed by PSNH, 308 were employed by WMECO, and 2,194 were employed by NSTAR Electric.  Approximately 48 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, 107 Selden Street, Berlin, CT 06037.

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.

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.

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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, 2013, goodwill totaled $3.5 billion, of which $3.2 billion was attributable to the acquisition of NSTAR in April 2012.  Total goodwill represented approximately 36 percent of our $9.6 billion of shareholders’ equity and approximately 13 percent of our total assets of $27.8 billion.  We test our goodwill balances 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.  The annual goodwill impairment test in 2013 resulted in a conclusion that goodwill is not impaired.

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

Severe weather, such as ice and snow storms, hurricanes and other natural disasters, may cause outages and property damage, which may require us to incur additional costs that may not be recoverable from customers.  The cost of repairing damage to our operating subsidiaries' facilities and the potential disruption of their operations due to storms, natural disasters or other catastrophic events could be substantial, particularly as customers demand better and quicker response times to outages.  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 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.

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.

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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.

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.

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

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

In addition, a period of prolonged economic weakness could impact customers’ ability to pay bills in a timely manner and increase customer bankruptcies, which may lead to increased bad debt expenses or other adverse effects on our financial position, results of operations or cash flows.

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

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

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

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

Changes in regulatory or legislative policy or unfavorable outcomes in regulatory proceedings could jeopardize our full and/or timely recovery of costs incurred by our regulated distribution and generation businesses.

Under state law, our Regulated companies are entitled to charge rates that are sufficient to allow them an opportunity to recover their reasonable operating and capital costs, to attract needed capital and maintain their financial integrity, while also protecting relevant public interests.  Each of these companies prepares and submits periodic rate filings with their respective state regulatory commissions for review and approval.  There is no assurance that these state commissions will approve the recovery of all such costs incurred by our Regulated companies, such as for construction, operation and maintenance, as well as a return on investment on their respective regulated assets.  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.

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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 included in 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 energy supply 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, which could have an adverse impact on its financial position, results of operations and cash flows.

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.  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.

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, in 2013, NU made contributions to the NUSCO Pension Plan totaling $202.7 million and NSTAR Electric contributed $82 million to the NSTAR Pension Plan.  We expect to make contributions in 2014 totaling $71.6 million.  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

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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.  

Item 2. Properties
Transmission and Distribution System
As of December 31, 2013, NU and our electric operating subsidiaries owned the following:
		Electric		Electric
NU		Distribution		Transmission
Number of substations owned		520		62
Transformer capacity (in kVa)		41,928,000		17,827,000
Overhead lines (distribution in pole miles and
	transmission in circuit miles)	52,022		3,870
Capacity range of overhead transmission lines (in kV)				69 to 345
Underground lines (distribution in conduit bank miles and
	transmission in cable miles)	12,785		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			183		19		138		20		156		15		43		8
Transformer capacity (in kVa)			18,951,000		3,117,000		11,374,000		9,575,000		7,617,000		3,868,000		3,986,000		1,267,000
Overhead lines (distribution in
	pole miles and transmission
	in circuit miles)		18,375		1,654		16,579		708		13,274		1,003		3,794		505
Capacity range of overhead
	transmission lines (in kV)				69-345				115-345				115-345				69-345
Underground lines (distribution
	in conduit bank miles and
	transmission in cable miles)		1,171		402		9,592		243		1,730		1		292		31
Capacity range of underground
	transmission lines (in kV)				69-345				115-345				115				115

									NSTAR
			NU			CL&P			Electric			PSNH			WMECO
Underground and overhead
	line transformers in service		627,962			286,922			131,500			166,866			42,674
Aggregate capacity (in kVa)			34,361,049			14,946,332			10,289,291			7,024,239			2,101,187

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Electric Generating Plants

As of December 31, 2013, PSNH owned the following electric generating plants:  

Type of Plant			Number of Units		Year Installed		Claimed Capability* (kilowatts)
Fossil – Steam Plants			5 units		1952-74		935,343
Hydro			20 units		1901-83		60,736
Internal Combustion			5 units		1968-70		101,868
Biomass			1 unit		2006		42,594
Total PSNH Generating Plant			31 units				1,140,541

*

Claimed capability represents winter ratings as of December 31, 2013.  The combined nameplate capacity of the generating plants is approximately 1,200 MW.

As of December 31, 2013, WMECO owned the following electric generating plants:  

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

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

CL&P and NSTAR Electric do not own any electric generating plants.

Natural Gas Distribution System

As of December 31, 2013, Yankee Gas owned 28 active gate stations, 206 district regulator stations, and 3,291 miles of natural gas main pipeline.  Yankee Gas also owns a 1.2 Bcf LNG facility in Waterbury, Connecticut.  

As of December 31, 2013, NSTAR Gas owned 21 active gate stations, 145 district regulator stations, and 3,213 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

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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 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

DOE Phase I Damages – 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).  Phase I covered damages for the period 1998 through 2002.  Following multiple appeals and cross-appeals in December 2012, the judgment awarding CYAPC $39.6 million, YAEC $38.3 million and MYAPC $81.7 million became final.

In January 2013, the proceeds from the DOE Phase I Damages Claim were received by the Yankee Companies and transferred to each Yankee Company’s respective decommissioning trust.  As a result of NU's consolidation of CYAPC and YAEC, the financial statements reflected an increase of $77.9 million in marketable securities for CYAPC and YAEC’s Phase I damage awards that were invested in the nuclear decommissioning trusts in 2013.

On May 1, 2013, CYAPC, YAEC and MYAPC filed applications with the FERC to reduce rates in their wholesale power contracts through the application of the DOE proceeds for the benefit of customers.  In its June 27, 2013 order, the FERC granted the proposed rate reductions, and changes to the terms of the wholesale power contracts to become effective on July 1, 2013.  In accordance with the FERC order, CL&P, NSTAR Electric, PSNH and WMECO began receiving the benefit of the DOE proceeds, and the benefits have been or will be passed on to customers.

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DOE Phase II Damages - 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.  

On November 15, 2013, the court issued a final judgment awarding CYAPC $126.3 million, YAEC $73.3 million, and MYAPC $35.8 million.  On January 14, 2014, the Yankee Companies received a letter from the U.S. Department of Justice stating that the DOE will not appeal the court's final judgment.  As of December 31, 2013, CL&P, NSTAR Electric, PSNH, WMECO, CYAPC, and YAEC have not reflected the impact of these expected receivables on their financial statements.

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

DOE Phase III Damages – On August 15, 2013, the Yankee Companies each filed subsequent lawsuits against the DOE seeking recovery of actual damages incurred in the years 2009 through 2012.  Responsive pleading from the Department of Justice was filed on November 18, 2013, and discovery is expected to begin once a protective order is in place.

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 September 27, 2012, the federal court dismissed portions of CLF’s suit pertaining to the installation of activated carbon injection and the electrostatic precipitators.  The case is expected to proceed to trial over the course of the next two years.

3.

Other Legal Proceedings

For further discussion of legal proceedings, see Item 1, Business:  "- Electric Distribution Segment," "- Electric Transmission Segment," and "- Natural Gas Distribution 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.

Item 4.

Mine Safety Disclosures

Not applicable.

EXECUTIVE OFFICERS OF THE REGISTRANT

The following table sets forth the executive officers of NU as of February 15, 2014.  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		44		Vice President, Controller and Chief Accounting Officer.
Gregory B. Butler		56		Senior Vice President, General Counsel and Secretary.
Christine M. Carmody*		51		Senior Vice President-Human Resources of NUSCO.
James J. Judge		58		Executive Vice President and Chief Financial Officer.
Thomas J. May		66		Chairman of the Board, President and Chief Executive Officer.
David R. McHale		53		Executive Vice President and Chief Administrative Officer.
Joseph R. Nolan, Jr.*		50		Senior Vice President-Corporate Relations of NUSCO.
Leon J. Olivier		65		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 has served as Vice President, Controller and Chief Accounting Officer of NU, CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO, Yankee Gas and NUSCO since April 10, 2012.  Previously, Mr. Buth served as Vice President-Accounting and Controller of NU, CL&P, PSNH, WMECO, Yankee Gas and NUSCO from June 2009 until April 10, 2012.  From June 2006 through January 2009, Mr. Buth served as 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.

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Gregory B. Butler.  Mr. Butler has served as Senior Vice President, General Counsel and Secretary of NU and Senior Vice President and General Counsel of NSTAR Electric and NSTAR Gas since April 10, 2012.  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 has served as a Director of NSTAR Electric and NSTAR Gas since April 10, 2012.  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 10, 2012.  Mr. Butler has served as a Trustee of the NSTAR Foundation since April 10, 2012.  He has served as a Director of Northeast Utilities Foundation, Inc. since December 1, 2002.  

Christine M. Carmody.  Ms. Carmody has served as Senior Vice President-Human Resources of NUSCO since April 10, 2012 and of CL&P, PSNH, WMECO and Yankee Gas since November 27, 2012.  She has served as Senior Vice President-Human Resources of NSTAR Electric and NSTAR Gas since August 1, 2008.  Ms. Carmody has served as a Director of CL&P, PSNH, WMECO and Yankee Gas since April 10, 2012, and of NSTAR Electric, NSTAR Gas, and NUSCO since November 27, 2012.  Previously, Ms. Carmody served as Vice President-Organizational Effectiveness of NSTAR, NSTAR Electric and NSTAR Gas from June 2006 to August 2008.  Ms. Carmody has served as a Director of Northeast Utilities Foundation, Inc. since April 10, 2012.  She has served as a Trustee of the NSTAR Foundation since August 1, 2008.

James J. Judge.  Mr. Judge has served as Executive Vice President and Chief Financial Officer of NU, CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO, Yankee Gas and NUSCO since April 10, 2012.  Mr. Judge has served as a Director of CL&P, PSNH, WMECO, Yankee Gas and NUSCO since April 10, 2012.  He has served as a Director of NSTAR Electric and NSTAR Gas since September 27, 1999.  Previously, Mr. Judge served as Senior Vice President and Chief Financial Officer of NSTAR, NSTAR Electric and NSTAR Gas from 1999 until April 2012.  Mr. Judge has served as Treasurer and a Director of Northeast Utilities Foundation, Inc. since April 10, 2012.  He has served as a Trustee of the NSTAR Foundation since December 12, 1995.  

Thomas J. May.  Mr. May has served as Chairman of the Board of NU since October 10, 2013, and 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 of NUSCO since April 10, 2012.  Mr. May has served as a Director of NSTAR Electric and NSTAR 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 and NSTAR Gas until April 10, 2012.  He served as Chairman, Chief Executive Officer and a Trustee since NSTAR was formed in 1999, and was elected President in 2002.  Mr. May has served as Chairman of the Board and President of Northeast Utilities Foundation, Inc. since October 15, 2013, and has served as a Director of Northeast Utilities Foundation, Inc. since April 10, 2012.  He has served as a Trustee of the NSTAR Foundation since August 18, 1987.  

David R. McHale.  Mr. McHale has served as Executive Vice President and Chief Administrative Officer of NU, CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO, Yankee Gas and NUSCO since April 10, 2012.  Mr. McHale has served as a Director of NSTAR Electric and NSTAR 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 has served as a Trustee of the NSTAR Foundation since April 10, 2012.  He has served as a Director of Northeast Utilities Foundation, Inc. since January 1, 2005.

Joseph R. Nolan, Jr.  Mr. Nolan has served as Senior Vice President-Corporate Relations of NSTAR Electric, NSTAR Gas and NUSCO since April 10, 2012.  He has served as Senior Vice President-Corporate Relations of CL&P, PSNH, WMECO and Yankee Gas since November 27, 2012.  Mr. Nolan has served as a Director of CL&P, PSNH, WMECO and Yankee Gas since April 10, 2012, and of NSTAR Electric, NSTAR Gas and NUSCO since November 27, 2012.  Previously, Mr. Nolan served as Senior Vice President-Customer & Corporate Relations of NSTAR, NSTAR Electric and NSTAR Gas from 2006 until April 10, 2012.  Mr. Nolan has served as a Director of Northeast Utilities Foundation, Inc. since April 10, 2012, and has served as Executive Director of Northeast Utilities Foundation, Inc. since October 15, 2013.  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.  He became Chief Executive Officer of NSTAR Electric and NSTAR Gas on April 10, 2012.  Mr. Olivier has served as Chief Executive Officer of CL&P, PSNH, WMECO and Yankee Gas since January 15, 2007.  Mr. Olivier has served as a Director of NSTAR Electric and NSTAR Gas since November 27, 2012, of PSNH, WMECO and Yankee Gas since 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 has served as a Trustee of the NSTAR Foundation since April 10, 2012.  He has served as a Director of Northeast Utilities Foundation, Inc. since April 1, 2006.  

27

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
2013		First		$	43.49		$	38.60		$	0.368

		Second			45.66			39.35			0.368
		Third			45.13			40.01			0.368
		Fourth			43.75			40.60			0.368
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

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.   

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 2013 and 2012, CL&P approved and paid $152 million and $100.5 million, respectively, of common stock dividends to NU.

During 2013, NSTAR Electric approved and paid $56 million of common stock dividends to its parent company.  For the period April 10, 2012 to December 31, 2012, NSTAR Electric approved and paid $159.9 million of common stock dividends to its parent company.

During 2013 and 2012, PSNH approved and paid $68 million and $90.7 million, respectively, of common stock dividends to NU.

During 2013 and 2012, WMECO approved and paid $40 million and $9.4 million, respectively, of common stock dividends to NU.

(b)

Holders

As of January 31, 2014, there were 46,983 registered common shareholders of our company on record.  As of the same date, there were a total of 315,434,940 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

The performance graph below illustrates a five-year comparison of cumulative total returns based on an initial investment of $100 in 2008 in Northeast Utilities common stock, as compared with the S&P 500 Stock Index and the EEI Index for the period 2009 through 2013, assuming all dividends are reinvested.

28

(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.

		Period		Total Number of Shares Purchased			Average Price Paid per Share	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans and Programs (at month end)
		October 1 - October 31, 2013		-		$	-	-	-
		November 1 - November 30, 2013		-			-	-	-
		December 1 - December 31, 2013		75,700			42.22	-	-
		Total		75,700		$	42.22	-	-

29

Item 6. Selected Consolidated Financial Data
NU Selected Consolidated Financial Data (Unaudited)
(Thousands of Dollars, except percentages and common         share information)					2013			2012 (a)			2011			2010			2009
Balance Sheet Data:
	Property, Plant and Equipment, Net				$	17,576,186		$	16,605,010		$	10,403,065		$	9,567,726		$	8,839,965
	Total Assets					27,795,537			28,302,824			15,647,066			14,472,601			14,057,679
	Total Capitalization (b) (c)					18,077,274			17,356,112			9,078,321			8,627,985			8,253,323
	Obligations Under Capital Leases (b)					10,744			11,071			12,358			12,236			12,873
Income Statement Data:
	Operating Revenues				$	7,301,204		$	6,273,787		$	4,465,657		$	4,898,167		$	5,439,430
	Net Income					793,689			533,077			400,513			394,107			335,592
	Net Income Attributable to Noncontrolling Interests					7,682			7,132			5,820			6,158			5,559
	Net Income Attributable to Controlling Interest				$	786,007		$	525,945		$	394,693		$	387,949		$	330,033
Common Share Data:
	Basic Earnings Per Common Share:
		Net Income Attributable to Controlling Interests			$	2.49		$	1.90		$	2.22		$	2.20		$	1.91
	Diluted Earnings Per Common Share:
		Net Income Attributable to Controlling Interest			$	2.49		$	1.89		$	2.22		$	2.19		$	1.91
	Weighted Average Common Shares Outstanding
		Basic				315,311,387			277,209,819			177,410,167			176,636,086			172,567,928
		Diluted				316,211,160			277,993,631			177,804,568			176,885,387			172,717,246
	Dividends Declared Per Share				$	1.47		$	1.32		$	1.10		$	1.03		$	0.95
	Market Price - Closing (high) (d)				$	45.33		$	40.57		$	36.31		$	32.05		$	26.33
	Market Price - Closing (low) (d)				$	38.67		$	33.53		$	30.46		$	24.78		$	19.45
	Market Price - Closing (end of year) (d)				$	42.39		$	39.08		$	36.07		$	31.88		$	25.79
	Book Value Per Share (end of year)				$	30.49		$	29.41		$	22.65		$	21.60		$	20.37
	Tangible Book Value Per Share (end of year) (e)				$	19.32		$	18.21		$	21.03		$	19.97		$	18.74
	Rate of Return Earned on Average Common Equity (%) (f)					8.3			7.9			10.1			10.7			10.2
	Market-to-Book Ratio (end of year) (g)					1.4			1.3			1.6			1.5			1.3
Capitalization:
	Total Equity					53	%		53	%		44	%		44	%		44	%
	Preferred Stock, not subject to mandatory redemption					1			1			1			1			1
	Long-Term Debt (b) (c)					46			46			55			55			55
						100	%		100	%		100	%		100	%		100	%

(a)		The 2012 results include the operations of NSTAR beginning April 10, 2012.
(b)		Includes portions due within one year.
(c)		Excludes RRBs.
(d)		Market price information reflects closing prices as reflected by the New York Stock Exchange.
(e)		Common Shareholder's Equity adjusted for goodwill and intangibles divided by total common shares outstanding.
(f)		Net Income Attributable to Controlling Interest divided by average Common Shareholders' Equity.
(g)		The closing market price divided by the book value per share.
CL&P Selected Financial Data (Unaudited)
(Thousands of Dollars)					2013			2012			2011			2010			2009
Operating Revenues					$	2,442,341		$	2,407,449		$	2,548,387		$	2,999,102		$	3,424,538
Net Income						279,412			209,725			250,164			244,143			216,316
Cash Dividends on Common Stock						151,999			100,486			243,218			217,691			113,848
Property, Plant and Equipment, Net						6,451,259			6,152,959			5,827,384			5,586,504			5,340,561
Total Assets						8,980,502			9,142,088			8,791,396			8,255,192			8,364,564
Rate Reduction Bonds						-			-			-			-			195,587
Long-Term Debt (a) (b)						2,741,208			2,862,790			2,583,753			2,583,102			2,582,361
Preferred Stock Not Subject to Mandatory Redemption						116,200			116,200			116,200			116,200			116,200
Obligations Under Capital Leases (a)						9,309			9,960			10,715			10,613			10,956
(a)		Includes portions due within one year.
(b)		Excludes RRBs.
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
		2013			2012 (a)			2011			2010			2009
Revenues:  (Thousands)
Residential	$	3,073,181		$	2,731,951		$	2,091,270		$	2,336,078		$	2,569,278
Commercial		2,387,535			1,604,661			1,236,374			1,346,228			1,495,821
Industrial		339,917			753,974			252,878			268,598			297,854
Wholesale		486,515			357,223			350,413			506,475			445,261
Miscellaneous and Eliminations		56,547			130,137			47,485			(29,878)			128,118
Total Electric		6,343,695			5,577,946			3,978,420			4,427,501			4,936,332
Natural Gas		855,601			572,857			430,799			434,277			449,571
Total - Regulated Companies		7,199,296			6,150,803			4,409,219			4,861,778			5,385,903
Other and Eliminations		101,908			122,984			56,438			36,389			53,527
Total	$	7,301,204		$	6,273,787		$	4,465,657		$	4,898,167		$	5,439,430
Regulated Companies - Sales:  (GWh)
Residential		21,896			19,719			14,766			14,913			14,412
Commercial		27,787			24,537			14,628			14,836			14,810
Industrial		5,648			5,462			4,418			4,481			4,423
Wholesale		855			2,154			1,020			3,423			4,183
Total		56,186			51,872			34,832			37,653			37,828
Regulated Companies - Customers:  (Average)
Residential		2,718,727			2,711,407			1,710,342			1,704,197			1,696,756
Commercial		371,897			370,389			199,240			198,558			196,813
Industrial		8,109			8,279			7,083			7,150			7,207
Total Electric		3,098,733			3,090,075			1,916,665			1,909,905			1,900,776
Natural Gas		493,563			483,770			207,753			205,885			206,438
Total		3,592,296			3,573,845			2,124,418			2,115,790			2,107,214
(a) The 2012 results include the operations of NSTAR beginning April 10, 2012.

CL&P Selected Sales Statistics
		2013			2012			2011			2010			2009
Revenues:  (Thousands)
Residential	$	1,294,160		$	1,263,845		$	1,345,290		$	1,597,754		$	1,840,750
Commercial		780,585			732,620			758,145			853,956			958,224
Industrial		129,557			126,165			126,783			144,463			151,839
Wholesale		219,367			214,807			278,751			441,660			386,034
Miscellaneous		18,672			70,012			39,418			(38,731)			87,691
Total	$	2,442,341		$	2,407,449		$	2,548,387		$	2,999,102		$	3,424,538
Sales:  (GWh)
Residential		10,314			9,978			10,092			10,196			9,848
Commercial		9,770			9,705			9,809			10,002			9,991
Industrial		2,320			2,426			2,414			2,467			2,427
Wholesale		851			1,155			1,592			3,040			3,434
Total		23,255			23,264			23,907			25,705			25,700
Customers:  (Average)
Residential		1,105,417			1,103,397			1,100,740			1,096,576			1,093,229
Commercial		108,735			108,589			108,235			107,532			107,121
Industrial		3,247			3,301			3,331			3,359			3,381
Total		1,217,399			1,215,287			1,212,306			1,207,467			1,203,731

31

Item 7.

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

The following discussion and analysis should be read in conjunction with our consolidated financial statements and related combined notes included in this Annual Report on Form 10-K.  References in this Annual Report to "NU," the "Company," "we," "us," and "our" refer to Northeast Utilities and its consolidated subsidiaries.  All per share amounts are reported on a diluted basis.  The consolidated financial statements of NU, NSTAR Electric and PSNH and the financial statements of CL&P and WMECO are herein collectively referred to as the "financial statements."

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 year.  The discussion below also includes non-GAAP financial measures referencing our 2013, 2012 and 2011 earnings and EPS excluding certain integration and merger costs related to NU's merger with NSTAR and 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.  We use these non-GAAP financial measures to evaluate and to provide details of earnings by business and to more fully compare and explain our 2013, 2012 and 2011 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, we completed our merger with NSTAR.  Unless otherwise noted, the results of NSTAR and its subsidiaries, hereinafter referred to as "NSTAR," are included in NU’s financial position, results of operations and cash flows as of December 31, 2013 and 2012, for the full year ended December 31, 2013, and for the period beginning April 10, 2012 through December 31, 2012 throughout this Management's Discussion and Analysis of Financial Condition and Results of Operations.

Executive Summary

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

Results:

·

We earned $786 million, or $2.49 per share, in 2013, compared with $525.9 million, or $1.89 per share, in 2012.  Excluding after-tax integration and merger-related costs of $13.8 million, or $0.04 per share, in 2013 and $107.6 million, or $0.39 per share, in 2012, we earned $799.8 million, or $2.53 per share, in 2013 and $633.5 million, or $2.28 per share, in 2012.  

·

Our electric distribution segment, which includes generation, earned $427 million, or $1.35 per share, in 2013, compared with $292.3 million, or $1.04 per share, in 2012.  The 2012 results include $51.1 million, or $0.19 per share, of after-tax merger settlement agreement costs.

·

Our transmission segment earned $287 million, or $0.91 per share, in 2013, compared with $249.7 million, or $0.90 per share, in 2012.

·

Our natural gas distribution segment earned $60.9 million, or $0.19 per share, in 2013, compared with $30.8 million, or $0.11 per share, in 2012.  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 earnings of $11.1 million, or $0.04 per share, in 2013, compared with net losses of $46.9 million, or $0.16 per share, in 2012.  The 2013 and 2012 results include $13.8 million, or $0.04 per share, and $54.4 million, or $0.19 per share, respectively, of after-tax integration and merger-related costs.

·

We project to make capital expenditures of approximately $7.6 billion from 2014 through 2017.  Of the $7.6 billion, we expect to invest approximately $3.5 billion in our electric and natural gas distribution segments and $3.7 billion in our electric transmission segment.  In addition, we project to invest approximately $400 million for our corporate service companies.

32

Legislative, Regulatory, Policy and Other Items:

·

In 2013, CL&P and NSTAR Electric filed a request with the PURA and DPU, respectively, seeking approval to recover storm restoration costs.  On December 30, 2013, the DPU approved recovery of NSTAR Electric’s $34.2 million in storm restoration costs.  On February 3, 2014, the PURA issued a draft decision, approving recovery of CL&P’s $365 million in storm restoration costs.

·

In 2013, Connecticut enacted into law two significant energy bills.  The first law implemented a number of the recommendations proposed in the Connecticut comprehensive energy strategy (CES), including the expansion of natural gas service, and required PURA to implement decoupling for each of Connecticut’s electric and natural gas utilities in their next respective rate cases.  The second law allows DEEP to conduct a process that will ultimately help Connecticut meet its Renewable Portfolio Standard by authorizing the state’s electric distribution companies to enter into long-term power purchase agreements.  

·

On November 22, 2013, the PURA issued a final decision approving a comprehensive joint natural gas infrastructure expansion plan (expansion plan), consistent with the goals of the CES, that was filed in June 2013 by Yankee Gas and other Connecticut natural gas distribution companies.  The expansion plan described how Yankee Gas expects to add approximately 82,000 new natural gas heating customers over the next 10 years.  

·

On July 1, 2013, NPT filed an amendment to the Department of Energy (DOE) Presidential Permit Application for a proposed improved route in the northernmost section of the project area.  The DOE completed its public scoping meeting process and the majority of its seasonal field work and environmental data collection.  On December 11, 2013, NPT filed an amendment to the Transmission Services Agreement (TSA) with FERC, which was accepted on January 13, 2014.  On December 31, 2013, NPT received ISO-NE approval under Section I.3.9 of the ISO tariff.  

·

On August 6, 2013, the FERC ALJ issued an initial decision regarding the September 2011 joint complaint filed with the FERC by various New England parties concerning the base ROE earned by New England transmission owners (NETOs).  The initial decision found that the current base ROE is not reasonable, but leaves policy considerations and additional adjustments to the FERC, and determined that a separate base ROE of 10.6 percent and 9.7 percent should be set for the refund period (October 1, 2011 through December 31, 2012) and the prospective period (beginning when FERC issues its final decision), respectively.  The FERC may adjust the prospective period base ROE in its final decision, expected in 2014, to reflect movement in the capital markets from when the case was filed in April 2013.  As a result, in 2013, we recorded a reserve and recognized an after-tax charge of $14.3 million for the potential financial impact from the FERC ALJ's initial decision.

·

On November 20, 2013, GSRP, the first, largest and most complicated project within the NEEWS family of projects was fully energized.  The project was fully energized ahead of schedule with a final cost of $676 million, $42 million under the $718 million estimated cost.

Liquidity:

·

Cash and cash equivalents totaled $43.4 million as of December 31, 2013, compared with $45.7 million as of December 31, 2012, while investments in property, plant and equipment totaled $1.5 billion in both 2013 and 2012.

·

Cash flows provided by operating activities in 2013 totaled $1.58 billion, compared with operating cash flows of $1.05 billion in 2012 (amounts are net of RRB payments).  The improved cash flows were due primarily to the addition of NSTAR, a decrease in storm restoration costs, and the absence in 2013 of customer bill credits and merger-related costs paid in 2012, partially offset by an increase in Pension Plan cash contributions.

·

In 2013, we issued $1.68 billion of new long-term debt consisting of $750 million by NU parent, $400 million by CL&P, $200 million by NSTAR Electric, $250 million by PSNH, and $80 million by WMECO.  These new issuances were used primarily to repay approximately $928 million of existing long-term debt and PCRBs.  On January 2, 2014, Yankee Gas issued $100 million of new long-term debt.  As of December 31, 2013, approximately $502 million of NU's current liabilities relate to long-term debt that will be paid in the next 12 months.  

·

On February 4, 2014, our Board of Trustees approved a common dividend payment of $0.3925 per share, payable on March 31, 2014 to shareholders of record as of March 3, 2014.  The dividend represented an increase of 6.8 percent over the quarterly dividend paid in December 2013.

33

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 2013, 2012 and 2011 is as follows:

		For the Years Ended December 31,
(Millions of Dollars, Except Per Share Amounts)		2013						2012 (1)						2011
		Amount			Per Share			Amount			Per Share			Amount			Per Share
Net Income Attributable to Controlling Interest (GAAP)		$	786.0		$	2.49		$	525.9		$	1.89		$	394.7		$	2.22
Regulated Companies		$	774.9		$	2.45		$	626.0		$	2.25		$	438.3		$	2.46
NU Parent and Other Companies			24.9			0.08			7.5			0.03			(14.4)			(0.08)
Non-GAAP Earnings			799.8			2.53			633.5			2.28			423.9			2.38
Integration and Merger-Related Costs (after-tax)			(13.8)			(0.04)			(107.6)			(0.39)			(11.3)			(0.06)
Storm Fund Reserve			-			-			-			-			(17.9)			(0.10)
Net Income Attributable to Controlling Interest (GAAP)		$	786.0		$	2.49		$	525.9		$	1.89		$	394.7		$	2.22

⁽¹⁾

Results include the operations of NSTAR beginning April 10, 2012.  

The 2013 after-tax integration-related costs consisted of costs incurred for employee severance in connection with ongoing integration, and consulting and retention costs.  The 2012 after-tax merger-related costs consisted of Regulated companies’ charges of $53.2 million (for further information, see the Regulated Companies portion of this Overview section), costs of $34 million at NU parent related to investment advisory fees, attorney fees, and consulting costs, an $11.5 million charge related to change in control costs and other compensation costs at NU parent, and an $8.9 million charge at NU parent for the establishment of a fund to advance Connecticut energy goals related to the Connecticut merger settlement agreement.

Excluding the impact of the integration and merger-related costs, our 2013 earnings increased by $166.3 million, as compared to 2012, due primarily to the inclusion of NSTAR beginning April 10, 2012, lower overall operations and maintenance costs, higher retail electric and firm natural gas sales, higher transmission segment earnings as a result of increased investments in the transmission infrastructure, and the favorable impact of a lower effective tax rate in 2013 at NU parent.  Partially offsetting these favorable earnings impacts were higher depreciation and property tax expense and the establishment of an after-tax reserve of $14.3 million for a potential customer refund related to an August 2013 initial decision from the FERC ALJ.  For further information, see "FERC Regulatory Issues - FERC Base ROE Complaint" in this Management's Discussion and Analysis.

Regulated Companies:  Our Regulated companies consist of the electric distribution, transmission, and natural gas distribution segments.  Generation activities of PSNH and WMECO are included in our electric distribution segment.  A summary of our segment earnings for 2013, 2012 and 2011 is as follows:

	For the Years Ended December 31,
(Millions of Dollars)	2013			2012 (1)			2011
Net Income – Regulated Companies (GAAP)	$	774.9		$	572.8		$	420.4
Electric Distribution	$	427.0		$	343.4		$	207.0
Transmission		287.0			249.7			199.6
Natural Gas Distribution		60.9			32.9			31.7
Net Income – Regulated Companies (Non-GAAP)		774.9			626.0			438.3
Merger-Related Costs (after-tax) (2)		-			(53.2)			-
Storm Fund Reserve (3)		-			-			(17.9)
Net Income - Regulated Companies (GAAP)	$	774.9		$	572.8		$	420.4

⁽¹⁾

Results include the operations of NSTAR beginning April 10, 2012.  

⁽²⁾

Merger-related 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.  

The 2012 after-tax merger-related costs consisted of $27.6 million ($46 million pre-tax) in charges at CL&P, NSTAR Electric, NSTAR Gas and WMECO for customer bill credits related to the Connecticut and Massachusetts merger settlement agreements, a $23.6 million ($40 million pre-tax) charge related to the Connecticut merger settlement agreement, whereby CL&P agreed to forego recovery of previously deferred storm restoration costs associated with Tropical Storm Irene and the October 2011 snowstorm, and a $2 million charge related to change in control costs and other compensation costs.

Excluding the impact of the merger-related costs, our electric distribution segment earnings increased in 2013, as compared to 2012, due primarily to the inclusion of NSTAR Electric distribution business’ earnings, lower overall operations and maintenance costs and higher retail electric sales due primarily to colder weather in the first and fourth quarters of 2013, as compared to the same periods in 2012.  The 2013 results were also favorably impacted by PSNH rate increases effective July 1, 2012 and July 1, 2013 as a result of the 2010 distribution rate case settlement.  Partially offsetting these favorable earnings impacts were higher depreciation and property tax expense.

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Our transmission segment earnings increased in 2013, as compared to 2012, due primarily to the inclusion of NSTAR Electric transmission business’ earnings, increased investments in our transmission infrastructure, including GSRP, and the favorable impact of a lower effective tax rate in 2013, partially offset by the $14.3 million after-tax reserve related to the August 2013 FERC ALJ initial decision.

Excluding the impact of the merger-related costs, our natural gas distribution segment earnings increased in 2013, as compared to 2012, due primarily to the inclusion of NSTAR Gas’ earnings, higher firm natural gas sales due primarily to colder weather in the first and fourth quarters of 2013, as compared to the same periods in 2012, as well as the addition of approximately 10,000 new natural gas heating customers in 2013, and the favorable impact related to an increase in Yankee Gas rates effective July 1, 2012 as a result of the Yankee Gas 2011 rate case decision.  

A summary of our retail electric GWh sales and percentage changes, assuming NSTAR Electric had been part of the NU electric distribution system for all periods, as well as percentage changes in CL&P, NSTAR Electric, PSNH and WMECO retail electric GWh sales, is as follows:

	For the Year Ended December 31, 2013 Compared to 2012
	Sales (GWh)
NU - Electric	2013		2012 (1)		Percentage Increase/ (Decrease)
Residential	21,896		21,374		2.4 %
Commercial (2)	27,787		27,647		0.5 %
Industrial	5,648		5,787		(2.4)%
Total	55,331		54,808		1.0 %

	For the Year Ended December 31, 2013 Compared to 2012
	CL&P		NSTAR Electric		PSNH		WMECO
Electric	Percentage Increase/ (Decrease)		Percentage Increase/ (Decrease)		Percentage Increase		Percentage Increase/ (Decrease)
Residential	3.4 %		1.3 %		2.2%		1.7 %
Commercial (2)	0.7 %		0.4 %		0.6%		(0.4)%
Industrial	(4.4)%		(3.0)%		2.1%		(3.0)%
Total	1.3 %		0.5 %		1.5%		- %

⁽¹⁾

Results include retail electric sales of NSTAR Electric from January 1, 2012 through December 31, 2012 for comparative purposes only.  

⁽²⁾

Commercial retail electric GWh sales include streetlighting and railroad retail sales.

A summary of our firm natural gas sales in million cubic feet and percentage changes, assuming NSTAR Gas had been part of the NU natural gas distribution system for all periods, as well as percentage changes in Yankee Gas and NSTAR Gas, for 2013, as compared to 2012, is as follows:

	For the Year Ended December 31, 2013 Compared to 2012
	Sales (million cubic feet)				Percentage
NU - Firm Natural Gas	2013		2012 (1)		Increase
Residential	36,777		30,873		19.1%
Commercial	40,215		35,662		12.8%
Industrial	21,266		20,992		1.3%
Total	98,258		87,527		12.3%
Total, Net of Special Contracts (2)	94,083		81,772		15.1%

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	For the Year Ended December 31, 2013 Compared to 2012
	Sales (million cubic feet)
	Yankee Gas		NSTAR Gas (3)
	Percentage		Percentage
Firm Natural Gas	Increase/(Decrease)		Increase
Residential	19.0 %		19.2%
Commercial	13.9 %		11.8%
Industrial	(1.9)%		10.9%
Total	9.8 %		14.9%
Total, Net of Special Contracts (2)	15.3 %

⁽¹⁾

Results include firm natural gas sales of NSTAR Gas from January 1, 2012 through December 31, 2012 for comparative purposes only.

⁽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, 2013 compared to 2012 has been provided for comparative purposes only.

Weather, fluctuations in energy supply costs, conservation measures (including company-sponsored energy efficiency programs), and economic conditions affect customer energy usage.  Industrial sales are less sensitive to temperature variations than residential and commercial sales.  In our service territories, weather impacts electric sales during the summer and electric and natural gas sales during the winter (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.  In addition, our electric and natural gas businesses are susceptible to damage from major storms and other natural events and disasters that could adversely affect our ability to provide energy.

Our 2013 consolidated retail electric sales were higher, as compared to 2012, due primarily to colder weather in the first and fourth quarters of 2013.  The 2013 retail electric sales for CL&P, NSTAR Electric and PSNH increased while they remained unchanged for WMECO, as compared to 2012, due primarily to colder weather in the first and fourth quarters of 2013.  In 2013, heating degree days were 17 percent higher in Connecticut and western Massachusetts, 16 percent higher in the Boston metropolitan area, and 15 percent higher in New Hampshire, and cooling degree days were 7 percent lower in Connecticut and western Massachusetts, 2 percent higher in the Boston metropolitan area, and 9 percent lower in New Hampshire, as compared to 2012.  On a weather-normalized basis (based on 30-year average temperatures), 2013 retail electric sales for CL&P and PSNH increased, while they decreased for NSTAR Electric and WMECO, as compared to 2012.  The 2013 weather-normalized NU consolidated total retail electric sales remained relatively unchanged, as compared to 2012.

For WMECO, fluctuations in retail electric sales do not impact earnings due to the DPU-approved revenue decoupling mechanism.  Under this decoupling mechanism, WMECO has an overall fixed annual level of distribution delivery service revenues of $132.4 million, comprised of customer base rate revenues of $125.4 million and a baseline low income discount recovery of $7 million.  These two mechanisms effectively break the relationship between sales volume and revenues recognized.

Our 2013 consolidated firm natural gas sales are subject to many of the same influences as our retail electric sales, but have benefitted from favorable natural gas prices and customer growth across all three customer classes.  Our 2013 consolidated firm natural gas sales were higher, as compared to 2012, due primarily to colder weather in the first and fourth quarters of 2013.  The 2013 weather-normalized NU consolidated total firm natural gas sales increased 0.9 percent, as compared to 2012, due primarily to residential customer growth, an increase in natural gas conversions, the migration of interruptible customers switching to firm service rates, and the addition of gas-fired distributed generation, all of which was primarily in the Yankee Gas service territory.

NU Parent and Other Companies:  NU parent and other companies (which includes certain subsidiaries of NSTAR beginning April 10, 2012, and our competitive businesses held by NU Enterprises) earned $11.1 million in 2013, compared with net losses of $46.9 million in 2012.  Excluding the impact of integration and merger-related costs of $13.8 million in 2013 and $54.4 million in 2012, NU parent and other companies earned $24.9 million in 2013, compared with $7.5 million in 2012.  Improved 2013 results were due primarily to a lower effective tax rate, a decrease in interest expense at NU parent, and an increase in earnings at the unregulated businesses.

Future Outlook

2014 EPS Guidance:  We currently project 2014 earnings of between $2.60 and $2.75 per share.

Liquidity

Consolidated:  Cash and cash equivalents totaled $43.4 million as of December 31, 2013, compared with $45.7 million as of December 31, 2012.

CL&P issued $400 million of 2.5 percent 2013 Series A First and Refunding Mortgage Bonds on January 15, 2013, due to mature in 2023.  The proceeds, net of issuance costs, were used to pay short-term borrowings outstanding under the CL&P credit agreement of $89 million and intercompany loans related to our commercial paper program of $305.8 million.  On September 3, 2013, CL&P

36

redeemed at par $125 million of 1.25 percent Series B 2011 PCRBs, which were subject to mandatory tender for purchase, using short-term debt.  

NSTAR Electric issued $200 million of three-year floating rate debentures on May 17, 2013, due to mature in 2016.  The proceeds, net of issuance costs, were used to pay short-term borrowings and for general corporate purposes.

PSNH redeemed at par approximately $109 million of the 5.45 percent 2001 Series C PCRBs on May 1, 2013, which were due to mature in 2021, using short-term debt.  On November 14, 2013, PSNH issued $250 million of 3.50 percent Series S First Mortgage Bonds, due to mature in 2023.  On December 23, 2013, PSNH redeemed approximately $89 million of the 4.75 percent Series B PCRBs, which were due to mature in 2021, using a portion of the proceeds from the Series S First Mortgage Bonds.  The remaining Series S First Mortgage Bond proceeds were used to pay short-term borrowings.

WMECO repaid at maturity $55 million of 5 percent Series A Senior Notes on September 1, 2013, using short-term debt.  On November 15, 2013, WMECO issued $80 million of 3.88 percent Series G Senior Notes, due to mature in 2023.  The proceeds, net of issuance costs, were used to pay short-term borrowings and for other working capital purposes.  

NU parent issued $750 million of Senior Notes on May 13, 2013, consisting of $300 million of 1.45 percent Series E Senior Notes, due to mature in 2018, and $450 million of 2.80 percent Series F Senior Notes, due to mature in 2023.  The proceeds, net of issuance costs, were used to repay the NU parent $250 million 5.65 percent Series C Senior Notes that matured on June 1, 2013 and the NU parent $300 million floating rate Series D Senior Notes that matured on September 20, 2013.  The remaining net proceeds were used to repay commercial paper program borrowings and for working capital purposes.

Yankee Gas issued $100 million of 4.82 percent Series L First Mortgage Bonds on January 2, 2014, due to mature in 2044.  The proceeds, net of issuance costs, were used to repay the $75 million 4.80 percent Series G First Mortgage Bonds that matured on January 1, 2014 and to pay $25 million in short-term borrowings.

On July 31, 2013, the FERC granted authorization allowing CL&P and WMECO to incur total short-term borrowings up to a maximum of $600 million and $300 million, respectively, effective January 1, 2014 through December 31, 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 December 23, 2013, the DPU authorized NSTAR Electric to issue up to $800 million in long-term debt for the two-year period ending December 31, 2015.  On September 26, 2013, the NHPUC issued an order, effective October 8, 2013, approving PSNH's request to issue up to $315 million in long-term debt through December 31, 2014, and to refinance approximately $89 million Series B PCRBs through its existing maturity of May 2021.  

On September 6, 2013, NU parent, CL&P, PSNH, WMECO, NSTAR Gas and Yankee Gas amended their joint five-year $1.15 billion revolving credit facility, dated July 25, 2012, by increasing the aggregate principal amount available thereunder by $300 million to $1.45 billion, extending the expiration date from July 25, 2017 to September 6, 2018, and increasing CL&P's borrowing sub-limit from $300 million to $600 million.  PSNH and WMECO each have borrowing sub-limits of $300 million.  Simultaneously, effective September 6, 2013, the CL&P $300 million revolving credit facility was terminated.

On September 6, 2013, NSTAR Electric amended its five-year $450 million revolving credit facility, dated July 25, 2012, by extending the expiration date from July 25, 2017 to September 6, 2018.  

On September 6, 2013, NU parent’s $1.15 billion commercial paper program was increased by $300 million to $1.45 billion.

As of December 31, 2013, NU had approximately $1.01 billion in short-term borrowings outstanding under its commercial paper program, leaving $435.5 million of available borrowing capacity.  The weighted-average interest rate on these borrowings as of December 31, 2013 was 0.24 percent, which is generally based on money market rates.  As of December 31, 2013, NSTAR Electric had $103.5 million in short-term borrowings outstanding under its commercial paper program, leaving $346.5 million of available borrowing capacity.  The weighted-average interest rate on these borrowings as of December 31, 2013 was 0.13 percent, which is generally based on money market rates.  

Each of NU, CL&P, NSTAR Electric, PSNH and WMECO use its available capital resources to fund its respective construction expenditures, meet debt requirements, pay operating 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 recover its electric and natural gas distribution construction expenditures as the related project costs are depreciated over the life of the assets.  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 current liabilities exceeding current assets by approximately $1.2 billion, $398 million and $339 million at NU, CL&P and NSTAR Electric, respectively, as of December 31, 2013.

As of December 31, 2013, $501.7 million of NU's obligations classified as current liabilities relates to long-term debt that will be paid in the next 12 months, consisting of $150 million for CL&P, $301.7 million for NSTAR Electric and $50 million for PSNH.  In addition, $31.7 million relates to the amortization of the purchase accounting fair value adjustment that will be amortized in the next twelve months.  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, PSNH and WMECO will reduce their short-term borrowings with cash

37

received from operating cash flows or with the issuance of new long-term debt, determined considering capital requirements and maintenance of NU's credit rating and profile.  Management expects the future operating cash flows of NU, CL&P, NSTAR Electric, PSNH and WMECO, along with the access to financial markets, will be sufficient to meet any future operating requirements and capital investment forecasted opportunities.

On March 15, 2013, NSTAR Electric made its final principal and interest payment on approximately $675 million of RRBs that were issued in March 2005.  On May 1, 2013, PSNH made its final principal and interest payment on approximately $525 million of RRBs that were issued in April 2001.  On June 1, 2013, WMECO made its final principal and interest payment on approximately $155 million of RRBs that were issued in May 2001.  As a result, NSTAR Electric, PSNH and WMECO are no longer recovering any payments from customers associated with these RRBs, which reduced NSTAR Electric’s, PSNH’s and WMECO’s cash flows provided by operating activities in 2013, compared with 2012.  There was no impact on operating cash flows net of RRB payments.

Cash flows provided by operating activities totaled $1.58 billion in 2013, compared with $1.05 billion in 2012 and $901.1 million in 2011 (all amounts are net of RRB payments, which are included in financing activities on the accompanying statements of cash flows).  The improved operating cash flows were due primarily to the addition of NSTAR, which contributed $138.1 million of operating cash flows (net of RRB payments) in the first quarter of 2013, a decrease of approximately $100 million in cash disbursements for storm restoration costs associated primarily with the February 2013 blizzard, as compared to 2012 cash disbursements for storm restoration costs associated primarily with Tropical Storm Irene and the October 2011 snowstorm, the absence in 2013 of $73 million in 2012 cash disbursements at CL&P, NSTAR Electric, NSTAR Gas and WMECO related to customer bill credits, and the absence in 2013 of $35 million of merger-related cash payments made in 2012.  In addition, operating cash flows benefited from an increase in amortization of regulatory deferrals primarily attributable to tracking mechanisms where such revenues exceeded costs resulting in a favorable cash flow impact.  Partially offsetting these favorable cash flow impacts was a $62.3 million increase in Pension Plan cash contributions, increases in coal and fuel inventories, and changes in traditional working capital amounts due primarily to the timing of accounts receivable and accounts payable.  The improved operating cash flows in 2012, compared with 2011, were due primarily to the addition of NSTAR, partially offset by an increase in storm restoration costs, pension plan cash contributions, customer bill credits, and merger-related costs.

A summary of our corporate credit ratings and outlooks by Moody's, S&P and Fitch is as follows:

Moody's

S&P

Fitch

Current

Outlook

Current

Outlook

Current

Outlook

NU Parent

Baa1

Stable

A-

Stable

BBB+

Stable

CL&P

Baa1

Stable

A-

Stable

BBB+

Stable

NSTAR Electric

A2

Stable

A-

Stable

A

Stable

PSNH

Baa1

Stable

A-

Stable

BBB+

Stable

WMECO

A3

Stable

A-

Stable

BBB+

Stable

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

Baa1

Stable

BBB+

Stable

BBB+

Stable

CL&P

A2

Stable

A

Stable

A

Stable

NSTAR Electric

A2

Stable

A-

Stable

A+

Stable

PSNH

A2

Stable

A

Stable

A

Stable

WMECO

A3

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.  On January 31, 2014, Moody's upgraded corporate credit and securities ratings of NU, CL&P and PSNH by one level and WMECO by two-levels.

We paid common dividends of $462.7 million in 2013, compared with $375 million in 2012.  The increase was due primarily to the issuance of approximately 136 million of NU common shares to the NSTAR shareholders on April 10, 2012 as a result of the merger, and an increase of approximately 7.1 percent in our common dividend paid beginning in March 2013.  On February 4, 2014, our Board of Trustees approved a common dividend payment of $0.3925 per share, payable on March 31, 2014 to shareholders of record as of March 3, 2014.  The dividend represented an increase of 6.8 percent over the dividend paid in December 2013.

CL&P, NSTAR Electric, PSNH, and WMECO paid $152 million, $56 million, $68 million, and $40 million, respectively, in common dividends to their respective parent company in 2013.  

Investments in Property, Plant and Equipment on the accompanying statements of cash flows do not include amounts incurred on capital projects but not yet paid, cost of removal, AFUDC related to equity funds, and, for certain subsidiaries, the capitalized portions of pension expense.  In 2013, investments for NU, CL&P, NSTAR Electric, PSNH, and WMECO were $1.5 billion, $434.9 million, $476.6 million, $186 million, and $128.8 million, respectively.  

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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 expense (all of which are non-cash factors), totaled $1.6 billion in 2013, $1.5 billion in 2012, and $1.2 billion in 2011.  These amounts included $44.7 million in 2013, $43.1 million in 2012, and $51.9 million in 2011, related to our corporate service companies, NUSCO and RRR.

Transmission Business:  Overall, transmission business capital expenditures increased by $10.5 million in 2013, as compared with 2012, due primarily to the addition of NSTAR Electric's capital expenditures, partially offset by the completion of the WMECO portion of GSRP.  A summary of transmission capital expenditures by company in 2013, 2012 and 2011 is as follows:  

		For the Years Ended December 31,
(Millions of Dollars)		2013			2012 (1)			2011
CL&P		$	211.9		$	182.5		$	128.6
NSTAR Electric			220.8			160.7			N/A
PSNH			99.7			55.7			68.1
WMECO			87.2			214.7			236.8
NPT			39.9			35.4			25.9
Total Transmission Segment		$	659.5		$	649.0		$	459.4

⁽¹⁾

Results include the transmission capital expenditures of NSTAR Electric beginning April 10, 2012.  

NEEWS:  GSRP, the first, largest and most complicated project within the NEEWS family of projects was fully energized on November 20, 2013.  The project involved the construction of 115 kV and 345 kV overhead lines by CL&P and WMECO from Ludlow, Massachusetts to Bloomfield, Connecticut.  This transmission upgrade ensures the reliable flow of power in and around the southern New England area and enables access to less expensive generation, further reducing the risk of congestion costs impacting New England customers.  The project was fully energized ahead of schedule with a final cost of $676 million, $42 million under the $718 million estimated cost.  As of December 31, 2013, CL&P and WMECO have placed $628.2 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 the second major NEEWS project.  All siting applications have been filed by CL&P and National Grid.  The Connecticut and Rhode Island portions of the project have been approved and a siting approval decision in Massachusetts is expected in early 2014.  On February 12, 2014, the Army Corps of Engineers issued its permit enabling construction on the Connecticut portion of the project.  This is the final permit for the Connecticut portion of the project.  NU’s portion of the cost is estimated to be $218 million and the project is expected to be placed in service in late 2015.

The Greater Hartford Central Connecticut Study (GHCC), which includes the reassessment of the Central Connecticut Reliability Project, continues to make progress.  The final need results, which were presented to the ISO-NE Planning Advisory Committee in November 2013, showed existing and worsening severe regional and local thermal overloads and voltage violations within and across each of the four study areas.  ISO-NE is expected to confirm the preferred transmission solutions in the first half of 2014, which are likely to include many 115 kV upgrades.  We continue to expect that the specific future projects being identified to address these reliability concerns will cost approximately $300 million and that the project will be placed in service in 2017.  

Included as part of NEEWS are associated reliability related projects, $90.8 million of which have been placed in service.  As of December 31, 2013, the remaining construction on the associated reliability related projects totaled $2.8 million, which is scheduled to be completed by mid-2014.   

Through December 31, 2013, CL&P and WMECO capitalized $252.8 million and $567 million, respectively, in costs associated with NEEWS, of which $40.8 million and $48.9 million, respectively, were capitalized in 2013.    

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 crosses the Cape Cod Canal and associated 115 kV upgrades in the center of Cape Cod (Lower SEMA Project) and related 115 kV projects (Mid-Cape Project).  The Lower SEMA Project line work was completed and placed into service in 2013.  The Mid-Cape Project is scheduled to be completed in 2017.  The aggregate estimated construction cost for the Cape Cod projects is expected to be approximately $150 million.  Through December 31, 2013, NSTAR Electric has invested $96 million in costs associated with the Cape Cod Reliability Projects, of which $61 million was capitalized in 2013.  

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.  The $1.4 billion project is subject to comprehensive federal and state public permitting processes and is expected to be operational by mid-2017.  On July 1, 2013, NPT filed an amendment to the DOE Presidential Permit Application for a proposed improved route in the northernmost section of the project area.  As of December 31, 2013, the DOE had completed its public scoping meeting process and the majority of its seasonal field work and environmental data collection.  NPT expects to file its state permit application in the fourth quarter of 2014 after the DOE’s draft Environmental Impact Statement (EIS) is received.  

39

NPT filed an amendment to the Transmission Services Agreement (TSA) with FERC on December 11, 2013, which was accepted by the FERC on January 13, 2014.  The TSA amendment that went into effect on February 14, 2014 extended certain deadlines to provide project flexibility and eliminated a penalty payment for termination of the project in the future.  

On December 31, 2013, NPT received ISO-NE approval under Section I.3.9 of the ISO tariff.  By approving the project’s Section I.3.9 application, ISO-NE determined that Northern Pass can reliably interconnect with the New England grid with no significant, adverse effect on the reliability or operating characteristics of the regional energy grid and its participants.  

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 expect projected costs to be approximately $440 million on these new initiatives.  

Distribution Business:  A summary of distribution capital expenditures by company for 2013, 2012 and 2011 is as follows:

	For the Years Ended December 31,
(Millions of Dollars)	2013			2012 (1)			2011
CL&P:
Basic Business	$	60.9		$	69.2		$	166.6
Aging Infrastructure		160.7			177.8			112.3
Load Growth		76.9			65.8			59.6
Total CL&P		298.5			312.8			338.5
NSTAR Electric:
Basic Business		98.5			47.3			N/A
Aging Infrastructure		110.6			111.5			N/A
Load Growth		53.6			17.4			N/A
Total NSTAR Electric		262.7			176.2			N/A
PSNH:
Basic Business		22.7			25.3			47.7
Aging Infrastructure		50.5			50.2			25.3
Load Growth		29.3			20.2			25.8
Total PSNH		102.5			95.7			98.8
WMECO:
Basic Business		7.9			12.7			24.2
Aging Infrastructure		24.6			18.5			11.5
Load Growth		9.2			6.5			6.1
Total WMECO		41.7			37.7			41.8
Total - Electric Distribution (excluding Generation)		705.4			622.4			479.1
Total - Natural Gas		175.2			162.9			102.8
Other Distribution		0.7			0.1			1.0
Total Electric and Natural Gas		881.3			785.4			582.9
PSNH Generation:
Clean Air Project		-			22.0			101.1
Other		9.7			7.9			23.7
Total PSNH Generation		9.7			29.9			124.8
WMECO Generation		4.5			0.7			11.7
Total Distribution Segment	$	895.5		$	816.0		$	719.4

⁽¹⁾

Results include the electric and natural gas distribution capital expenditures of NSTAR beginning April 10, 2012.  

 

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

CL&P System Resiliency Plan:  In accordance with the PURA-approved System Resiliency Plan, CL&P will spend approximately $300 million to improve the resiliency of its electric distribution system, which includes vegetation management.  CL&P expects to complete the plan in five years in two separate phases.  Costs of Phase 1 of the plan, which is primarily focused on vegetation management, totaled approximately $32 million in 2013 and is estimated to cost $53 million in 2014.  Phase 2 of the plan is estimated to cost approximately $215 million over the period from 2015 through 2017.

WMECO Solar Project: On September 4, 2013, the DPU approved WMECO's proposal to build a third solar generation facility and expand its solar energy portfolio from 6 MW to 8 MW.  On October 22, 2013, WMECO announced it would install a 3.9 MW solar generation facility on a site in East Springfield, Massachusetts.  The facility is expected to be completed in mid-2014 at an estimated cost of approximately $15 million.

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Yankee Gas Expansion Plan:  In accordance with 2013 Connecticut law and regulation, on June 14, 2013, Yankee Gas and other Connecticut natural gas distribution companies filed a comprehensive joint natural gas infrastructure expansion plan (expansion plan) with DEEP and PURA.  The expansion plan described how Yankee Gas expects to add approximately 82,000 new natural gas heating customers over the next 10 years.  Yankee Gas estimates that its portion of the plan will cost approximately $700 million over 10 years.  For further information on the expansion plan, see "Regulatory Developments and Rate Matters - Connecticut - Yankee Gas Natural Gas Expansion Plan" in this Management’s Discussion and Analysis.  For further information on the Connecticut law, see "Legislative and Policy Matters - Connecticut" in this Management’s Discussion and Analysis.

Projected Capital Expenditures:  A summary of the projected capital expenditures for the Regulated companies' electric transmission and for the total electric distribution, generation, and natural gas distribution businesses for 2014 through 2017, including our corporate service companies' capital expenditures on behalf of the Regulated companies, is as follows:

	Year
(Millions of Dollars)	2014			2015			2016			2017			2014-2017 Total
CL&P Transmission	$	247		$	199		$	178		$	165		$	789
NSTAR Electric Transmission		191			250			285			202			928
PSNH Transmission		106			124			123			42			395
WMECO Transmission		73			85			49			2			209
NPT		47			222			610			487			1,366
Total Transmission	$	664		$	880		$	1,245		$	898		$	3,687
Electric Distribution	$	679		$	647		$	647		$	619		$	2,592
Generation		24			34			20			15			93
Natural Gas		189			219			201			227			836
Total Distribution	$	892		$	900		$	868		$	861		$	3,521
Corporate Service Companies	$	117		$	93		$	76		$	76		$	362
Total	$	1,673		$	1,873		$	2,189		$	1,835		$	7,570

Actual capital expenditures could vary from the projected amounts for the companies and years 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 NETOs, 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 October 1, 2011.  In response, the NETOs filed testimony and analysis based on standard FERC methodology and precedent demonstrating that the base ROE of 11.14 percent remained just and reasonable.  The FERC set the case for trial before a FERC ALJ after settlement negotiations were unsuccessful in August 2012.

Hearings before the FERC ALJ were held in May 2013, followed by the filing of briefs by the complainants, the Massachusetts municipal electric utilities (late interveners to the case), the FERC trial staff and the NETOs.  The NETOs recommended that the current base ROE of 11.14 percent should remain in effect for the refund period (October 1, 2011 through December 31, 2012) and the prospective period (beginning when FERC issues its final decision).  The complainants, the Massachusetts municipal electric utilities, and the FERC trial staff each recommended a base ROE of 9 percent or below.

On August 6, 2013, the FERC ALJ issued an initial decision, finding that the base ROE in effect from October 2011 through December 2012 was not reasonable under the standard application of FERC methodology, but leaving policy considerations and additional adjustments to the FERC.  Using the established FERC methodology, the FERC ALJ determined that separate base ROEs should be set for the refund period and the prospective period.  The FERC ALJ found those base ROEs to be 10.6 percent and 9.7 percent, respectively.  The FERC may adjust the prospective period base ROE in its final decision to reflect movement in 10-year Treasury bond rates from the date that the case was filed (April 2013) to the date of the final decision.  The parties filed briefs on this decision with the FERC, and a decision from the FERC is expected in 2014.  Though NU cannot predict the ultimate outcome of this proceeding, in 2013 the Company recorded a series of reserves at its electric subsidiaries to recognize the potential financial impact from the FERC ALJ's initial decision for the refund period.  The aggregate after-tax charge to earnings totaled $14.3 million at NU, which represents reserves of $7.7 million at CL&P, $3.4 million at NSTAR Electric, $1.4 million at PSNH and $1.8 million at WMECO.

On December 27, 2012, several additional parties filed a separate complaint concerning the NETOs' base ROE with the FERC.  This complaint seeks to reduce the NETOs’ base ROE effective January 1, 2013, effectively extending the refund period for an additional 15 months, and to consolidate this complaint with the joint complaint filed on September 30, 2011.  The NETOs have asked the FERC to reject this complaint.  The FERC has not yet acted on this complaint, and management is unable to predict the ultimate outcome or estimate the impacts of this complaint on the financial position, results of operations or cash flows.

As of December 31, 2013, the CL&P, NSTAR Electric, PSNH, and WMECO aggregate shareholder equity invested in their transmission facilities was approximately $2.3 billion.  As a result, each 10 basis point change in the prospective period authorized base ROE would change annual consolidated earnings by an approximate $2.3 million.

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Regulatory Developments and Rate Matters

Electric and Natural Gas Base Distribution Rates:  

Each NU utility subsidiary is subject to the regulatory jurisdiction of the state in which it operates:  CL&P and Yankee Gas operate in Connecticut and are subject to PURA regulation; NSTAR Electric, WMECO and NSTAR Gas operate in Massachusetts and are subject to DPU regulation; and PSNH operates in New Hampshire and is subject to NHPUC regulation.  

In Connecticut, pursuant to the April 2012 PURA-approved Connecticut merger settlement agreement, CL&P is subject to a base distribution rate freeze until December 1, 2014.  Yankee Gas distribution rates were established in a 2011 PURA approved rate case.  See Connecticut - Yankee Gas Distribution Rate Case in this Regulatory Developments and Rate Matters section for further information.  

In Massachusetts, "An Act Relative to Competitively Priced Electricity in the Commonwealth" (Energy Act), which was enacted in 2012, requires electric utility companies to file at least one distribution rate case every five years and natural gas companies to file at least one distribution rate case every 10 years, and limits those companies to one settlement agreement in any 10-year period.  Pursuant to the April 2012 DPU-approved Massachusetts comprehensive merger settlement agreements, NSTAR Electric, WMECO and NSTAR Gas are subject to a base distribution rate freeze through December 31, 2015.  

In New Hampshire, PSNH is currently operating under the 2010 NHPUC approved distribution rate case settlement, which is effective through June 30, 2015.  Under the settlement, PSNH is permitted to file a request to collect certain exogenous costs and step increases on an annual basis.  See New Hampshire - Distribution Rates in this Regulatory Developments and Rate Matters section for further information.

As a result of the PURA-approved Connecticut merger settlement agreement, we expect to file a CL&P base distribution rate proceeding in mid-2014 with base distribution rates effective December 1, 2014.  The exact timing of the base distribution rate proceedings for our other utility subsidiaries has not yet been determined.  

Major Storms:

2013, 2012 and 2011 Major Storms:  Over the past three years, CL&P, NSTAR Electric, PSNH and WMECO each experienced significant storms, including Tropical Storm Irene, the October 2011 snowstorm, Storm Sandy, and the February 2013 blizzard.  As a result of these storms, each electric utility company suffered damage to its distribution and transmission systems, which caused customer outages and required the incurrence of costs to repair significant damage and restore customer service.  

The magnitude of these storm restoration costs met the criteria for cost deferral in Connecticut, Massachusetts, and New Hampshire.  As a result, the storms had no material impact on the results of operations of CL&P, NSTAR Electric, PSNH and WMECO.  We believe our response to each of these 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 electric utility company is seeking recovery of its deferred storm restoration costs through its applicable regulatory recovery process.  

CL&P 2013 Storm Filing:  In March 2013, CL&P filed a request with PURA for approval to recover storm restoration costs associated with five major storms, all of which occurred in 2011 and 2012.  CL&P's deferred storm restoration costs associated with these major storms totaled $462 million.  Of that amount, approximately $414 million is subject to recovery in rates after giving effect to CL&P’s agreement to forego the recovery of $40 million of previously deferred storm restoration costs as well as an existing storm reserve fund balance of approximately $8 million.  During the second half of 2013, the PURA proceeded with the storm recovery review issuing discovery, holding hearings and ultimately on February 3, 2014, issuing a draft decision on the level of storm costs recovery.

In its draft decision, the PURA approved recovery of $365 million of deferred storm restoration costs and ordered CL&P to capitalize approximately $18 million of the deferred storm restoration costs as utility plant, which will be included in depreciation expense in future rate proceedings.  PURA will allow recovery of the $365 million with carrying charges in CL&P’s distribution rates over a six-year period beginning December 1, 2014.  The remaining costs were either disallowed or are probable of recovery in future rates and did not have a material impact on CL&P’s financial position, results of operations or cash flows.  The final decision is expected from PURA in the first quarter of 2014.

NSTAR Electric 2013 Storm Filing:  On December 30, 2013, the DPU approved NSTAR Electric’s request to recover storm restoration costs, plus carrying costs, related to Tropical Storm Irene and the October 2011 snowstorm.  The DPU approved recovery of $34.2 million of the $38 million requested costs.  NSTAR Electric will recover these costs, plus carrying costs, in its distribution rates over a five-year period that commenced on January 1, 2014.

PSNH Major Storm Cost Reserve:  On June 27, 2013, the NHPUC approved an increase to PSNH’s distribution rates effective July 1, 2013 that included a $5 million increase to the current level of funding for the major storm cost reserve.

WMECO SRRCA Mechanism:  WMECO has an established Storm Reserve Recovery Cost Adjustment (SRRCA) mechanism to recover the restoration costs associated with its major storms.  Effective January 1, 2012, WMECO began recovering the restoration costs of Tropical Storm Irene and other storms that took place prior to August 2011.  On August 30, 2013, WMECO submitted its 2013 Annual SRRCA filing to begin recovering the restoration costs associated with the October 2011 snowstorm and Storm Sandy.  On

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December 20, 2013, the DPU approved the 2013 Annual SRRCA filing for effect on January 1, 2014, subject to further review and reconciliation.

2013, 2012 and 2011 Major Storm Deferrals:  As of December 31, 2013, the storm restoration costs deferred for recovery from customers for major storms that occurred during 2013, 2012 and 2011 at CL&P, NSTAR Electric, PSNH, and WMECO were as follows:

(Millions of Dollars)		2012 and 2011		2013		Total
CL&P		$ 365.0		$ 28.8		$ 393.8
NSTAR Electric		61.3		63.6		124.9
PSNH		33.7		5.3		39.0
WMECO		35.3		-		35.3
Total		$ 495.3		$ 97.7		$ 593.0

DPU Storm Penalties:  Under Massachusetts law and regulation, the DPU has established standards of performance for emergency preparation and restoration of service for electric companies, including required annual ERP filings with the DPU for review and approval.  As a remedy to violations of those standards, the DPU is authorized to levy a penalty not to exceed $250,000 for each violation for each day that the violation persists up to a maximum penalty of $20 million for any related series of violations.  In December 2012, in separate orders issued by the DPU, NSTAR Electric and WMECO each received penalties related to 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, which were refunded to their customers.  In December 2012, NSTAR Electric and WMECO each filed appeals with the SJC arguing the DPU penalties should be vacated.  NSTAR Electric and WMECO filed initial briefs on November 5, 2013.  Oral arguments are scheduled for March 2014.

Emergency Response Plans:  Under Connecticut law and regulation, the PURA has established performance standards that electric and natural gas companies incorporated into their ERPs and operations in 2013.  CL&P and Yankee Gas will be subject to penalties levied by PURA of up to 2.5 percent of annual distribution revenues for failure to meet performance standards.  In 2013, CL&P and Yankee Gas met the established performance standards.   

Connecticut:

CL&P 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, 2014, the PURA approved an increase to CL&P’s energy supply portion of the total average SS rate from 7.638 cents per kWh to 9.152 cents per kWh and the energy supply portion of the total average LRS rate from 6.698 cents per kWh to 10.762 cents per kWh.  These changes were due primarily to the market conditions for the procurement of energy.  The SS and LRS rates reflect CL&P’s costs to procure energy for its customers.  Adjustments to these rates do not impact earnings as CL&P is fully recovering the costs of its SS and LRS services from customers.

CL&P CTA and SBC Reconciliation:  On January 22, 2014, PURA approved CL&P’s 2012 CTA and SBC reconciliation as filed on April 1, 2013, which compared CTA and SBC billed revenues to revenue requirements, as required by PURA.  The 2012 CTA was over recovered by $21.3 million, resulting in a cumulative net under recovered balance of $8.9 million as of December 31, 2012.  The 2012 SBC was over recovered by $19.4 million, resulting in a cumulative net under recovery of $19.7 million as of December 31, 2012.  

CL&P 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 August 1, 2013, CL&P filed with PURA its semi-annual FMCC filing for the period January 1, 2013 through June 30, 2013.  This filing also included the June 30, 2013 through December 31, 2013 projected amounts for informational purposes only.  The filing identified a total net under recovery of $2.7 million for the period.  On February 19, 2014, PURA approved CL&P’s FMCC filing.

CL&P Conservation Adjustment Mechanism:  In 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 those already collected through the statutory charge and the revenues lost because of the expanded energy efficiency programs.  On September 11, 2013, DEEP approved CL&P’s expanded 2014 conservation spending budget of $144.6 million.  The PURA approved a CAM effective January 1, 2014 subject to a future review of its revenue and expense reconciliation filing to be submitted by CL&P.

CL&P Long-Term Wind Contracts:  On September 19, 2013, CL&P, along with another Connecticut utility, signed long-term commitments, as required by regulation, to purchase approximately 250 MW of wind power from a Maine wind farm and 20 MW of solar power from sites in Connecticut, at a combined average price of less than 8 cents per kWh.  On October 23, 2013, PURA issued a final decision accepting the contracts.  The projects are expected to be operational by the end of 2016.  For further information, see "Legislative and Policy Matters - Connecticut" in this Management’s Discussion and Analysis.

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.  For further information, see "Business Development and Capital Expenditures - Distribution Business - CL&P System Resiliency Plan" in this Management’s Discussion and Analysis.

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

Yankee Gas Natural Gas Expansion Plan:  On June 14, 2013, Yankee Gas and other Connecticut natural gas distribution companies filed an expansion plan with DEEP and PURA in response to the Connecticut CES and the recently enacted Connecticut Public Act 13-298, "An Act Concerning Implementation of Connecticut’s Comprehensive Energy Strategy and Various Revisions to the Energy Statutes."  The expansion plan describes how the natural gas distribution companies expect to add approximately 280,000 new natural gas heating customers over the next 10 years.  Yankee Gas will serve approximately 82,000 of those customers.  

The expansion plan outlines a set of comprehensive recommendations, several of which are already incorporated into Public Act 13-298.  Key recommendations include providing more flexibility in the process of adding new customers, establishing new regulatory tools to help fund conversion costs over time, providing for mechanisms for timely recovery of capital investments made by natural gas distribution companies and allowing utilities to secure additional pipeline capacity into Connecticut.  

On July 16, 2013, DEEP issued a determination letter finding the expansion plan was consistent with the CES and requesting certain modifications to be made.  On July 26, 2013, the natural gas distribution companies submitted their responses to DEEP and PURA.  On November 22, 2013, PURA issued a final decision approving the expansion plan consistent with the goals of the CES.  For further information on the Connecticut law, see "Legislative and Policy Matters - Connecticut" in this Management’s Discussion and Analysis.

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).  NSTAR Electric and WMECO fully recover their energy costs through DPU-approved regulatory rate mechanisms.

2014 Annual Reconciliation Filing:  On November 1, 2013, NSTAR Electric and WMECO filed separately their respective 2014 annual cost recovery mechanisms, including the mechanisms to collect the costs to provide retail transmission, energy supply and energy efficiency services to its customers as well as the costs related to pension and other post-retirement employee benefit costs.  The reconciliation filings compared the total revenues to revenue requirements related to these services.  On December 31, 2013, the DPU issued a final decision approving the rates as filed, subject to future review and reconciliation.  As of December 31, 2013, we had cumulative deferred net regulatory asset balances related to these services of $142.1 million and $9.9 million for NSTAR Electric and WMECO, respectively.  

Energy Efficiency Plans:  In accordance with Massachusetts law passed in 2008 known as the Green Communities Act, natural gas and electric distribution companies must file three-year energy efficiency plans, which were initially filed by NSTAR Electric, WMECO and NSTAR Gas, and approved by the DPU, in 2010 covering the period 2010 through 2012.  The NSTAR Electric, WMECO and NSTAR Gas three-year plans covering the period 2013 through 2015 were approved by the DPU in 2013.  Distribution companies that do not yet have rate decoupling mechanisms in place, like NSTAR Electric and NSTAR Gas, include Lost Base Revenue (LBR) rate adjustment mechanisms in order to offset reduced distribution rate revenues as a result of successful energy efficiency programs.  For the year ended December 31, 2013, NSTAR Electric, WMECO and NSTAR Gas incurred recoverable Energy Efficiency program expenses of $167.2 million, $38.9 million, and $31 million, respectively.

Long-Term Wind Contracts: NSTAR Electric and WMECO, along with two other Massachusetts utilities, signed a long-term commitment, as required by regulation, to purchase wind power from six wind farms in Maine and New Hampshire for a combined estimated generating capacity of approximately 565 MW.  On September 20, 2013, these contracts were filed jointly with the DPU.  On November 21, 2013, the utility companies provided a supplemental filing to the DPU to reflect the termination of three of the six wind farms.  Initial briefs were filed on December 23, 2013 and reply briefs were filed on January 8, 2014.  Over the 15-year life of the remaining contracts, the utilities will pay an average price of less than 8 cents per kWh.  The projects are in various stages of permitting or development and are expected to begin operation in 2015 and 2016.

On November 26, 2012, the DPU approved NSTAR Electric’s 15-year renewable energy contract with Cape Wind Associates, LLC.  Under this contract, NSTAR Electric would purchase 129 MW of renewable energy from an offshore wind energy facility, which is currently expected to achieve commercial operation by May 2016.  

DPU Safety and Reliability Programs (CPSL):  Since 2006, NSTAR Electric has been recovering incremental costs related to the DPU-approved Safety and Reliability Programs.  From 2006 through 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).  In October 2010, NSTAR Electric filed a reconciliation of the cumulative CPSL program activity for the periods 2006 through 2009 with the DPU in order to determine a proposed rate adjustment.  The DPU allowed the proposed rates to go into effect January 1, 2011, subject to final

44

reconciliation of CPSL program costs through a future DPU proceeding.  In February 2013, NSTAR Electric updated the October 2010 filing with final activity through 2011.  NSTAR Electric recorded its 2006 through 2011 revenues under the CPSL programs based on the May 2010 Order.  

NSTAR Electric cannot predict the timing of a final DPU order related to its CPSL filings for the period 2006 through 2011.  While we do not believe that any subsequent DPU order would result in revenues that are 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 stipulates that NSTAR Electric must incur a revenue requirement of at least $15 million per year for 2012 through 2015 related to 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, 2013, NSTAR Electric was in compliance with the performance metrics and has recognized the entire $15 million revenue requirement during 2013 and 2012.

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.  In 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.  The DPU issued an order approving the implementation of a revised Basic Service rate but 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.

In 2010, NSTAR Electric filed an appeal of the DPU’s order with the SJC.  In 2012, the SJC vacated the DPU order and remanded the matter to the DPU for further review.  The DPU has not taken any action on the remand.

NSTAR Electric deferred approximately $34 million of costs associated with energy-related bad debt as a regulatory asset through 2011 as NSTAR Electric had concluded that it was probable that these costs would ultimately be recovered from customers.  Due to delays and the duration of the proceedings, 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 related to the regulatory asset in 2012.  NSTAR Electric will continue to maintain the reserve until the proceeding has been concluded with the DPU.

New Hampshire:

Distribution Rates:  In 2013, PSNH filed for a distribution rate step increase in accordance with the 2010 NHPUC approved distribution rate case settlement.  On June 27, 2013, the NHPUC approved an increase to rates of $12.6 million, effective July 1, 2013.  The increase consists primarily of $7.7 million related to net plant additions and a $5 million increase to the current level of funding for the Major Storm Cost reserve.

ES and SCRC Rates:  On December 12, 2013, PSNH filed a request with the NHPUC to adjust its ES and SCRC rates effective January 1, 2014.  PSNH’s request proposed to increase the current ES and SCRC billing rates to reflect projected costs for 2014. On December 27, 2013, the NHPUC approved the request. The approved energy supply portion of the 2014 rate is 9.23 cents per kWh and the SCRC rate for 2014 is 0.35 cents per kWh.

Clean Air Project Prudence Proceeding:  The Clean Air Project, which involved the installation of wet scrubber technology at PSNH’s Merrimack coal-fired generation station in Bow, New Hampshire, was placed in service in September 2011.  In November 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.  In April 2012, the NHPUC issued an order authorizing temporary rates to recover a significant portion of the Clean Air Project costs.  The docket will remain open to conduct a comprehensive prudence review of the Clean Air Project and the establishment of permanent rates.  The temporary rates will remain in effect until permanent rates allowing full recovery of all prudently incurred costs are approved.  At that time, the NHPUC will reconcile recoveries collected under the temporary rates with approved permanent rates.

The NHPUC has issued a series of orders ruling on the scope of its Clean Air Project inquiry and discovery issues.  On December 23, 2013, the NHPUC Staff and other intervenors filed testimony discussing the prudency of the Clean Air Project, which cost $421 million.  Discovery is currently ongoing with hearings likely in late 2014.  We continue to believe that we were prudent in the undertaking and completion of the Clean Air Project.  While we cannot predict with certainty the outcome of the Clean Air Project prudence review, we believe all costs were incurred appropriately and are probable of recovery.

PSNH Generation:  On January 18, 2013, the NHPUC opened a docket to investigate market conditions affecting PSNH’s ES 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.  On July 15, 2013, the NHPUC accepted from the NHPUC Staff a "Report on Investigation into Market Conditions, Default Service Rate, Generation Ownership and Impact on the Competitive Electricity Market."  The report recommended that the NHPUC examine whether default service rates remain sustainable on a going forward basis, define "just and reasonable" with respect to default service in the context of competitive retail markets, analyze the current and expected value of PSNH’s generating units, and identify means to mitigate and address stranded cost recovery.  

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On September 18, 2013, the NHPUC issued a Request for Proposal to hire a valuation expert to determine the value of PSNH's generation assets and entitlements.  On October 16, 2013, the State of New Hampshire Legislative Oversight Committee on Electric Utility Restructuring (Oversight Committee) requested that the NHPUC conduct an analysis to determine whether it is now in the economic interest of PSNH’s retail customers for PSNH to divest its interest in generation plants.  On November 1, 2013, the Oversight Committee asked for a preliminary report on the findings by April 1, 2014 that would include at a minimum the NHPUC Staff’s position, the analysis of the valuation expert, and any recommendations for legislation that may be needed concerning divestiture or otherwise related to this issue.  A valuation expert has been hired and the investigation is currently ongoing.  At this time, we cannot predict the outcome of this review.  Our current PSNH generation rate base totals approximately $760 million.  We continue to believe all costs and generation investments are probable of recovery.

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 that closed-cycle cooling systems are not warranted.  

Legislative and Policy Matters

Federal:

On January 2, 2013, the "American Taxpayer Relief Act of 2012" became law, which extended the accelerated deduction of depreciation to businesses through 2013.  This extended stimulus provided NU with cash flow benefits of approximately $300 million (approximately $95 million at CL&P, $85 million at NSTAR Electric, $35 million at PSNH, and $50 million at WMECO).  

On September 13, 2013, the Internal Revenue Service issued final Tangible Property regulations that are meant to simplify, clarify and make more administrable previously issued guidance.  In the third quarter of 2013, CL&P recorded an after-tax valuation allowance of $10.5 million against its deferred tax assets as a result of these regulations.  NU is in compliance with the new regulations, but continues to evaluate several new potential elections.  Therefore, a change to the valuation allowance at CL&P could result once NU completes the review of the impact of the final regulations.

Connecticut:

In 2013, Connecticut enacted into law two significant energy bills.  The first law, Public Act 13-298, implemented a number of the recommendations proposed in the CES.  Public Act 13-298 authorized the filing of a plan to expand natural gas service to Connecticut residents that currently do not have access to natural gas.  For further information on Yankee Gas’ filing, see "Regulatory Developments and Rate Matters - Connecticut - Yankee Gas Natural Gas Expansion Plan" in this Management's Discussion and Analysis.  The law also required PURA to implement decoupling for each of Connecticut’s electric and natural gas utilities in their next respective rate cases.  Finally, the law allows electric distribution companies to recover their costs as well as lost revenues from various state energy policy initiatives, including expanded energy efficiency programs.

The second law, Public Act 13-303, "An Act Concerning Connecticut’s Clean Energy Goals," allows DEEP to conduct a process to procure from renewable energy generators, under long-term contracts with the electric distribution companies, additional renewable generation to help Connecticut meet its Renewable Portfolio Standard (RPS).  Large scale hydropower facilities located in the New England Power Pool Generation Information System (NEPOOL GIS) geographic eligibility area or an area abutting the northern boundary of the NEPOOL GIS geographic eligibility area are eligible to bid into DEEP's process.  If Connecticut experiences a material shortfall in reaching its RPS goals, such hydropower, under certain conditions, can be used to alleviate such shortfall, up to five percent of RPS requirements in 2020.  

The law also requires DEEP to develop a schedule to assign a gradually reducing renewable energy credit value for all Class I biomass or landfill generation facilities.  Such reduced credit values will not apply to biogas or anaerobic digestion facilities, or to facilities that have a long-term contract in place.  The commissioner of DEEP may adjust such changes to the values of renewable energy credits, if such adjustment is appropriate given the availability of other Class I renewable energy sources.  

On September 26, 2013, DEEP issued a final determination that authorized the state’s electric distribution companies to enter into long-term power purchase agreements for a total of 270 MW of Class I renewable generation from two projects.  On October 23, 2013, PURA issued a final decision accepting the contracts presented by the electric distribution companies.  On October 21, 2013, DEEP

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issued a Request for Proposal seeking proposals for energy and RECs from private developers for up to 4 percent of the state’s electric distribution companies’ load (estimated to be between 100 MW to 150 MW) of Class I renewable energy resources for biomass, landfill gas and run off river hydropower projects from new or existing facilities.

Massachusetts:  

On July 24, 2013, Massachusetts enacted a law that changed the income tax rate applicable to utility companies effective January 1, 2014, from 6.5 percent to 8 percent.  The tax law change required NU to remeasure its accumulated deferred income taxes and resulted in NU increasing its deferred tax liability with an offsetting regulatory asset of approximately $61 million at its utility companies.

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 discussed below.  See the combined notes to our financial statements for further information concerning the accounting policies, estimates and assumptions used in the preparation of our 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 for 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 Regulatory assets are amortized as the incurred costs are recovered through 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 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 from customers 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 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 financial statements.  

Pension and PBOP:  NUSCO sponsors the NUSCO Pension Plan and NSTAR Electric acts as plan sponsor for the NSTAR Pension Plan, both of which cover certain of our employees.  In addition, our service company sponsors the NUSCO and NSTAR 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.  

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Pre-tax net periodic benefit expense (excluding SERP) for the Pension Plans was $236.3 million, $234.9 million and $127.7 million for the years ended December 31, 2013, 2012 and 2011, respectively.  The pre-tax net periodic benefit expense for the PBOP Plans was $32.6 million, $72.3 million and $43.6 million for the years ended December 31, 2013, 2012 and 2011, respectively.  NSTAR pension and PBOP expense was included in NU beginning April 10, 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 expected long-term rate of return on plan assets, discount rate, compensation/progression rate, and health care cost trend rates and are discussed below.

Expected Long-Term Rate of Return on Plan Assets:  In developing this assumption, we consider historical and expected returns and input from our 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, 2013, our aggregate expected long-term rate of return assumption of 8.25 percent was used to determine our pension and PBOP expense.  For the forecasted 2014 pension and PBOP expense, our expected long-term rate of return of 8.25 percent for all plans was used reflecting our 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 were 5.03 percent for the NUSCO Pension Plan, 4.85 percent for the NSTAR Pension Plan, 4.78 percent for the NUSCO PBOP Plans and 5.10 percent for the NSTAR PBOP Plan as of December 31, 2013.

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.  As of December 31, 2013 and 2012, we used a compensation/progression rate of 3.5 percent for the NUSCO Pension Plan and 4 percent for the NSTAR Pension Plan, 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 (which was fully amortized in 2013), 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, 2013, investment gains and losses that remain to be reflected in the calculation of plan assets over the next four years were losses of $41.8 million and gains of $27.6 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, 2013, the net unrecognized actuarial losses on the NUSCO Pension and PBOP Plan liabilities were $628.8 million and $111 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, 2013 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, 2013, the net unrecognized actuarial losses on the NSTAR Pension and PBOP Plan liabilities were approximately $498 million and $12.1 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 $132 million and $9.1 million, respectively, in 2014.  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.  We contributed $57.6 million to the PBOP Plans in 2013 and expect to contribute $39.7 million in 2014.  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 $202.7 million in 2013, of which $108.3 million was contributed by PSNH.  NSTAR Electric contributed $82 million to the NSTAR Pension Plan in 2013.  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 94.6 percent and 96 percent as of January 1, 2013 for the NUSCO Pension Plan and NSTAR Pension Plan, respectively.  We currently estimate that aggregate contributions of $71.6 million to the Pension Plans will be made in 2014.  Fluctuations in the average discount rate used to calculate expected contributions to the Pension Plans can have a significant impact on the amounts.  

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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			2013			2012		2013			2012
NU
Lower long-term rate of return		$	17.2		$	15.0		$	3.4		$	3.1
Lower discount rate		$	22.3		$	22.0		$	6.8		$	6.7
Higher compensation increase		$	12.4		$	10.4			N/A			N/A
NSTAR Plans
Lower long-term rate of return		$	5.6		$	4.8		$	1.8		$	1.7
Lower discount rate		$	5.4		$	6.8		$	3.4		$	4.1
Higher compensation increase		$	3.8		$	3.6			N/A			N/A

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:  The health care cost trend rate assumption used to calculate the 2013 PBOP expense amounts was 7 percent for the NUSCO PBOP Plan, subsequently decreasing by 50 basis points per year to an ultimate rate of 5 percent in 2017, and 7.10 percent for the NSTAR PBOP Plan, subsequently decreasing to an ultimate rate of 4.5 percent in 2024.  As of December 31, 2013, the health care cost trend rate assumption used to determine the NUSCO and NSTAR PBOP Plans’ year end funded status is 7 percent, subsequently decreasing to an ultimate rate of 4.5 percent in 2024.  The effect of a hypothetical increase in the health care cost trend rate by one percentage point would be an increase to the service and interest cost components of PBOP Plan expense by $7.1million in 2013, with a $85.8 million impact on the postretirement benefit obligation.  See Note 10A, "Employee Benefits - Pension Benefits and Postretirement Benefits Other Than Pensions," to the financial statements for more information.

Goodwill:  We have recorded approximately $3.5 billion of goodwill associated with the previous mergers and acquisitions.  NU has identified its reporting units for purposes of allocating and testing goodwill as Electric Distribution, Electric Transmission and Natural Gas Distribution.  These reporting units are consistent with our operating segments underlying our reportable segments.  Electric Distribution and Electric Transmission reporting units include carrying 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.  As of December 31, 2013, goodwill was allocated to the reporting units as follows:  $2.5 billion to Electric Distribution, $0.6 billion to Electric Transmission, and $0.4 billion to Natural Gas Distribution.

We are required to test goodwill balances for impairment at least annually by considering the fair value of the reporting units, which requires us to use estimates and judgments.  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 values of the reporting units’ assets and liabilities 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 test as of October 1, 2013 for the Electric Distribution, Electric Transmission and Natural Gas Distribution reporting units.  This evaluation required the test of several factors that impact the fair value of the reporting units, including conditions and assumptions that affect the future cash flows of the reporting units.  

The 2013 goodwill impairment test resulted in a conclusion that goodwill is not impaired and none of the reporting units is at risk of a goodwill impairment.  

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 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 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

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(including information gained from those examinations), developments in case law, settlements of tax positions, changes in tax law and regulations, rulings by taxing authorities and statute of limitation expirations.  Such information or events may have a significant impact on our financial position, results of operations and cash flows.  

Accounting for Environmental Reserves:  Environmental reserves are accrued when assessments indicate 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 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 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 financial statements.

Other Matters

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

Contractual Obligations and Commercial Commitments:  Information regarding our contractual obligations and commercial commitments as of December 31, 2013 is summarized annually through 2018 and thereafter as follows: