CONNECTICUT LIGHT & POWER CO - Annual Report: 2015 (Form 10-K)

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

FORM 10-K

x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE      SECURITIES EXCHANGE ACT OF 1934
	For the Fiscal Year Ended December 31, 2015
	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	EVERSOURCE ENERGY (a Massachusetts voluntary association) 300 Cadwell Drive Springfield, Massachusetts 01104 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) 300 Cadwell Drive Springfield, Massachusetts 01104 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
	x	¨

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
	¨	x

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
	x	¨

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
	x	¨

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
Eversource Energy	x		¨		¨
The Connecticut Light and Power Company	¨		¨		x
NSTAR Electric Company	¨		¨		x
Public Service Company of New Hampshire	¨		¨		x
Western Massachusetts Electric Company	¨		¨		x

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

	Yes	No
Eversource Energy	¨	x
The Connecticut Light and Power Company	¨	x
NSTAR Electric Company	¨	x
Public Service Company of New Hampshire	¨	x
Western Massachusetts Electric Company	¨	x

The aggregate market value of Eversource Energy’s 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 Eversource Energy's most recently completed second fiscal quarter (June 30, 2015) was $14,345,789,335 based on a closing market price of $45.41 per share for the 315,916,964 common shares outstanding on June 30, 2015.  

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, 2016
Eversource Energy Common shares, $5.00 par value	317,191,249 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

Eversource Energy 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.

Eversource Energy, The Connecticut Light and Power Company, NSTAR Electric Company, Public Service Company of New Hampshire, and Western Massachusetts Electric Company each separately file this combined Form 10-K.  Information contained herein relating to any individual registrant is filed by such registrant on its own behalf.  Each registrant makes no representation as to information relating to the other registrants.

GLOSSARY OF TERMS

i

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EVERSOURCE ENERGY 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

2015 FORM 10-K ANNUAL REPORT

TABLE OF CONTENTS

iii

EVERSOURCE ENERGY 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 "Eversource," "the Company," "we," "our," and "us" refer to Eversource and its consolidated subsidiaries.  On April 30, 2015, the Company's legal name was changed from Northeast Utilities to Eversource Energy.  CL&P, NSTAR Electric, PSNH and WMECO are each doing business as Eversource Energy.  

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,

·

actions or inaction of local, state and federal regulatory, public policy and taxing bodies,

·

changes in business conditions, which could include disruptive technology related to our current or future business model,

·

changes in economic conditions, including impact on interest rates, tax policies, and customer demand and payment ability,

·

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 of Financial Condition and Results of Operations and Combined Notes to Consolidated Financial Statements.  We encourage you to review these items.  

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EVERSOURCE ENERGY 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 combined Annual Report on Form 10-K.

Eversource Energy, headquartered in Boston, Massachusetts and Hartford, Connecticut, is a public utility holding company subject to regulation by the 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 eastern 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.

CL&P, NSTAR Electric, PSNH and WMECO also serve New England customers through Eversource Energy's electric transmission business.

On April 30, 2015, the Company's legal name was changed from Northeast Utilities to Eversource Energy. CL&P, NSTAR Electric, PSNH and

WMECO are each doing business as Eversource Energy.

Eversource Energy, 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 Eversource Energy.  Eversource Energy recognizes three reportable segments: electric distribution, electric transmission and natural gas distribution.  Eversource Energy's electric distribution segment includes the generation businesses of PSNH and WMECO.  These three segments represented substantially all of Eversource Energy's total consolidated revenues for the years ended December 31, 2015 and 2014.  CL&P, NSTAR Electric, PSNH and WMECO do not report separate business segments.   

ELECTRIC DISTRIBUTION SEGMENT

General

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

The following table shows the sources of 2015 electric franchise retail revenues for Eversource Energy's electric distribution companies, collectively, based on categories of customers:

(Thousands of Dollars, except percentages)		2015		% of Total
Residential	$	3,608,155		55
Commercial		2,476,686		38
Industrial		326,564		5
Other		151,195		2
Total Retail Electric Revenues	$	6,562,600		100%

2

A summary of our distribution companies' retail electric GWh sales volumes and percentage changes for 2015, as compared to 2014, is as follows:

	2015		2014		Percentage Change
Residential	21,441		21,317		0.6 %
Commercial	27,598		27,449		0.5 %
Industrial	5,577		5,676		(1.7)%
Total	54,616		54,442		0.3 %

Our 2015 consolidated retail electric sales volumes were slightly higher, as compared to 2014, due primarily to the impact of colder winter weather experienced in the first quarter of 2015 and warmer weather in the third quarter of 2015, partially offset by milder winter weather in the fourth quarter of 2015 throughout our service territories as well as an increase in customer conservation efforts, including the impact of energy efficiency programs sponsored by CL&P, NSTAR Electric, PSNH and WMECO.

Fluctuations in retail electric sales volumes at NSTAR Electric and PSNH impact earnings.  For CL&P (effective December 1, 2014) and WMECO, fluctuations in retail electric sales volumes do not impact earnings due to their respective regulatory commission approved revenue decoupling mechanisms.  These distribution revenues are decoupled from their customer sales volumes, which breaks the relationship between sales volumes and revenues recognized.  CL&P and WMECO reconcile their annual base distribution rate recovery amounts to their respective pre-established levels of baseline distribution delivery service revenues.  Any difference between the allowed level of distribution revenue and the actual amount incurred during a 12-month period is adjusted through rates in the following period.

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, 2015, 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 2015 electric franchise retail revenues based on categories of customers:

	CL&P
(Thousands of Dollars, except percentages)		2015			% of Total
Residential	$	1,641,165			61
Commercial		841,093			31
Industrial		129,544			5
Other		62,704			3
Total Retail Electric Revenues	$	2,674,506			100%

A summary of CL&P's retail electric GWh sales volumes and percentage changes for 2015, as compared to 2014, is as follows:

	2015		2014		Percentage Change
Residential	10,094		10,026		0.7 %
Commercial	9,635		9,643		(0.1)%
Industrial	2,342		2,377		(1.5)%
Total	22,071		22,046		0.1 %

Rates

CL&P is subject to regulation by the PURA, which, among other things, has jurisdiction over rates, 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 operating and capital costs, in order 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 40 percent of its customer load at SS or LRS rates while the other 60 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 electric distribution business or its operating income.

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

·

An electric generation services charge (GSC), which recovers energy-related costs incurred as a result of providing electric generation service supply to all customers that have not migrated to competitive energy suppliers.  The GSC is adjusted periodically and reconciled semi-annually in accordance with the policies and procedures of the PURA, with any differences refunded to, or recovered from, customers.

·

A revenue decoupling adjustment (effective December 1, 2014) that reconciles the amounts recovered from customers, on an annual basis, to the distribution revenue requirement approved by the PURA in its last rate case, which currently is an annual amount of $1.059 billion.

·

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 customers, as well as ongoing operating costs to maintain the infrastructure.  

·

A federally-mandated congestion charge (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 the PURA to reduce these charges.  The FMCC also recovers costs associated with CL&P's system resiliency program.  The FMCC is adjusted periodically and reconciled semi-annually in accordance with the policies and procedures of the PURA, with any differences refunded to, or recovered from, customers.

·

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 assessment charge (CTA), assessed to recover stranded costs associated with electric industry restructuring such as various IPP contracts.  The CTA is reconciled annually to actual costs incurred and reviewed by the PURA, with any difference refunded to, or recovered from, customers.

·

A systems benefits charge (SBC), 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.  The SBC is reconciled annually to actual costs incurred and reviewed by the PURA, with any difference refunded to, or recovered from, customers.  

·

A Clean Energy Fund charge, which is used to promote investment in renewable energy sources.  Amounts collected by this charge are deposited into the Clean Energy Fund and administered by the Clean Energy Finance and Investment Authority.  The Clean Energy 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.

As required by regulation, CL&P, jointly with UI, entered into the following contracts whereby UI will share 20 percent and CL&P will share 80 percent of the costs and benefits (CL&P's portion of these costs are either recovered from, or refunded to, customers through the FMCC charge):

·

Four CfDs (totaling approximately 787 MW of capacity) with three electric generation units and one demand response project, which extend through 2026 and have terms of up to 15 years beginning in 2009.  The capacity CfDs obligate both CL&P and UI to make or receive payments on a monthly basis to or from the project and generation owners based on the difference between a contractually set capacity price and the capacity market prices that the project and generation owners receive in the ISO-NE capacity markets.

·

Three CfDs (totaling approximately 500 MW of peaking capacity) with three peaking generation units.  The three peaker CfDs pay the generation owners the difference between capacity, forward reserve and energy market revenues and a cost-of service payment stream for 30 years beginning in 2008 (including costs of plant operation and the prices that the generation owners receive for capacity and other products in the ISO-NE markets).  

·

Long-term commitments to purchase approximately 250 MW of wind power from a Maine wind farm and 20 MW of solar power from a multi-site project in Connecticut.  Both of these projects are expected to be operational by the end of 2016.

On December 17, 2014 the PURA approved CL&P's application to amend customer rates, effective December 1, 2014, for a total base distribution rate increase of $152 million, which includes an authorized ROE of 9.02 percent for the first twelve month period and 9.17 percent thereafter.  The distribution rate increase included a revenue decoupling mechanism effective December 1, 2014, and the recovery of 2011 and 2012 storm restoration costs and system resiliency costs.  Also in December 2014, the PURA granted a re-opener request to CL&P’s base distribution rate application for further review of the appropriate balance of ADIT utilized in the calculation of rate base.  On July 2, 2015, the PURA issued a final order that approved a settlement agreement filed on May 19, 2015 between CL&P and the PURA Prosecutorial Staff, and which included an increase to total allowed annual revenue requirements of $18.4 million beginning December 1, 2014.

4

Sources and Availability of Electric Power Supply

As noted above, CL&P does not own any generation assets and purchases energy supply to serve its SS and LRS loads from a variety of competitive sources through requests for proposals.  CL&P periodically enters into full requirements contracts for the majority of SS loads for periods of up to one year for its residential customers and small and medium commercial and industrial customers.  CL&P is authorized to supply the remainder of the SS loads through a self-managed process that includes bilateral purchases and spot market purchases.  CL&P typically enters into full requirements contracts for LRS for larger commercial and industrial customers every three months.  Currently, CL&P has full requirements contracts in place for 80 percent of its SS loads for the first half of 2016 and has bilateral purchases in place to self-manage the remaining 20 percent.  For the second half of 2016, CL&P has 50 percent of its SS load under full requirements contracts, intends to purchase an additional 30 percent of full requirements and will self-manage the remainder as needed.  None of the SS load for 2017 has been procured.  CL&P has full requirements contracts in place for its LRS loads through the second quarter of 2016 and intends to purchase 100 percent of full requirements for the third and fourth quarters of 2016.

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, 2015, 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 approximately 1,700 square miles.  WMECO provides retail franchise electric service to approximately 209,000 customers in 59 cities and towns in the western region of Massachusetts, covering an area of approximately 1,500 square miles.  Neither NSTAR Electric nor WMECO owns any generating facilities used to supply customers, and each purchases its respective energy requirements from competitive energy suppliers.  

In 2009, WMECO was authorized by the DPU to install solar energy generation in its service territory.  From 2010 through 2014, WMECO completed development of a total of 8 MW solar generation facilities on sites in Pittsfield, Springfield, and East Springfield, Massachusetts.  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 generation facilities.

The following table shows the sources of the 2015 electric franchise retail revenues of NSTAR Electric and WMECO based on categories of customers:

		NSTAR Electric				WMECO
(Thousands of Dollars, except percentages)		2015		% of Total		2015			% of Total
Residential	$	1,205,387		48		$	255,797		59
Commercial		1,187,452		47			135,222		31
Industrial		84,667		3			35,439		8
Other		47,610		2			5,778		2
Total Retail Electric Revenues	$	2,525,116		100%		$	432,236		100%

A summary of NSTAR Electric's and WMECO's retail electric GWh sales volumes and percentage changes for 2015, as compared to 2014, is as follows:

		NSTAR Electric						WMECO
		2015		2014		Percentage Change		2015		2014		Percentage Change
Residential		6,687		6,625		0.9 %		1,465		1,494		(2.0)%
Commercial		13,120		13,009		0.9 %		1,478		1,466		0.8 %
Industrial		1,248		1,291		(3.3)%		620		626		(0.9)%
Total		21,055		20,925		0.6 %		3,563		3,586		(0.6)%

Rates

NSTAR Electric and WMECO are each subject to regulation by the DPU, which, among other things, has jurisdiction over rates, 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 operating and capital costs, in order 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 remains their electric distribution company.  Both NSTAR Electric and WMECO purchase power from competitive suppliers on behalf of, and pass the related cost through to, their respective customers who do not choose a competitive energy supplier (basic service).  Most of the residential customers of NSTAR Electric and WMECO have continued to buy their power from NSTAR Electric or WMECO at basic service rates.  Most commercial and industrial customers have switched to a competitive energy supplier.  

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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, maintenance of infrastructure, capital investment, meter reading, billing, and customer service.

NSTAR Electric continues to supply approximately 39 percent of its customer load at basic service rates while the other 61 percent of its customer load has migrated to competitive energy suppliers.  WMECO continues to supply approximately 41 percent of its customer load at basic service rates while the other 59 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 Electric 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 uncollectible energy costs from customers.  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 and NSTAR Green wind contracts through the basic service charge.  Basic service costs are reconciled annually, with any differences refunded to, or recovered from, customers.

·

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 in 2011.  Currently, WMECO is allowed to collect $132.4 million annually.

·

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 contract buy-outs.

·

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

·

Reconciling adjustment charges that recover certain DPU-approved costs as follows:  pension and PBOP benefits, low income customer discounts, lost revenue and credits associated with net-metering facilities installed by customers, storms, consultants retained by the attorney general, long-term renewable contracts and energy efficiency programs and lost base revenue associated with energy efficiency measures.  In addition to these adjustments common to both NSTAR Electric and WMECO, NSTAR Electric has reconciling adjustment charges that collect costs associated with certain safety and reliability projects and a Smart Grid pilot program.  WMECO has a reconciling adjustment charge that recovers costs associated with certain solar projects owned and operated by WMECO.  

As required by regulation, NSTAR Electric and WMECO, along with two other Massachusetts electric utilities, signed long-term commitments to purchase a combined estimated generating capacity of approximately 334 MW of wind power from two wind farms in Maine over 15 years.  The projects are in various stages of permitting, development, or operation.  One unit began operating in late 2015, and the other unit is expected to be in operation by December 2016.  In addition, WMECO previously signed a long-term commitment to purchase an estimated generating capacity of approximately 37.5 MW of wind power from a wind farm in Maine over 15 years that is expected to be in operation in 2016.

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.  

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 2015 performance as each company achieved results at or above target for all of its respective SQ metrics in 2015.

Sources and Availability of Electric Power Supply

As noted above, neither NSTAR Electric nor WMECO owns any generation assets (other than WMECO's 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 per 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.

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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, 2015, PSNH furnished retail franchise electric service to approximately 503,000 retail customers in 211 cities and towns in New Hampshire, covering an area of approximately 5,630 square miles.  PSNH currently owns and operates approximately 1,200 MW of primarily coal-, natural gas-, and oil-fired electricity generation plants.  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 2011.  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.  PSNH is permitted to recover prudent Scrubber costs through its default energy service rates under New Hampshire law.  Effective January 1, 2016, PSNH is recovering all Scrubber costs in rates charged to customers.  For further information, see "Regulatory Developments and Rate Matters – New Hampshire – Clean Air Project Prudence Proceeding" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.

The following table shows the sources of PSNH's 2015 electric franchise retail revenues based on categories of customers:

	PSNH
(Thousands of Dollars, except percentages)		2015		% of Total
Residential	$	505,806		54
Commercial		312,918		34
Industrial		76,914		8
Other		35,103		4
Total Retail Electric Revenues	$	930,741		100%

A summary of PSNH's retail electric GWh sales volumes and percentage changes for 2015, as compared to 2014, is as follows:

	2015		2014		Percentage Change
Residential	3,195		3,172		0.7 %
Commercial	3,365		3,332		1.0 %
Industrial	1,367		1,382		(1.1)%
Total	7,927		7,886		0.5 %

Rates

PSNH is subject to regulation by the NHPUC, which, among other things, has jurisdiction over 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 operating and capital costs, in order 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 choose a competitive energy supplier.  At the end of 2015, approximately 21 percent of all of PSNH's customers (approximately 53 percent of load) were taking service from competitive energy suppliers, compared to 21 percent of customers (approximately 46 percent of load) at the end of 2014.  

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

·

A default energy service 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.  These charges recover the costs of PSNH's generation, as well as purchased power, and include an allowed ROE of 9.81 percent.

·

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 plants 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.  

·

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

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·

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

The energy charge and SCRC rates change semi-annually and are reconciled annually and differences between actual costs incurred versus current rates are either refunded or recovered in subsequent rates charged to customers.

PSNH distribution rates were set in a 2010 NHPUC rate case settlement, which expired on June 30, 2015.  In the 2015 PSNH Settlement Agreement, the Company agreed that its present distribution rates will stay in effect until at least July 1, 2017.  However, certain aspects of the 2010 rate case settlement will continue, including funding for reliability enhancement program activities, adjustment of distribution rates for certain exogenous events that in the aggregate exceed $1 million, and major storm reserve funding.

Generation Divestiture

In 2013, the NHPUC opened a docket to investigate market conditions affecting PSNH's default energy service rate, how PSNH will maintain just and reasonable rates in light of those conditions, and any impact of PSNH's generation ownership on the New Hampshire competitive electric market.  In April 2014, the NHPUC staff issued a "Preliminary Status Report Addressing the Economic Interest of PSNH's Retail Customers as it Relates to the Potential Divestiture of PSNH's Generating Plants," which included a consultant's analysis of the fair market value of PSNH generating assets and long-term power purchase contracts.  The consultant's analysis estimated the fair market value of PSNH's generation assets to be $225 million as of December 31, 2013 and compared that amount to a stated net book value of $660 million, implying potential "stranded costs" of approximately $435 million.  An abbreviated draft update by the consultant dated August 17, 2015, increased the estimated fair market value of PSNH’s generation assets to $235 million.

In 2014, the Legislature enacted changes to the laws governing divestiture of PSNH's generation assets, effective September 30, 2014.  The new law required the NHPUC to initiate a proceeding to determine whether all or some of PSNH's generation assets should be divested.  The law gives the NHPUC express authority to order the divestiture of all or some of PSNH's generation assets if the NHPUC finds it is in the economic interest of customers to do so.  The law also clarified the definition of "stranded costs" to include costs approved for recovery by the NHPUC in connection with the divestiture or retirement of PSNH's generation assets.

On June 10, 2015, Eversource and PSNH entered into the 2015 Public Service Company of New Hampshire Restructuring and Rate Stabilization Agreement (the Agreement) with the New Hampshire Office of Energy and Planning, certain members of the NHPUC staff, the Office of Consumer Advocate, two state senators, and several other parties.  The Agreement was filed with the NHPUC on the same day.  Under the terms of the Agreement, PSNH has agreed to divest its generation assets upon NHPUC approval.  The Agreement is designed to provide a resolution of issues pertaining to PSNH's generation assets in pending regulatory proceedings before the NHPUC.  The Agreement provided for the Clean Air Project prudence proceeding to be resolved and all remaining Clean Air Project costs to be included in rates effective January 1, 2016.  As part of the Agreement, PSNH has agreed to forego recovery of $25 million of the deferred equity return related to the Clean Air Project.  In addition, PSNH will not seek a general distribution rate increase effective before July 1, 2017 and will contribute $5 million to create a clean energy fund, which will not be recoverable from its customers.  

In 2015, the Legislature enacted changes to law to allow the use of securitization financing to recover any stranded costs resulting from the divestiture of PSNH’s generating assets.  If the Agreement is approved, following divestiture of PSNH’s generating assets, bonds will be issued to recover resulting stranded costs.  

On January 26, 2016, Advisory Staff of the NHPUC and the parties to the Agreement filed a stipulation with the NHPUC agreeing that near-term divestiture of PSNH’s generation was in the public interest and that the Agreement should be approved.  Implementation of the Agreement is subject to NHPUC approval, which is expected in early 2016.  

Sources and Availability of Electric Power Supply

During 2015, approximately 54 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 competitive energy suppliers.  The remaining 46 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 2016 in a similar manner.  Included in the 54 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.

Merrimack and Schiller Stations have recently operated at lower than typical capacity factors due to moderate regional temperatures.  The Hydro stations have been operating at high capacity factors. PSNH’s Energy Service Rate has been set at 9.99 cents per kWh effective January 1, 2016, which includes 1.27 cents per kWh reflecting full recovery of costs related to the Clean Air Project.

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.  

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Wholesale Transmission Revenues

A summary of Eversource Energy's wholesale transmission revenues is as follows:

(Thousands of Dollars)		2015
CL&P	$	513,025
NSTAR Electric		299,241
PSNH		127,509
WMECO		129,502
Total Wholesale Transmission Revenues	$	1,069,277

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 transmission rates provide for the annual reconciliation 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 Complaints

Three separate complaints have been filed at the FERC by combinations of New England state attorneys general, state regulatory commissions, consumer advocates, consumer groups, municipal parties and other parties (the "Complainants").  In these three separate complaints, the Complainants challenged the NETOs' base ROE of 11.14 percent that had been utilized since 2006 and sought an order to reduce it prospectively from the date of the final FERC order and for the 15-month complaint refund periods stipulated in the separate complaints.  In 2014, the FERC ordered a 10.57 percent base ROE for the first complaint refund period and prospectively from October 16, 2014 and that a utility's total or maximum ROE shall not exceed the top of the new zone of reasonableness, which was set at 11.74 percent.  The NETOs and the Complainants sought rehearing from the FERC.  In late 2014, the NETOs made a compliance filing and the Company began issuing refunds to customers from the first complaint period.  

On March 3, 2015, FERC issued an order denying all issues raised on rehearing by the NETOs and Complainants in the first complaint.  The FERC order upheld the base ROE of 10.57 percent for the first complaint refund period and prospectively from October 16, 2014, and upheld that the utility's total ROE (the base ROE plus any incentive adders) for the transmission assets to which the adder applies is capped at the top of the zone of reasonableness, which is currently set at 11.74 percent.  The NETOs and Complainants have filed appeals to the D.C. Circuit Court of Appeals, which have been consolidated, and briefing is scheduled to be concluded in the second quarter of 2016.  A court decision is expected in late 2016.

For the second and third complaint proceedings, hearings were held in late June and early July 2015 and briefs were filed in July and August 2015.  The state parties, municipal utilities and FERC trial staff each believe that the base ROE should be reduced to an amount lower than 10.57 percent.  The NETOs believe that the Complainants' positions are without merit, and the existing base ROE of 10.57 is just and reasonable and should be maintained.  On December 18, 2015, the FERC ALJ reopened the record to have the NETOs and FERC trial staff review certain calculations.  The FERC ALJ’s initial recommendation is expected by March 31, 2016.  A final FERC order is expected in late 2016 or early 2017.

Although Eversource is uncertain on the final outcome of the second and third complaints regarding the ROE, we believe the current reserves established are appropriate to reflect probable and reasonably estimable refunds. For further information, see "FERC Regulatory Issues – FERC ROE Complaints" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.  

FERC Order No. 1000

On August 15, 2014, the D.C. Circuit Court of Appeals upheld the FERC's authority to order major changes to transmission planning and cost allocation in FERC Order No. 1000 and Order No. 1000-A, including transmission planning for public policy needs, and the requirement that utilities remove from their transmission tariffs their rights of first refusal to build transmission.  On March 19, 2015, the FERC acted on all rehearing requests filed by the NETOs, including CL&P, NSTAR Electric, PSNH and WMECO, and other parties and accepted the November 2013 compliance filing made by ISO-NE and the NETOs, subject to further compliance.  The FERC accepted our proposal that the new competitive transmission planning process will not apply to certain projects, which have been declared as the preferred solution by ISO-NE, unless ISO-NE later decides a solution must be re-evaluated.  The FERC determined on rehearing that we can restore provisions that recognize the NETOs’ rights to retain use and control of their existing rights of ways.  Final compliance was filed by the NETOs in November 2015 and was accepted by the FERC on December 14, 2015.

Additionally, the FERC affirmed that it can eliminate our right of first refusal to build transmission in New England even though the FERC previously approved and granted special protections to these rights.  The NETOs filed an appeal to the D.C. Circuit Court of Appeals, challenging this FERC ruling.  State regulators also filed an appeal, challenging FERC’s determination that ISO-NE should select public policy transmission projects after a competitive process.  The Court is expected to resolve the appeals in 2016.

Transmission Projects

During 2015, we were involved in the planning, development and construction of a series of electric transmission projects, including the NEEWS family of projects; the Greater Hartford Central Connecticut (GHCC) solutions; and Greater Boston Reliability Solutions, which are a series of new transmission projects over the next five years that will enhance system reliability and improve capacity.  We were involved in the planning and

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development of Northern Pass, which is our 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; and the Clean Energy Connect Project, which is a planned transmission, wind and hydro generation project that we intend to develop with experienced renewable generation companies. For further information, see "Business Development and Capital Expenditures – Electric Transmission Business" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.

Transmission Rate Base

Under our FERC-approved tariff, and with the exception of transmission projects that received specific FERC approval to include CWIP in rate base, transmission projects generally enter rate base after they are placed in commercial operation.  At the end of 2015, our estimated transmission rate base was approximately $5.2 billion, including approximately $2.4 billion at CL&P, $1.4 billion at NSTAR Electric, $548 million at PSNH, and $625 million at WMECO.  

NATURAL GAS DISTRIBUTION SEGMENT

NSTAR Gas distributes natural gas to approximately 286,000 customers in 51 communities in central and eastern Massachusetts covering 1,067 square miles, and Yankee Gas distributes natural gas to approximately 226,000 customers in 71 cities and towns in Connecticut covering 2,187 square miles.  Total throughput (sales and transportation) in 2015 was approximately 71.7 Bcf for NSTAR Gas and 57.8 Bcf for Yankee Gas.  Our natural gas businesses provide 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 Eversource Energy's natural gas distribution companies.  A portion of the storage of natural gas supply for NSTAR Gas during the winter heating season is provided by Hopkinton LNG Corp., an indirect, wholly-owned subsidiary of Eversource Energy.  NSTAR Gas has access to Hopkinton LNG Corp. facilities in Hopkinton, Massachusetts consisting of a LNG liquefaction and vaporization plant and three above-ground cryogenic storage tanks having an aggregate capacity of 3.0 Bcf of liquefied natural gas. NSTAR Gas also has access to Hopkinton LNG Corp. facilities in Acushnet, Massachusetts that include additional storage capacity of 0.5 Bcf and additional vaporization capacity.  

Yankee Gas 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 it to provide economic supply and make economic refill of natural gas typically during periods of low demand.  

NSTAR Gas and Yankee Gas generate revenues primarily through the sale and/or transportation of natural 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 natural gas suppliers.  Retail natural gas service in Connecticut is partially unbundled: residential customers in Yankee Gas' service territory buy natural gas supply and delivery only from Yankee Gas while commercial and industrial customers may choose their natural gas suppliers.  NSTAR Gas offers firm transportation service to all customers who purchase natural gas from sources other than NSTAR Gas while Yankee Gas offers firm transportation service to its commercial and industrial customers who purchase natural gas from sources other than Yankee Gas.  In addition, both natural gas distribution companies offer interruptible transportation and interruptible natural gas sales service to those high volume commercial and industrial customers, generally during the colder months, that have the capability to switch from natural gas to an alternative fuel on short notice, for whom NSTAR Gas and Yankee Gas can interrupt service during peak demand periods or at any other time to maintain distribution system integrity.

The following table shows the sources of the 2015 total Eversource Energy natural gas franchise retail revenues based on categories of customers:

(Thousands of Dollars, except percentages)		2015		% of Total
Residential	$	497,873		54
Commercial		327,439		36
Industrial		93,378		10
Total Retail Natural Gas Revenues	$	918,690		100%

A summary of our firm natural gas sales volumes in million cubic feet and percentage changes for 2015, as compared to 2014, is as follows:

					Percentage
	2015		2014		Change
Residential	38,455		38,969		(1.3)%
Commercial	43,006		42,977		0.1 %
Industrial	21,538		22,245		(3.2)%
Total	102,999		104,191		(1.1)%
Total, Net of Special Contracts (1)	98,458		99,500		(1.0)%

 ⁽¹⁾

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

Our firm natural gas sales volumes are subject to many of the same influences as our retail electric sales volumes.  In addition, they have benefited from customer growth in both of our natural gas distribution companies.  In 2015, consolidated firm natural gas sales volumes were lower, as compared to 2014.  The 2015 firm natural gas sales volumes were negatively impacted by record warm weather in the fourth quarter of 2015, when compared to 2014, partially offset by colder winter weather in the first quarter of 2015, as compared to 2014, throughout our natural gas service territories.  Weather-normalized Eversource consolidated firm natural gas sales volumes increased 2.5 percent in 2015, as compared to 2014, due primarily to improved economic conditions as well as residential and commercial customer growth, through conversions to natural gas service.  

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Rates

NSTAR Gas and Yankee Gas are subject to regulation by the DPU and the PURA, respectively, which, among other things, have jurisdiction over rates, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, standards of service and construction and operation of facilities.  Both of Eversource Energy's natural gas companies are entitled under their respective state law to charge rates that are sufficient to allow them an opportunity to recover their reasonable operating and capital costs, in order to attract needed capital and maintain their financial integrity, while also protecting relevant public interests.

Retail natural gas delivery and supply rates are established by the DPU and 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;

·

A seasonal cost of gas adjustment clause (CGAC) at NSTAR Gas 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 semi-annually.  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 five percent; and

·

A local distribution adjustment clause (LDAC) at NSTAR Gas that collects all energy efficiency and related program costs, environmental costs, pension and PBOP related costs, attorney general consultant costs, and costs associated with low income customers.  The LDAC is reset annually and provides for the recovery of certain costs applicable to both sales and transportation customers.

·

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 from or refunded to customers during the following year.  Carrying charges on outstanding balances are calculated using Yankee Gas' weighted average cost of capital in accordance with the directives of the PURA; and

·

Conservation Adjustment Mechanism (CAM) at Yankee Gas, 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 revenues to expenses is performed annually with any difference being recovered from or refunded to customers, with carrying charges, during the following year.

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 DPU in 2006.  This practice attempts to minimize the impact of fluctuations in natural gas prices to NSTAR Gas' firm natural gas customers.  These financial contracts do not procure natural gas supply.  All costs incurred or benefits realized when these contracts are settled are included in the CGAC.

NSTAR Gas is 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 distribution revenues for failing to meet such metrics.  NSTAR Gas will not be required to pay a SQ charge for its 2015 performance as it achieved results at or above target for all of its SQ metrics in 2015.

On October 30, 2015, the DPU issued its order in the NSTAR Gas distribution rate case, which approved an annualized base rate increase of $15.8 million, plus other increases of approximately $11.5 million, mostly relating to recovery of pension and PBOP expenses and the Hopkinton Gas Service Agreement, effective January 1, 2016.  In the order, the DPU also approved an authorized regulatory ROE of 9.8 percent, the establishment of a revenue decoupling mechanism, the recovery of certain bad debt expenses, and a 52.1 percent equity component of its capital structure.  On November 19, 2015, NSTAR Gas filed a motion for reconsideration of the order with the DPU seeking the correction of mathematical errors and other plant and cost of service items.

Yankee Gas’ last rate proceeding was in 2011, which approved an allowed ROE of 8.83 percent and allowed for a substantial increase in annual spending for bare steel and cast iron pipeline replacement.  In 2015, Yankee Gas entered into a settlement agreement with the PURA staff pursuant to which Yankee Gas provided a $1.5 million rate credit to firm customers beginning in December 2015, and established an earnings sharing mechanism whereby Yankee Gas and its customers will share equally in any earnings exceeding a 9.5 percent ROE in a twelve month period commencing with the period from April 1, 2015 through March 31, 2016.

Massachusetts Natural Gas Replacement and Expansion

On July 7, 2014, Massachusetts enacted "An Act Relative to Natural Gas Leaks" (the Act).  The Act establishes a uniform natural gas leak classification standard for all Massachusetts natural gas utilities and a program that accelerates the replacement of aging natural gas infrastructure.  The program will enable companies, including NSTAR Gas, to better manage the scheduling and costs of replacement.  The Act also calls for the DPU to authorize natural gas utilities to design and offer programs to customers that will increase the availability, affordability and feasibility of natural gas service for new customers.  

In October 2014, pursuant to the Act, NSTAR Gas filed the Gas System Enhancement Program (GSEP) with the DPU.  NSTAR Gas' program accelerates the replacement of certain natural gas distribution facilities in the system to within 25 years.  The GSEP includes a new tariff effective January 1, 2016 that provides NSTAR Gas an opportunity to collect the costs for the program on an annual basis through a newly designed

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reconciling factor.  On April 30, 2015, the DPU approved the GSEP.  We expect capital expenditures of approximately $255 million for the period 2016 through 2019 for the GSEP.   

Connecticut Natural Gas Expansion Plan

In 2013, in accordance with Connecticut law and regulations, the PURA approved a comprehensive joint natural gas infrastructure expansion plan (expansion plan) filed 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 a 10-year period.  Yankee Gas estimates that its portion of the plan will cost approximately $700 million over 10 years.  In January 2015, the PURA approved a joint settlement agreement proposed by Yankee Gas and other Connecticut natural gas distribution companies and regulatory agencies that clarified the procedures and oversight criteria applicable to the expansion plan.  On March 20, 2015, Yankee Gas filed its initial System Expansion (SE) Rate reconciliation for 2014.  The proposed SE rate was approved by the PURA for implementation as of April 1, 2015, pending final PURA approval following a contested hearing.     

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 under a firm portfolio management contract with a term of one year, which has a maximum quantity of approximately 154,700 MMBtu/day of firm flowing natural gas supplies and 76,700 MMBtu/day of firm natural gas storage supplies.

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 natural 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 regions.  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 LNG Corp., which owns an LNG liquefaction and vaporization plant and three above-ground cryogenic storage tanks having an aggregate capacity of 3.0 Bcf of liquefied natural gas.  NSTAR Gas also has access to Hopkinton LNG Corp. facilities that include additional storage capacity of 0.5 Bcf and additional vaporization capacity.

The 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' 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, NSTAR Gas and Yankee Gas each believes that participation in planned and anticipated pipeline and storage expansion projects will be required in order for it to meet current and future sales growth opportunities.

NATURAL GAS PIPELINE EXPANSION

Access Northeast is a natural gas pipeline and storage project (the "Project") being developed jointly by Eversource, Spectra Energy Corp and National Grid.  Access Northeast will enhance the Algonquin and Maritimes & Northeast pipeline systems using existing routes and will include two new LNG storage tanks and liquefaction and vaporization facilities in Acushnet, Massachusetts that will be connected to the Algonquin gas pipeline.  The Project is expected to be capable of delivering approximately 900 million cubic feet of additional natural gas per day to New England on peak demand days.  Eversource and Spectra Energy Corp each own a 40 percent interest in the Project, with the remaining 20 percent interest owned by National Grid.  The total projected cost for both the pipeline and the LNG storage is expected to be approximately $3 billion with anticipated in-service dates commencing in November 2018.  The Project is subject to FERC and other federal and state regulatory approvals.  On November 17, 2015, the FERC accepted the Project’s request to initiate the pre-filing review process.  Upon completion of the pre-filing review, a certificate application will be filed with the FERC.  In late 2015, the Project bid into the New England Natural Gas Pipeline Capacity RFP conducted by certain EDCs in Massachusetts and Rhode Island, including NSTAR Electric and WMECO in Massachusetts, and in December 2015 and January 2016, those Massachusetts EDCs filed with the DPU seeking approval of the contracts for pipeline and storage capacity with the Project.  We expect the Rhode Island EDC to file its selected contracts with the Rhode Island regulatory agencies in the first half of 2016.  In February 2016, PSNH filed for approval with the NHPUC, of its proposed contract for natural gas pipeline capacity and storage with the Project.  

PROJECTED CAPITAL EXPENDITURES

We project to make capital expenditures of approximately $9.2 billion from 2016 through 2019.  Of the $9.2 billion, we expect to invest approximately $4.9 billion in our electric and natural gas distribution segments and $3.9 billion in our electric transmission segment.  In addition, we

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project to invest approximately $0.4 billion in information technology and facilities upgrades and enhancements.  These projections do not include capital expenditures related to Access Northeast or Clean Energy Connect.

FINANCING

Our credit facilities and indentures require that Eversource Energy 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, 2015, a total of $200 million of Eversource’s long-term debt, all at NSTAR Electric, will be paid in the next 12 months.  

NUCLEAR FUEL STORAGE

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.  The Yankee Companies have completed collection of their decommissioning and closure costs through the proceeds from the spent nuclear fuel litigation against the DOE and has refunded amounts to its member companies.  These proceeds were used by the Yankee Companies to offset the decommissioning and closure cost amounts due from their member companies or to decrease the wholesale FERC-approved rates charged under power purchase agreements with CL&P, NSTAR Electric, PSNH and WMECO and several other New England utilities.  The decommissioning rates charged by the Yankee Companies have been reduced to zero.  CL&P, NSTAR Electric, PSNH and WMECO can recover these costs from, or refund proceeds to, their customers through state regulatory commission-approved retail rates.  

We consolidate the assets and obligations of CYAPC and YAEC on our consolidated balance sheet because we own more than 50 percent of these companies.  

For information on the DOE proceeds received related to the spent nuclear fuel litigation, see Note 11C, "Commitments and Contingencies – Contractual Obligations – Yankee Companies," in the accompanying Item 8, Financial Statements and Supplementary Data.

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 PSNH's generation facilities.  

In 1997, PSNH filed in a timely manner for a renewal of the NPDES permit for the Merrimack Station.  As a result, the existing permit was administratively continued.  In 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.  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.  On April 18, 2015 EPA issued a revised section of the draft NPDES permit for Merrimack Station.  The revised portion of the draft permit deals solely with the treatment of wastewater from the flue gas desulfurization system.  On August 18, 2015 PSNH again submitted comments.  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 coal- and oil-fired electric generating stations, we believe it is unlikely that they would face similar permitting determinations.

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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 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 stations.  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 electric generating stations.  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 coal- and oil-fired electric generating stations 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.  At Schiller Station additional controls are being installed at the two coal-fired units, the cost of which is estimated to be approximately $2.5 million.

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 2015, the total RPS obligation was 8.3 percent and it will ultimately reach 24.8 percent in 2025.  Energy suppliers, like PSNH, must possess sufficient quantities of RECs to satisfy the RPS requirements.  PSNH owns renewable sources and uses a portion of internally generated RECs to meet its RPS obligations and sells other internally generated RECs when it is economically beneficial to do so.  To the extent that a supplier, like PSNH, does not possess sufficient RECs to satisfy its RPS requirements, it makes up any shortfall by making an alternative compliance payment at a rate per REC established by law.  The costs of both the RECs and alternative compliance payments are recovered by PSNH through its default energy service rates charged 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 2015, the total RPS obligation was 19.5 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 its GSC rate.

Massachusetts' RPS program also requires electricity suppliers to meet renewable energy standards.  For 2015, the requirement was 19.25 percent, and will ultimately reach 22.1 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

We have recorded a liability for what we believe, based upon currently available information, is our reasonably estimable environmental investigation, remediation, and/or Natural Resource Damages costs for waste disposal sites for which we have probable liability.  Under federal and state law, government agencies and private parties can attempt to impose liability on us for recovery of investigation and remediation costs at hazardous waste sites.  As of December 31, 2015, the liability recorded 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 $51.1 million, representing 64 sites.  These costs could be significantly higher if additional 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 currently have partial or full ownership responsibilities at former MGP sites that have a reserve balance of $45.5 million of the total $51.1 million as of December 31, 2015.  Many 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.

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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 endangers 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 coal- and oil-fired 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.  The third three-year control period took effect on January 1, 2015 and extends through December 31, 2017.  In this control period, each regulated power plant must hold CO₂ allowances equal to 50 percent of its emissions during each of the first two years of the three-year period, and hold CO₂ allowances equal to 100 percent of its remaining emissions for the three-year control period at the end of the period.

PSNH anticipates that its generating units will emit between one million and three 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, which emissions are an offset.  PSNH satisfied its RGGI requirements by purchasing CO₂ allowances at auction.  The cost of complying with RGGI requirements is recoverable from PSNH customers.  Current legislation provides that the portion of the RGGI auction proceeds in excess of $1 per allowance will be refunded to customers.

Because none of Eversource Energy's other subsidiaries, CL&P, NSTAR Electric or WMECO, currently owns any generating assets (other than WMECO's solar photovoltaic facilities 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 energy suppliers to satisfy energy supply requirements to CL&P, NSTAR Electric and WMECO are likely to 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 currently 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 completing the relicensing application for its 6.5 MW Eastman Falls Hydro Station, the license for which expires in 2017.

EMPLOYEES

As of December 31, 2015, Eversource Energy employed a total of 7,943 employees, excluding temporary employees, of which 1,037 were employed by CL&P, 1,240 were employed by NSTAR Electric, 694 were employed by PSNH, and 291 were employed by WMECO.  Approximately 50 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 14 collective bargaining agreements.

INTERNET INFORMATION

Our website address is www.eversource.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 Eversource Energy'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.  Information contained on the Company's website or that can be accessed through the website is not incorporated into and does not constitute a part of this Annual Report on Form 10-K.  Printed copies of these reports may be obtained free of charge by writing to our Investor Relations Department at Eversource Energy, 107 Selden Street, Berlin, CT 06037.  

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Item 1A.

Risk Factors

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

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

Cyber breaches, acts of war or terrorism, physical attacks or grid disturbances resulting from internal or external sources could target our transmission, distribution and generation facilities or our information technology systems.  Such actions could impair our ability to manage these facilities, operate our systems effectively, or properly manage our data, networks and programs, resulting in loss of service to customers.

We have instituted safeguards to protect our operational systems and information technology assets.  We devote substantial resources to network and application security, encryption and other measures to protect our computer systems and infrastructure from unauthorized access or misuse and interface with numerous external entities to improve our cybersecurity situational awareness.  FERC, through the North American Electric Reliability Corporation, requires certain safeguards to be implemented to deter cyber and/or physical attacks.  These safeguards may not always be effective due to the evolving nature of cyber and/or physical attacks.

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, physical attacks 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.

Strategic development opportunities in both electric and natural gas transmission may not be successful and projects may not commence operation as scheduled or be completed, which could have a material adverse effect on our business prospects.

We are pursuing broader strategic development investment opportunities that will benefit the New England region related to the construction of electric and natural gas transmission facilities, interconnections to generating resources and other investment opportunities.  The development, construction and expansion of electric transmission and natural gas transmission facilities involve numerous risks.  Various factors could result in increased costs or result in delays or cancellation of these projects.  Risks include regulatory approval processes, new legislation, economic events or factors, environmental and community concerns, design and siting issues, difficulties in obtaining required rights of way, competition from incumbent utilities and other entities, 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 or our future growth opportunities may not be realized as anticipated.

As a result of legislative and regulatory changes during 2015, the states in which we provide service have implemented new procedures to select for construction new major electric transmission and gas pipeline facilities.  These procedures require the review of competing projects and permit the selection of only those projects that are expected to provide the greatest benefit to customers.  If the projects in which we have invested are not selected for construction, it would have a material adverse effect on our future financial position, results of operations and cash flows.

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

The rates that our electric and gas companies charge their customers are determined by their state regulatory commissions and by FERC.  These commissions also regulate the companies' accounting, operations, the issuance of certain securities and certain other matters.  FERC also regulates the transmission of electric energy, the sale of electric energy at wholesale, accounting, issuance of certain securities and certain other matters.

Under state and federal law, our electric and gas 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 regulatory commissions for review and approval.

The FERC has jurisdiction over our transmission costs recovery and the allowed return on equity.  The ROE has been contested by outside parties as unjust and unreasonable.  Certain outside parties have filed three complaints against all electric companies under the jurisdiction of ISO-NE alleging that the ROE is unjust and unreasonable.  The first complaint, which was concluded in 2015, resulted in a decrease of the allowed ROE.  The second and third complaints are currently under review with the FERC.  The FERC has initiated a review of the regional and local transmission rates due to a lack of adequate transparency.  FERC also found that the formula rates generally lacked sufficient details to determine how costs are derived and recovered in rates.

A federal appeals court decision has upheld the FERC's authority to order major changes to transmission planning and cost allocation in FERC Order No. 1000 and Order No. 1000-A, including transmission planning for public policy needs, and the requirement that utilities remove from their transmission tariffs their rights of first refusal to build transmission.  Additionally, the FERC affirmed that it can eliminate our right of first refusal to build transmission in New England even though the FERC previously approved and granted special protections to these rights.  Implementation of FERC's goals in New England, including within our service territories, may expose us to competition for construction of transmission projects, additional regulatory considerations, and potential delay with respect to future transmission projects, which may adversely affect our results of operation.

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There is no assurance that the commissions will approve the recovery of all costs incurred by our electric and gas companies, including costs for construction, operation and maintenance, as well as a reasonable return on their respective regulated assets.  The amount of costs incurred by the 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.

If our settlement agreement regarding the divestiture of our generation assets in New Hampshire is not approved, it could have a material adverse effect on our earnings.

Under our settlement agreement for the divestiture of our generation assets in New Hampshire, we will be entitled to collect from customers an amount equal to the difference between the proceeds from the sale of these assets and the undepreciated book value of those assets.  Costs related to the divestiture would also be recoverable.  To minimize the financial impact on customers in New Hampshire, the legislature passed legislation that allows for the securitization of stranded costs to be recovered.  If the NHPUC does not approve the settlement, we may not be able to fully recover these costs in future rate proceedings, which could have a material adverse effect on our financial position, results of operations and cash flows.

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

Our ability to properly operate our transmission, distribution and generation systems is critical to the financial performance of our business.  Our transmission, distribution and generation businesses face several operational risks, including the breakdown, failure of, or damage to operating equipment, information technology systems, 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; 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.  Many of our transmission projects are expected to alleviate identified reliability issues and reduce customers' costs. However, if the in-service date for one or more of these projects is delayed due to economic events or factors, or regulatory or other delays, the risk of failures in the electricity transmission system may increase.  Any 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.  Outages at generating stations may be deemed imprudent by the NHPUC resulting in disallowance of replacement power and repair 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.

Increases in electric and gas prices and/or a weak economy can lead to changes in legislative and regulatory policy promoting increased 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 natural gas sales in our service territories.  Economic downturns or periods of high energy supply costs can also impact customers’ ability to pay their energy bills, resulting in increased bad debt expense.  If energy use were to decline or bad debt expense were to increase, without corresponding adjustments in rates at our electric and gas companies that do not currently have revenue decoupling, then our revenues would be reduced, which would have an adverse effect on our financial position, results of operations and cash flows.

Severe storms could cause significant damage to any of our 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 regulators and 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.

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.  As of December 31, 2015, goodwill totaled $3.5 billion.  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.  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 financial position, results of operations and total capitalization.  The annual goodwill impairment test in 2015 resulted in a conclusion that our goodwill is not impaired.

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

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Because utility companies, including our electric and natural gas utility subsidiaries, have large 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 Eversource Energy and its subsidiaries; may make state legislatures, utility commissions and other regulatory authorities less likely to view Eversource Energy and its subsidiaries in a favorable light; and may cause Eversource Energy 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 the business, results of operations, cash flow and financial condition of Eversource Energy and each of its utility subsidiaries.

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.

The unauthorized access to and the misappropriation of confidential and proprietary customer, employee, financial or system operating information could adversely affect our business operations and adversely impact our reputation.

In the regular course of business we maintain sensitive customer, employee, financial and system operating information and are required by various federal and state laws to safeguard this information.  Cyber intrusions, security breaches, theft or loss of this information by cyber crime or otherwise could lead to the release of critical operating information or confidential customer or employee information, which could adversely affect our business operations or adversely impact our reputation, and could result in significant costs, fines and litigation.  We maintain limited privacy protection liability insurance to cover limited damages and defense costs arising from unauthorized disclosure of, or failure to protect, private information as well as costs for notification to, or for credit card monitoring of, customers, employees and other persons in the event of a breach of private information.  This insurance covers amounts paid to avert, prevent or stop a network attack or the disclosure of personal information, and costs of a qualified forensics firm to determine the cause, source and extent of a network attack or to investigate, examine and analyze our network to find the cause, source and extent of a data breach.  While we have implemented measures designed to prevent cyber-attacks and mitigate their effects should they occur.  These measures may not be effective due to the continually evolving nature of efforts to access confidential information.

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 Eversource 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 postretirement benefit plans.

We provide a defined benefit pension plan and other postretirement 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 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 financings and negatively affect our financial position, results of operations or cash flows.  For further information, see Note 9A, "Employee Benefits - Pensions and Postretirement Benefits Other Than Pensions," to the financial statements.

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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, 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 government agencies .  Although we would expect that any costs of these rules and regulations would be recovered from customers, their impact on energy use by customers and the ultimate impact on our business would be dependent upon the specific rules and regulations adopted and cannot be determined at this time.  The impact of these additional costs to customers could lead to a further reduction in energy consumption resulting in a decline in electricity and gas sales in our service territories, which would have an adverse impact on our business and financial position, results of operations or cash flows.  Any failure by us to comply with environmental laws and regulations, even if due to factors beyond our control, or reinterpretations of existing requirements, could also increase costs.  Existing environmental laws and regulations may be revised or new laws and regulations seeking to protect the environment may be adopted or become applicable to us.  Revised or additional laws could result in significant additional expense and operating restrictions on our facilities or increased compliance costs, which may not be fully recoverable in distribution company rates.  The cost impact of any such laws, rules or regulations would be dependent upon the specific requirements adopted and cannot be determined at this time.  For further information, see Item 1, Business - Other Regulatory and Environmental Matters, included in this Annual Report on Form 10-K.

As a holding company with no revenue-generating operations, Eversource parent's liquidity is dependent on dividends from its subsidiaries, its commercial paper program, and its ability to access the long-term debt and equity capital markets.

Eversource 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 Eversource parent, and/or Eversource parent's ability to access its commercial paper program or the long-term debt and equity capital markets.  Prior to funding Eversource parent, the subsidiary companies have financial obligations that must be satisfied, including among others, their operating expenses, debt service, preferred dividends of certain subsidiaries, and obligations to trade creditors.  Additionally, the subsidiary companies could retain their free cash flow to fund their capital expenditures in lieu of receiving equity contributions from Eversource parent.  Should the subsidiary companies not be able to pay dividends or repay funds due to Eversource parent, or if Eversource parent cannot access its commercial paper programs or the long-term debt and equity capital markets, Eversource 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, 2015, Eversource and our electric operating subsidiaries owned the following:
		Electric		Electric
Eversource		Distribution		Transmission
Number of substations owned		512		66
Transformer capacity (in kVa)		41,484,000		13,780,000
Overhead lines (in circuit miles)		40,258		3,932
Capacity range of overhead transmission lines (in kV)		N/A		69 to 345
Underground lines (distribution in circuit miles and     transmission in cable miles)		16,778		407
Capacity range of underground transmission lines (in kV)		N/A		69 to 345

			CL&P				NSTAR Electric				PSNH				WMECO
			Distribution		Transmission		Distribution		Transmission		Distribution		Transmission		Distribution		Transmission
Number of substations owned			182		19		133		24		154		16		43		7
Transformer capacity (in kVa)			19,605,000		3,117,000		11,431,000		6,728,000		5,257,000		3,868,000		5,191,000		67,000
Overhead lines (in circuit miles)			16,951		1,662		7,983		750		11,913		1,039		3,411		481
Capacity range of overhead     transmission lines (in kV)			N/A		69 to 345		N/A		115 to 345		N/A		115 to 345		N/A		69 to 345
Underground lines (distribution     in circuit miles and     transmission in cable miles)			6,528		136		7,354		260		1,821		1		1,075		10
Capacity range of underground     transmission lines (in kV)			N/A		69 to 345		N/A		115 to 345		N/A		115		N/A		115

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									NSTAR
			Eversource			CL&P			Electric			PSNH			WMECO
Underground and overhead line transformers in service			618,387			288,352			126,353			160,848			42,834
Aggregate capacity (in kVa)			35,097,967			15,300,765			11,429,921			6,202,270			2,165,011

Electric Generating Plants

As of December 31, 2015, PSNH owned the following electric generating plants:  

Type of Plant		Number of Units		Year Installed		Claimed Capability* (kilowatts)
Steam Plants		5		1952-74		935,343
Hydro		20		1901-83		58,115
Internal Combustion		5		1968-70		101,869
Biomass		1		2006		42,594
Total PSNH Generating Plant		31				1,137,921

*

Claimed capability represents winter ratings as of December 31, 2015.  The combined nameplate capacity of the generating plants is approximately 1,200 MW.

As of December 31, 2015, WMECO owned the following electric generating plants:  

Type of Plant			Number of Sites		Year Installed		Claimed Capability** (kilowatts)
Solar Fixed Tilt, Photovoltaic			3		2010-14		8,000

** 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, 2015, Yankee Gas owned 28 active gate stations, 203 district regulator stations, and approximately 3,317 miles of natural gas main pipeline.  Yankee Gas also owns a liquefaction and vaporization plant and above ground storage tank with a storage capacity equivalent of 1.2 Bcf of natural gas in Waterbury, Connecticut.

As of December 31, 2015, NSTAR Gas owned 21 active gate stations, 164 district regulator stations, and approximately 3,250 miles of natural gas main pipeline.  Hopkinton, another subsidiary of Eversource, owns a satellite vaporization plant and above ground storage tanks in Acushnet, MA.  In addition, Hopkinton owns a liquefaction and vaporization plant with above ground storage tanks in Hopkinton, MA.  Combined, the two plants' tanks have an aggregate storage capacity equivalent to 3.5 Bcf of natural gas that is provided to NSTAR Gas under contract.

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 I 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 natural gas distribution pipelines are obtained from municipal and other state authorities who, in granting these locations, act as agents for the state. In some cases the actions of these authorities are subject to appeal to the DPU.  The rights to these locations are not limited in time and are subject to the action of these authorities and the legislature.  Under Massachusetts law, with the exception of municipal-owned utilities, no other entity may provide electric or natural gas delivery service to retail

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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 natural gas in the areas in which Yankee Gas supplies natural 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 natural gas utility under a valid franchise of its own or are not subject to an exclusive franchise of another natural 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 natural 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.  

In June 2013, FERC approved CYAPC, YAEC and MYAPC to reduce rates in their wholesale power contracts through the application of the DOE proceeds for the benefit of customers.  Changes to the terms of the wholesale power contracts became 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 passed on to customers.

On September 17, 2014, in accordance with the MYAPC’s three-year refund plan, MYAPC returned a portion of the DOE Phase I Damages proceeds to the member companies, including CL&P, NSTAR Electric, PSNH, and WMECO, in the amount of $3.2 million, $1.1 million, $1.4 million and $0.8 million, respectively.  On September 28, 2015, MYAPC returned the remaining DOE Phase I Damages proceeds to the member companies, including CL&P, NSTAR Electric, PSNH, and WMECO, in the amount of $2.3 million, $0.8 million, $1 million and $0.6 million, respectively.  

DOE Phase II Damages - In December 2007, the Yankee Companies each filed subsequent lawsuits against the DOE seeking recovery of actual damages incurred related to the alleged failure of the DOE to provide for a permanent facility to store spent nuclear fuel generated in years 2001 through 2008 for CYAPC and YAEC and from 2002 through 2008 for MYAPC (DOE Phase II Damages).  In November 2013, the court issued a

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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.

In March and April 2014, CYAPC, YAEC and MYAPC received payment of $126.3 million, $73.3 million and $35.8 million, respectively, of the DOE Phase II Damages proceeds and made the required informational filing with FERC in accordance with the process and methodology outlined in the 2013 FERC order.  The Yankee Companies returned the DOE Phase II Damages proceeds to the member companies, including CL&P, NSTAR Electric, PSNH, and WMECO, for the benefit of their respective customers, on June 1, 2014.  Refunds to CL&P's, NSTAR Electric's, PSNH's and WMECO's customers for these DOE proceeds began in the third quarter of 2014 and all refunds under these proceedings have been disbursed.

DOE Phase III Damages - In August 2013, the Yankee Companies each filed subsequent lawsuits against the DOE seeking recovery of actual damages incurred in the years 2009 through 2012.  The trial on this matter was held on June 30 and July 1, 2015, with a post-trial briefing that concluded on October 14, 2015.  The parties are awaiting a decision from the court.  

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. 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.  CLF filed an amended complaint on May 28, 2013, related to routine maintenance of the boiler performed in 2008 and 2009.  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 continues to believe this suit is without merit and intends to defend it vigorously.  However, at this time the case has been stayed while the State settlement process related to the divestiture of generating assets, including Merrimack Station, continues.

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 and federal regulatory and rate proceedings, civil lawsuits related thereto, and information about proceedings relating to power, transmission and pricing issues; "- Nuclear Fuel Storage" 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 Eversource Energy as of February 16, 2016.  All of the Company's officers serve terms of one year and until their successors are elected and qualified:

Name		Age		Title
Thomas J. May		68		Chairman of the Board, President and Chief Executive Officer
James J. Judge		60		Executive Vice President and Chief Financial Officer
Leon J. Olivier		67		Executive Vice President-Enterprise Energy Strategy and Business Development
David R. McHale		55		Executive Vice President and Chief Administrative Officer
Werner J. Schweiger		56		Executive Vice President and Chief Operating Officer
Gregory B. Butler		58		Senior Vice President and General Counsel
Christine M. Carmody*		53		Senior Vice President-Human Resources of Eversource Service
Joseph R. Nolan, Jr.*		52		Senior Vice President-Corporate Relations of Eversource Service
Jay S. Buth		46		Vice President, Controller and Chief Accounting Officer

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

Thomas J. May.  Mr. May has served as Chairman of the Board of Eversource Energy since October 10, 2013, and as President and Chief Executive Officer and as a Trustee of Eversource Energy; as Chairman and a Director of CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO and Yankee Gas; and as Chairman, President and Chief Executive Officer and a Director of Eversource Service since April 10, 2012.  Mr. May has served as a Director of NSTAR Electric and NSTAR Gas since September 27, 1999.  Mr. May previously 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 of Eversource Energy Foundation, Inc. since October 15, 2013, and as a Director of Eversource Energy Foundation, Inc. since April 10, 2012.  He previously served as President of Eversource Energy Foundation, Inc. from October 15, 2013 to September 29, 2014.  He has served as a Trustee of the NSTAR Foundation since August 18, 1987.  

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James J. Judge.  Mr. Judge has served as Executive Vice President and Chief Financial Officer of Eversource Energy, CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO, Yankee Gas and Eversource Service and as a Director of CL&P, PSNH, WMECO, Yankee Gas and Eversource Service since April 10, 2012 and 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 as a Director of Eversource Energy Foundation, Inc. since April 10, 2012.  He has served as a Trustee of the NSTAR Foundation since December 12, 1995.  

Leon J. Olivier.  Mr. Olivier has served as Executive Vice President-Enterprise Energy Strategy and Business Development of Eversource Energy since September 2, 2014 and as a Director of Eversource Service since January 17, 2005.  Mr. Olivier previously served as Executive Vice President and Chief Operating Officer of Eversource Energy and Eversource Service from May 13, 2008 until September 2, 2014, and as Chief Executive Officer of NSTAR Electric and NSTAR Gas from April 10, 2012 until August 11, 2014, of CL&P, PSNH, WMECO and Yankee Gas from January 15, 2007 to September 29, 2014, and of CL&P from September 10, 2001 to September 29, 2014, and as a Director of NSTAR Electric and NSTAR Gas from November 27, 2012 to September 29, 2014, of PSNH, WMECO and Yankee Gas from January 17, 2005 to September 29, 2014, and of CL&P from September 10, 2001 to September 29, 2014.   Previously, Mr. Olivier served as Executive Vice President-Operations of Eversource Energy from February 13, 2007 to May 12, 2008.  He has served as a Director of Eversource Energy Foundation, Inc. since April 1, 2006.  Mr. Olivier has served as a Trustee of the NSTAR Foundation since April 10, 2012.  

David R. McHale.  Mr. McHale has served as Executive Vice President and Chief Administrative Officer of Eversource Energy and Eversource Service since April 10, 2012 and as a Director of Eversource Service since January 1, 2005.  Mr. McHale previously served as Executive Vice President and Chief Administrative Officer of CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO and Yankee Gas from April 10, 2012 to September 29, 2014 and as a Director of NSTAR Electric and NSTAR Gas from November 27, 2012 to September 29, 2014, of PSNH, WMECO and Yankee Gas from January 1, 2005 to September 29, 2014, and of CL&P from January 15, 2007 to September 29, 2014.  Previously, Mr. McHale served as Executive Vice President and Chief Financial Officer of Eversource Energy, CL&P, PSNH, WMECO, Yankee Gas and Eversource Service from January 2009 to April 2012, and as Senior Vice President and Chief Financial Officer of Eversource Energy, CL&P, PSNH, WMECO, Yankee Gas and Eversource Service from January 2005 to December 2008.  He has served as a Director of Eversource Energy Foundation, Inc. since January 1, 2005.  Mr. McHale has served as a Trustee of the NSTAR Foundation since April 10, 2012.  

Werner J. Schweiger.  Mr. Schweiger has served as Executive Vice President and Chief Operating Officer of Eversource Energy since September 2, 2014 and of Eversource Service since August 11, 2014, and as President of CL&P since June 2, 2015 and as Chief Executive Officer of CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO and Yankee Gas since August 11, 2014, and as a Director of Eversource Service, NSTAR Gas and Yankee Gas since September 29, 2014 and of CL&P, PSNH, NSTAR Electric and WMECO since May 28, 2013.  He previously served as President-Electric Distribution of Eversource Service from January 16, 2013 until August 11, 2014 and as President of NSTAR Electric from April 10, 2012 until January 16, 2013 and as a Director of NSTAR Electric from November 27, 2012 to January 16, 2013.  From February 27, 2002 until April 10, 2012, Mr. Schweiger was Senior Vice President-Operations of NSTAR Electric and NSTAR Gas.  Mr. Schweiger has served as a Director of Eversource Energy Foundation, Inc. since September 29, 2014.  He has served as a Trustee of the NSTAR Foundation since September 29, 2014.

Gregory B. Butler.  Mr. Butler has served as Senior Vice President and General Counsel of Eversource Energy since May 1, 2014, of NSTAR Electric, and NSTAR Gas since April 10, 2012, and of CL&P, PSNH, WMECO, Yankee Gas and Eversource Service since March 9, 2006.  Mr. Butler has served as a Director of NSTAR Electric and NSTAR Gas since April 10, 2012, of Eversource Service since November 27, 2012, and of CL&P, PSNH, WMECO and Yankee Gas since April 22, 2009.  Mr. Butler previously served as Senior Vice President, General Counsel and Secretary of Eversource Energy from April 10, 2012 until May 1, 2014, and as Senior Vice President and General Counsel of Eversource Energy from December 1, 2005 to April 10, 2012.  He has served as a Director of Eversource Energy Foundation, Inc. since December 1, 2002.  He has been a Trustee of the NSTAR Foundation since April 10, 2012.

Christine M. Carmody.  Ms. Carmody has served as Senior Vice President-Human Resources of Eversource Service since April 10, 2012 and as a Director of Eversource Service since November 27, 2012.  Ms. Carmody previously served as Senior Vice President-Human Resources of CL&P, PSNH, WMECO and Yankee Gas from November 27, 2012 to September 29, 2014, and of NSTAR Electric and NSTAR Gas from August 1, 2008 to September 29, 2014, and as a Director of CL&P, PSNH, WMECO and Yankee Gas from April 10, 2012 to September 29, 2014 and of NSTAR Electric and NSTAR Gas from November 27, 2012 to September 29, 2014.  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 Eversource Energy Foundation, Inc. since April 10, 2012.  She has served as a Trustee of the NSTAR Foundation since August 1, 2008.

Joseph R. Nolan, Jr.  Mr. Nolan has served as Senior Vice President-Corporate Relations of Eversource Service since April 10, 2012 and as a Director of Eversource Service since November 27, 2012.  Mr. Nolan previously served as Senior Vice President-Corporate Relations of NSTAR Electric and NSTAR Gas from April 10, 2012 to September 29, 2014, and of CL&P, PSNH, WMECO and Yankee Gas from November 27, 2012 to September 29, 2014, as a Director of CL&P, PSNH, WMECO and Yankee Gas from April 10, 2012 to September 29, 2014 and of NSTAR Electric and NSTAR Gas from November 27, 2012 to September 29, 2014.  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 Eversource Energy Foundation, Inc. since April 10, 2012, and has served as Executive Director of Eversource Energy Foundation, Inc. since October 15, 2013.  He has served as a Trustee of the NSTAR Foundation since October 1, 2000.

Jay S. Buth.  Mr. Buth has served as Vice President, Controller and Chief Accounting Officer of Eversource Energy, CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO, Yankee Gas and Eversource Service since April 10, 2012.  Previously, Mr. Buth served as Vice President-Accounting and Controller of Eversource Energy, CL&P, PSNH, WMECO, Yankee Gas and Eversource Service 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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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

Eversource.  Our common shares are listed on the New York Stock Exchange.  The ticker symbol is "ES."  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
2015		First		$	56.83		$	48.54		$	0.4175

		Second			51.42			45.20			0.4175
		Third			52.15			44.64			0.4175
		Fourth			52.85			48.18			0.4175
2014		First		$	45.69		$	41.28		$	0.3925

		Second			47.60			44.28			0.3925
		Third			47.37			41.92			0.3925
		Fourth			56.66			44.37			0.3925

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 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 Eversource.

Common stock dividends approved and paid to Eversource during the year were as follows:

	For the Years Ended December 31,
(Millions of Dollars)	2015			2014
CL&P	$	196.0		$	171.2
NSTAR Electric		198.0			253.0
PSNH		106.0			66.0
WMECO		37.2			60.0

(b)

Holders

As of January 31, 2016, there were 42,493 registered common shareholders of our company on record.  As of the same date, there were a total of 317,191,249 common shares issued.

(d)

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.

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(e)

Performance Graph

The performance graph below illustrates a five-year comparison of cumulative total returns based on an initial investment of $100 in 2010 in Eversource Energy common stock, as compared with the S&P 500 Stock Index and the EEI Index for the period 2011 through 2015, assuming all dividends are reinvested.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The following table discloses purchases of our common shares made by us or on our behalf for the periods shown below.  The common shares purchased consist of open market purchases made by the Company or an independent agent.  These share transactions related to shares awarded under the Company's Incentive Plan and Dividend Reinvestment Plan and matching contributions under the Eversource 401k Plan.

		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, 2015		117,887		$	50.33	-	-
		November 1 - November 30, 2015		3,178			50.76	-	-
		December 1 - December 31, 2015		6,001			51.17	-	-
		Total		127,066		$	50.38	-	-

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Item 6.				Selected Consolidated Financial Data
Eversource Selected Consolidated Financial Data (Unaudited)
(Thousands of Dollars, except percentages and   common share information)					2015			2014			2013			2012 (a)			2011
Balance Sheet Data:
	Property, Plant and Equipment, Net				$	19,892,441		$	18,647,041		$	17,576,186		$	16,605,010		$	10,403,065
	Total Assets (b)					30,580,309			29,740,387			27,760,315			28,269,780			15,617,627
	Total Capitalization (b) (c) (d)					19,542,240			18,946,395			18,042,052			17,323,068			9,048,882
	Obligations Under Capital Leases (c)					8,222			9,434			10,744			11,071			12,358
Income Statement Data:
	Operating Revenues				$	7,954,827		$	7,741,856		$	7,301,204		$	6,273,787		$	4,465,657
	Net Income					886,004			827,065			793,689			533,077			400,513
	Net Income Attributable to Noncontrolling Interests					7,519			7,519			7,682			7,132			5,820
	Net Income Attributable to Common Shareholders				$	878,485		$	819,546		$	786,007		$	525,945		$	394,693
Common Share Data:
	Net Income Attributable to Common Shareholders:
		Basic Earnings Per Common Share			$	2.77		$	2.59		$	2.49		$	1.90		$	2.22
		Diluted Earnings Per Common Share			$	2.76		$	2.58		$	2.49		$	1.89		$	2.22
	Weighted Average Common Shares Outstanding:
		Basic				317,336,881			316,136,748			315,311,387			277,209,819			177,410,167
		Diluted				318,432,687			317,417,414			316,211,160			277,993,631			177,804,568
	Dividends Declared Per Common Share				$	1.67		$	1.57		$	1.47		$	1.32		$	1.10
	Market Price - Closing (high) (e)				$	54.52		$	56.15		$	45.33		$	40.57		$	36.31
	Market Price - Closing (low) (e)				$	44.63		$	41.52		$	38.67		$	33.53		$	30.46
	Market Price - Closing (end of year) (e)				$	51.07		$	53.52		$	42.39		$	39.08		$	36.07
	Book Value Per Common Share (end of year)				$	32.64		$	31.47		$	30.49		$	29.41		$	22.65
	Tangible Book Value Per Common Share (end of year) (f)				$	21.54		$	20.37		$	19.32		$	18.21		$	21.03
	Rate of Return Earned on Average Common Equity (%) (g)					8.7			8.4			8.3			7.9			10.1
	Market-to-Book Ratio (end of year) (h)					1.6			1.7			1.4			1.3			1.6
Capitalization:
	Total Equity					53	%		53	%		53	%		53	%		44	%
	Preferred Stock Not Subject to Mandatory Redemption					1			1			1			1			1
	Long-Term Debt (b) (c) (d)					46			46			46			46			55
						100	%		100	%		100	%		100	%		100	%
CL&P Selected Financial Data (Unaudited)
(Thousands of Dollars)					2015			2014			2013			2012			2011
Operating Revenues					$	2,802,675		$	2,692,582		$	2,442,341		$	2,407,449		$	2,548,387
Net Income						299,360			287,754			279,412			209,725			250,164
Cash Dividends on Common Stock						196,000			171,200			151,999			100,486			243,218
Property, Plant and Equipment, Net						7,156,809			6,809,664			6,451,259			6,152,959			5,827,384
Total Assets (b)						9,592,957			9,344,400			8,965,906			9,127,602			8,775,451
Long-Term Debt (b) (c)						2,763,682			2,826,243			2,726,613			2,848,303			2,567,808
Preferred Stock Not Subject to Mandatory Redemption						116,200			116,200			116,200			116,200			116,200
Obligations Under Capital Leases (c)						7,624			8,439			9,309			9,960			10,715
(a)		The 2012 results include the operations of NSTAR beginning April 10, 2012.
(b)		The 2011 through 2014 amounts reflect reclassifications due to the adoption of new accounting guidance that changed the balance sheet presentation of debt issuance costs.  Unamortized debt issuance costs are now presented as a direct reduction from the carrying amount of the debt liability rather than as a deferred cost.  Prior year amounts were retrospectively adjusted to conform to the current year presentation.  See Note 1C, "Summary of Significant Accounting Policies – Accounting Standards," for further information.
(c)		Includes portions due within one year.
(d)		Excludes RRBs.
(e)		Market price information reflects closing prices as reflected by the New York Stock Exchange.
(f)		Common Shareholders' Equity adjusted for goodwill and intangibles divided by total common shares outstanding.
(g)		Net Income Attributable to Common Shareholders divided by average Common Shareholders' Equity.
(h)		The closing market price divided by the book value per share.
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.

26

Eversource Selected Consolidated Sales Statistics
		2015			2014			2013			2012 (a)			2011
Revenues:  (Thousands)
Residential	$	3,608,155		$	3,288,313		$	3,073,181		$	2,731,951		$	2,091,270
Commercial		2,476,686			2,471,440			2,387,535			1,604,661			1,236,374
Industrial		326,564			348,698			339,917			753,974			252,878
Wholesale		411,749			447,899			486,515			357,223			350,413
Other and Eliminations		110,013			97,090			56,547			130,137			47,485
Total Electric		6,933,167			6,653,440			6,343,695			5,577,946			3,978,420
Natural Gas		993,662			1,002,880			855,601			572,857			430,799
Total - Regulated Companies		7,926,829			7,656,320			7,199,296			6,150,803			4,409,219
Other and Eliminations		27,998			85,536			101,908			122,984			56,438
Total	$	7,954,827		$	7,741,856		$	7,301,204		$	6,273,787		$	4,465,657
Regulated Companies - Sales Volumes:
Electric (GWh)
Residential		21,441			21,317			21,896			19,719			14,766
Commercial		27,598			27,449			27,787			24,537			14,628
Industrial		5,577			5,676			5,648			5,462			4,418
Wholesale		3,215			3,018			855			2,154			1,020
Total Electric		57,831			57,460			56,186			51,872			34,832
Natural Gas (million cubic feet)		102,999			104,191			98,258			69,894			46,880
Regulated Companies - Customers:  (Average)
Residential		2,747,679			2,734,047			2,718,727			2,711,407			1,710,342
Commercial		374,552			373,511			371,897			370,389			199,240
Industrial		7,868			8,016			8,109			8,279			7,083
Total Electric		3,130,099			3,115,574			3,098,733			3,090,075			1,916,665
Natural Gas		506,175			499,186			493,563			483,770			207,753
Total - Regulated Companies		3,636,274			3,614,760			3,592,296			3,573,845			2,124,418
(a) The 2012 results include the operations of NSTAR beginning April 10, 2012.
CL&P Selected Sales Statistics
		2015			2014			2013			2012			2011
Revenues:  (Thousands)
Residential	$	1,641,165		$	1,474,181		$	1,294,160		$	1,263,845		$	1,345,290
Commercial		841,093			879,343			780,585			732,620			758,145
Industrial		129,544			149,220			129,557			126,165			126,783
Wholesale		128,169			146,787			219,367			214,807			278,751
Other		62,704			43,051			18,672			70,012			39,418
Total	$	2,802,675		$	2,692,582		$	2,442,341		$	2,407,449		$	2,548,387
Sales Volumes:  (GWh)
Residential		10,094			10,026			10,314			9,978			10,092
Commercial		9,635			9,643			9,770			9,705			9,809
Industrial		2,342			2,377			2,320			2,426			2,414
Wholesale		712			736			851			1,155			1,592
Total		22,783			22,782			23,255			23,264			23,907
Customers:  (Average)
Residential		1,117,778			1,111,467			1,105,417			1,103,397			1,100,740
Commercial		109,339			109,093			108,735			108,589			108,235
Industrial		3,163			3,213			3,247			3,301			3,331
Total		1,230,280			1,223,773			1,217,399			1,215,287			1,212,306

27

Item 7.

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

EVERSOURCE ENERGY AND SUBSIDIARIES

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

On April 30, 2015, the Company's legal name was changed from Northeast Utilities to Eversource Energy.  CL&P, NSTAR Electric, PSNH and WMECO are each doing business as Eversource Energy.  

Refer to the Glossary of Terms included in this combined 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 Eversource.  The earnings and EPS of each business discussed below do not represent a direct legal interest in the assets and liabilities of 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 Common Shareholders of each business by the weighted average diluted Eversource common shares outstanding for the period.  The discussion below also includes non-GAAP financial measures referencing our 2015, 2014 and 2013 earnings and EPS excluding certain integration costs incurred by Eversource parent and our Regulated companies.  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 2015, 2014 and 2013 results without including the impact of these items.  Due to the nature and significance of these items on Net Income Attributable to Common Shareholders, 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 Common Shareholders 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 Common Shareholders are included under "Financial Condition and Business Analysis – Overview – Consolidated" and "Financial Condition and Business Analysis – Overview – Regulated Companies" in Management's Discussion and Analysis of Financial Condition and Results of Operations, herein.  

Financial Condition and Business Analysis

Executive Summary

Results:

·

We earned $878.5 million, or $2.76 per share, in 2015, compared with $819.5 million, or $2.58 per share, in 2014.  Excluding integration costs, we earned $894.3 million, or $2.81 per share, in 2015 and $841.6 million, or $2.65 per share, in 2014.  

·

Our electric distribution segment, which includes generation, earned $507.9 million, or $1.59 per share, in 2015, compared with $462.4 million, or $1.45 per share, in 2014.  Our electric transmission segment earned $304.5 million, or $0.96 per share, in 2015, compared with $295.4 million, or $0.93 per share, in 2014.  Our natural gas distribution segment earned $72.4 million, or $0.23 per share, in 2015, compared with $72.3 million, or $0.23 per share, in 2014.  The 2015 electric and natural gas distribution results exclude $0.8 million of after-tax integration costs.

·

Eversource parent and other companies earned $9.5 million, or $0.03 per share, in 2015, compared with $11.5 million, or $0.04 per share, in 2014.  The 2015 and 2014 results exclude $15 million, or $0.05 per share, and $22.1 million, or $0.07 per share, respectively, of after-tax integration costs.

Liquidity:

·

Cash flows provided by operating activities totaled $1.4 billion in 2015, compared with $1.6 billion in 2014.  Investments in property, plant and equipment totaled $1.7 billion in 2015 and $1.6 billion in 2014.  Cash and cash equivalents totaled $23.9 million as of December 31, 2015, compared with $38.7 million as of December 31, 2014.

·

In 2015, we issued approximately $1.23 billion of new long-term debt consisting of $450 million by Eversource parent, $350 million by CL&P, $250 million by NSTAR Electric, $100 million by NSTAR Gas, and $75 million by Yankee Gas.  In 2015, we repaid $212 million of existing long-term debt consisting of $162 million by CL&P and $50 million by WMECO.  

·

In 2015, we paid cash dividends on common shares of $529.8 million, compared with $475.2 million in 2014.  On February 3, 2016, our Board of Trustees approved a common share dividend payment of $0.445 per share, payable on March 31, 2016 to shareholders of record as of March 2, 2016.  The 2016 dividend represented an increase of 6.6 percent over the dividend paid in December 2015, and is the equivalent to dividends on common shares of approximately $565 million on an annual basis.  

28

·

We project to make capital expenditures of approximately $9.2 billion from 2016 through 2019.  Of the $9.2 billion, we expect to invest approximately $4.9 billion in our electric and natural gas distribution segments and $3.9 billion in our electric transmission segment.  In addition, we project to invest approximately $0.4 billion in information technology and facilities upgrades and enhancements.  These projections do not include capital investments related to Access Northeast or Clean Energy Connect.  

Strategic, Legislative, Regulatory, Policy and Other Items:

·

On December 18, 2015, the New Hampshire Site Evaluation Committee (NH SEC) accepted NPT’s application as complete allowing the formal siting process to move forward.  The project is expected to be operational in the first half of 2019.  On January 28, 2016, NPT bid into the three-state Clean Energy RFP process.  

·

The Clean Energy Connect Project is a planned transmission, wind and hydro generation project that we plan to co-develop with experienced renewable generation companies.  On January 28, 2016, the Clean Energy Connect project was bid into the three-state Clean Energy RFP process.  Our investment, should the Clean Energy Connect Project be selected in the RFP process, is currently estimated to be at least $400 million and will consist of the Massachusetts portion of a new 25-mile, 345 kV transmission line with a 600 MW capacity.  

·

On January 28, 2016, the DPU approved NSTAR Electric’s, WMECO’s, and NSTAR Gas’ three-year electric and natural gas energy efficiency plan, which was jointly developed with other Massachusetts electric distribution companies (EDCs) and natural gas distribution companies.  On December 31, 2015, DEEP approved CL&P’s and Yankee Gas’ three-year electric and natural gas C&LM plan, which was jointly developed with other Connecticut EDCs and natural gas distribution companies.  These electric and natural gas energy efficiency and C&LM plans include the ability to earn performance incentives as well as recover LBR for NSTAR Electric until it is operating under a decoupled rate structure.

·

On January 7, 2015, the DPU issued an order concluding that NSTAR Electric had removed energy-related bad debt costs from base distribution rates effective January 1, 2006.  As a result of the DPU order, in the first quarter of 2015 NSTAR Electric increased its regulatory assets and reduced its operations and maintenance expense by $24.2 million for energy-related bad debt costs through 2014, resulting in after-tax earnings of $14.5 million.  NSTAR Electric filed for recovery of the energy-related bad debt costs regulatory asset from customers and on November 20, 2015, the DPU approved NSTAR Electric’s proposed rate increase to recover these costs over a 12-month period, beginning January 1, 2016.  

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 Common Shareholders and diluted EPS, is as follows:

		For the Years Ended December 31,
		2015						2014						2013
(Millions of Dollars, Except Per Share Amounts)		Amount			Per Share			Amount			Per Share			Amount			Per Share
Net Income Attributable to Common Shareholders (GAAP)		$	878.5		$	2.76		$	819.5		$	2.58		$	786.0		$	2.49
Regulated Companies		$	884.8		$	2.78		$	830.1		$	2.61		$	774.9		$	2.45
Eversource Parent and Other Companies			9.5			0.03			11.5			0.04			24.9			0.08
Non-GAAP Earnings			894.3			2.81			841.6			2.65			799.8			2.53
Integration Costs (after-tax)			(15.8)			(0.05)			(22.1)			(0.07)			(13.8)			(0.04)
Net Income Attributable to Common Shareholders (GAAP)		$	878.5		$	2.76		$	819.5		$	2.58		$	786.0		$	2.49

The 2015 and 2014 integration costs are associated with our branding efforts and severance costs.  

Regulated Companies:  Our Regulated companies consist of the electric distribution, electric 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 and EPS is as follows:

		For the Years Ended December 31,
		2015						2014						2013
(Millions of Dollars, Except Per Share Amounts)		Amount			Per Share			Amount			Per Share			Amount			Per Share
Electric Distribution		$	507.9		$	1.59		$	462.4		$	1.45		$	427.0		$	1.35
Electric Transmission			304.5			0.96			295.4			0.93			287.0			0.91
Natural Gas Distribution			72.4			0.23			72.3			0.23			60.9			0.19
Non-GAAP Earnings			884.8			2.78			830.1			2.61			774.9			2.45
Integration Costs (after-tax)			(0.8)			-			-			-			-			-
Net Income - Regulated Companies		$	884.0		$	2.78		$	830.1		$	2.61		$	774.9		$	2.45

The 2015 Regulated companies' integration costs include severance in connection with cost saving initiatives.

29

Excluding integration costs, our electric distribution segment earnings increased $45.5 million in 2015, as compared to 2014, due primarily to the impact of the December 1, 2014 CL&P base distribution rate increase, the $27.5 million favorable earnings impact related to the resolution of NSTAR Electric’s basic service bad debt adder and the settlement with the Massachusetts Attorney General on eleven open dockets covering the CPSL program filings and the recovery of LBR related to 2009 through 2011 energy efficiency programs at NSTAR Electric, an increase in the recovery of LBR at NSTAR Electric related to 2015 energy efficiency programs, and higher retail sales volumes at NSTAR Electric and PSNH.  Partially offsetting these favorable earnings impacts were a higher effective tax rate in 2015, higher property taxes, higher depreciation expense and a $5 million contribution in 2015 to create a clean energy fund in connection with the PSNH divestiture agreement.  

Our electric transmission segment earnings increased $9.1 million in 2015, as compared to 2014, due primarily to the result of lower reserve charges associated with the FERC ROE complaint proceedings of $12.4 million recorded in 2015, as compared to $22.4 million recorded in 2014, and a higher transmission rate base as a result of an increased investment in our transmission infrastructure.  These favorable earnings impacts were partially offset by a higher effective tax rate in 2015.

Our natural gas distribution segment earnings increased $0.1 million in 2015, as compared to 2014.  Our natural gas distribution segment earnings were favorably impacted by a decrease in operations and maintenance costs primarily attributable to lower employee-related expenses, a lower effective tax rate in 2015, and additional natural gas heating customers.  These favorable earnings impacts were offset by a decrease in firm natural gas sales volumes driven by record warm weather in the fourth quarter of 2015, as compared to 2014, higher depreciation expense and higher property taxes.

Eversource Parent and Other Companies:  Excluding the impact of integration costs, Eversource parent and other companies had earnings of $9.5 million in 2015, compared with earnings of $11.5 million in 2014.  The earnings decrease was due primarily to a higher effective tax rate at Eversource parent in 2015, as compared to 2014, higher interest expense at Eversource parent as a result of new debt issuances in January 2015, and reduced earnings in 2015 from Eversource's unregulated electrical contracting business, which was sold in April 2015.  These unfavorable earnings impacts were partially offset by a reduction in operations and maintenance costs.

Electric and Natural Gas Sales Volumes:  Weather, fluctuations in energy supply costs, conservation measures (including utility-sponsored energy efficiency programs), and economic conditions affect customer energy usage.  Industrial sales volumes are less sensitive to temperature variations than residential and commercial sales volumes.  In our service territories, weather impacts electric sales volumes during the summer and both electric and natural gas sales volumes during the winter; however, natural gas sales volumes are more sensitive to temperature variations than are electric sales volumes.  Customer heating or cooling usage may not directly correlate with historical levels or with the level of degree-days that occur.

Fluctuations in retail electric sales volumes at NSTAR Electric and PSNH impact earnings ("Traditional" in the table below).  For CL&P (effective December 1, 2014) and WMECO, fluctuations in retail electric sales volumes do not impact earnings due to their respective regulatory commission approved revenue decoupling mechanisms (“Decoupled” in the table below).  These distribution revenues are decoupled from their customer sales volumes, which breaks the relationship between sales volumes and revenues recognized.  CL&P and WMECO reconcile their annual base distribution rate recovery amounts to their respective pre-established levels of baseline distribution delivery service revenues.  Any difference between the allowed level of distribution revenue and the actual amount incurred during a 12-month period is adjusted through rates in the following period.  

A summary of our retail electric GWh sales volumes and our firm natural gas sales volumes in million cubic feet and percentage changes is as follows:  

	For the Year Ended December 31, 2015 Compared to 2014
	Sales Volumes (GWh)				Percentage
Electric	2015		2014		Increase/(Decrease)
Traditional:
Residential	9,882		9,798		0.9%
Commercial	16,486		16,340		0.9%
Industrial	2,614		2,673		(2.2)%
Total - Traditional	28,982		28,811		0.6%
Decoupled:
Residential	11,559		11,519		0.3%
Commercial	11,112		11,109		- %
Industrial	2,963		3,003		(1.3)%
Total - Decoupled	25,634		25,631		- %
Total Sales Volumes	54,616		54,442		0.3%
	For the Year Ended December 31, 2015 Compared to 2014
	Sales Volumes (million cubic feet)				Percentage
Firm Natural Gas	2015		2014		Increase/(Decrease)
Residential	38,455		38,969		(1.3)%
Commercial	43,006		42,977		0.1 %
Industrial	21,538		22,245		(3.2)%
Total Sales Volumes	102,999		104,191		(1.1)%
Total, Net of Special Contracts (1)	98,458		99,500		(1.0)%

⁽¹⁾

Special contracts are unique to the natural gas distribution 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.

30

Our 2015 retail electric sales volumes at our electric utilities with a traditional rate structure (NSTAR Electric and PSNH) were slightly higher, as compared to 2014, due primarily to the impact of colder winter weather experienced in the first quarter of 2015 and warmer weather in the third quarter of 2015, partially offset by milder winter weather in the fourth quarter of 2015 throughout those service territories.  In 2015, heating degree days were 1 percent lower in the Boston metropolitan area, and 5 percent lower in New Hampshire, as compared to 2014.  Cooling degree days in 2015 were 19 percent higher in the Boston metropolitan area and 57 percent higher in New Hampshire, as compared to 2014.  Weather-normalized retail electric sales volumes were relatively unchanged in 2015, as compared to 2014.  Improved economic conditions were offset by an increase in customer conservation efforts resulting from company-sponsored energy efficiency programs.

Our firm natural gas sales volumes are subject to many of the same influences as our retail electric sales volumes.  In addition, they have benefited from customer growth in both of our natural gas distribution companies.  In 2015, consolidated firm natural gas sales volumes were lower, as compared to 2014.  The 2015 firm natural gas sales volumes were negatively impacted by record warm weather in the fourth quarter of 2015, when compared to 2014, partially offset by colder winter weather in the first quarter of 2015, as compared to 2014, throughout our natural gas service territories.  Weather-normalized Eversource consolidated firm natural gas sales volumes increased 2.5 percent in 2015, as compared to 2014, due primarily to improved economic conditions as well as residential and commercial customer growth, partially offset by customer conservation efforts resulting from company-sponsored energy efficiency programs.  On October 30, 2015, the DPU issued its order in the NSTAR Gas distribution rate case, which included the establishment of a revenue decoupling mechanism beginning January 1, 2016.    

Prior to December 1, 2014, CL&P earned LBR related to reductions in sales volume as a result of successful energy efficiency programs.  LBR was recovered from retail customers through the FMCC.  Effective December 1, 2014, CL&P no longer earns LBR due to its revenue decoupling mechanism.  NSTAR Electric recognized LBR of $60.6 million in 2015 and $39.9 million in 2014.  On January 28, 2016, NSTAR Electric received approval of a three-year energy efficiency plan, which includes recovery of LBR until it is operating under a decoupled rate structure.  

For further information, see "Regulatory Developments and Rate Matters - Massachusetts - NSTAR Electric, WMECO and NSTAR Gas Energy Efficiency Plan" and "Regulatory Developments and Rate Matters - Massachusetts - NSTAR Gas Distribution Rates"  in this Management's Discussion and Analysis of Financial Conditions and Results of Operations.

Future Outlook

2016 EPS Guidance:  We currently project 2016 earnings of between $2.90 per diluted share and $3.05 per diluted share.

Liquidity

Consolidated:  Cash and cash equivalents totaled $23.9 million as of December 31, 2015, compared with $38.7 million as of December 31, 2014.

Long-Term Debt Issuances and Repayments:  On January 15, 2015, Eversource parent issued $150 million of 1.60 percent Series G Senior Notes, due to mature in 2018, and $300 million of 3.15 percent Series H Senior Notes, due to mature in 2025.  

On May 20, 2015 and December 1, 2015, CL&P issued $300 million and $50 million, respectively, of 4.15 percent 2015 Series A First and Refunding Mortgage Bonds due to mature in 2045.  

On September 10, 2015, Yankee Gas issued $75 million of 3.35 percent 2015 Series M First Mortgage Bonds due to mature in 2025.  

On November 18, 2015, NSTAR Electric issued $250 million of 3.25 percent debentures, due to mature in 2025.  

On December 8, 2015, NSTAR Gas issued $100 million of 4.35 percent Series O First Mortgage Bonds due to mature in 2045.

The proceeds of all debt issuances, net of issuance costs, were used to repay short-term borrowings and fund capital expenditures and working capital.

On April 1, 2015, CL&P repaid at maturity the $100 million 5.00 percent 2005 Series A First and Refunding Mortgage Bonds and also redeemed the $62 million 1996A Series 1.55 percent PCRBs that were subject to mandatory tender, using short term borrowings.

On August 3, 2015, WMECO repaid at maturity the $50 million 5.24 percent Series C Senior Notes, using short-term borrowings.

Long-Term Debt Issuance Authorizations:  On November 25, 2015, PURA approved Yankee Gas’ request to extend the authorization period for issuance of up to $125 million in long-term debt from December 31, 2015 to December 31, 2016.  On December 4, 2015, the DPU authorized WMECO to issue up to $100 million in long-term debt for the period through December 31, 2016.  On December 4, 2015, the DPU approved NSTAR Electric’s request to extend the authorization period for issuance of up to $250 million in long-term debt from December 31, 2015 to December 31, 2016.  

Credit Agreements and Commercial Paper Programs:  Eversource parent, CL&P, PSNH, WMECO, NSTAR Gas and Yankee Gas are parties to a five-year $1.45 billion revolving credit facility.  On October 26, 2015, this revolving credit facility was amended and restated and the termination date was extended to September 4, 2020.  Under the revolving credit facility, CL&P has a borrowing sublimit of $600 million, and PSNH and WMECO each have borrowing sublimits of $300 million.  The revolving credit facility serves to backstop Eversource parent's $1.45 billion commercial paper program.  The commercial paper program allows Eversource parent to issue commercial paper as a form of short-term debt.  As of December 31, 2015 and 2014, Eversource parent had approximately $1.1 billion in short-term borrowings outstanding on each date under the

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Eversource parent commercial paper program, leaving $351.5 million and $348.9 million of available borrowing capacity as of December 31, 2015 and 2014, respectively.  The weighted-average interest rate on these borrowings as of December 31, 2015 and 2014 was 0.72 percent and 0.43 percent, respectively.  As of December 31, 2015, there were intercompany loans from Eversource parent of $277.4 million to CL&P, $231.3 million to PSNH and $143.4 million to WMECO.  As of December 31, 2014, there were intercompany loans from Eversource parent of $133.4 million to CL&P, $90.5 million to PSNH and $21.4 million to WMECO.  

NSTAR Electric has a five-year $450 million revolving credit facility.  On October 26, 2015, this revolving credit facility was amended and restated and the termination date was extended to September 4, 2020.  The facility serves to backstop NSTAR Electric's $450 million commercial paper program.  As of December 31, 2015 and 2014, NSTAR Electric had $62.5 million and $302 million, respectively, in short-term borrowings outstanding under its commercial paper program, leaving $387.5 million and $148 million of available borrowing capacity as of December 31, 2015 and 2014, respectively.  The weighted-average interest rate on these borrowings as of December 31, 2015 and 2014 was 0.40 percent and 0.27 percent, respectively.

Cash Flows:  Cash flows provided by operating activities totaled $1.4 billion in 2015, compared with $1.6 billion in 2014.  The decrease in operating cash flows in 2015 compared to 2014 was due primarily to the $302 million payment made to fully satisfy the obligation with the DOE, as discussed below, and an increase in purchased power and congestion costs at NSTAR Electric, WMECO and CL&P that will be recovered in future periods.  Also contributing to the decrease in operating cash flows were DOE Damages proceeds received from the Yankee Companies of $4.7 million in 2015, compared to $132 million in 2014.  Partially offsetting these unfavorable cash flow impacts were a decrease of $49.2 million in Pension and PBOP Plan cash contributions in 2015, as compared to 2014, and lower federal income tax payments of approximately $324 million in 2015, as compared to 2014, primarily due to the extension of the accelerated depreciation deduction.  

In late 2015, CL&P and WMECO made payments of $244.6 million and $57.4 million, respectively, to fully satisfy their obligations with the DOE, which were classified as long-term debt on the balance sheets as of December 31, 2014, for costs associated with the disposal of spent nuclear fuel and high-level radioactive waste for all periods prior to 1983 from their previous ownership interest in the Millstone nuclear power station.  CL&P and WMECO divested their ownership interest in Millstone in 2001.  These payments included accumulated interest of $178 million and $41.8 million for CL&P and WMECO, respectively.  CL&P funded its payment with the issuance of debt, and WMECO liquidated its spent nuclear fuel trust to satisfy its obligation with the DOE.  

On December 18, 2015, the "Protecting Americans from Tax Hikes" Act became law, which extended the accelerated deduction of depreciation to businesses from 2015 through 2019.  This extended stimulus provides us with cash flow benefits in 2016 of approximately $275 million (including approximately $105 million for CL&P) due to a refund of taxes paid in 2015 and lower expected tax payments in 2016 of approximately $300 million.

In 2015, we paid cash dividends of $529.8 million, or $1.67 per common share, compared with $475.2 million, or $1.57 per share in 2014.  Our quarterly common share dividend payment was $0.4175 per share, in 2015, as compared to $0.3925 per share, in 2014.  On February 3, 2016, our Board of Trustees approved a common share dividend payment of $0.445 per share, payable on March 31, 2016 to shareholders of record as of March 2, 2016.  The 2016 dividend represented an increase of 6.6 percent over the dividend paid in December 2015, and is equivalent to dividends on common shares of approximately $565 million on an annual basis.  

In 2015, CL&P, NSTAR Electric, PSNH, and WMECO paid $196 million, $198 million, $106 million, and $37.2 million, respectively, in common stock dividends to Eversource parent.  

Investments in Property, Plant and Equipment on the 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 the capitalized portions of pension expense.  In 2015, investments for Eversource, CL&P, NSTAR Electric, PSNH, and WMECO were $1.7 billion, $523.8 million, $469.5 million, $308 million, and $134.6 million, respectively.  

Each of Eversource, 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 Eversource's construction expenditures utilizes a significant amount of cash for projects that have a long-term return on investment and recovery period.  In addition, Eversource's Regulated companies recover their 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 and debt used to finance the investments.  These factors have resulted in current liabilities exceeding current assets by approximately $371 million and $82 million at Eversource and WMECO, respectively, as of December 31, 2015.

As of December 31, 2015, a total of $200 million of Eversource’s long-term debt classified as current liabilities, all at NSTAR Electric, will be paid in the next 12 months.  The remaining $28.9 million of Eversource's long-term debt classified as current liabilities relates to fair value adjustments from the merger that will be amortized in the next 12 months and have no cash flow impact.  Eversource, 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.  Eversource, CL&P, NSTAR Electric, PSNH and WMECO will reduce their short-term borrowings with operating cash flows or with the issuance of new long-term debt, determined by considering capital requirements and maintenance of Eversource's credit rating and profile.  We expect the future operating cash flows of Eversource, 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.

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Credit Ratings:  On April 23, 2015, S&P upgraded the corporate credit ratings by one level and changed the outlooks to stable from positive of Eversource parent, CL&P, NSTAR Electric, PSNH, WMECO, Yankee Gas and NSTAR Gas.  On May 19, 2015, Moody's changed the outlooks of PSNH and WMECO to positive from stable and affirmed their corporate credit ratings.  On June 2, 2015, Fitch changed the outlooks to positive from stable of CL&P, PSNH and WMECO and affirmed its corporate credit ratings of Eversource parent, CL&P, NSTAR Electric, PSNH, WMECO and NSTAR Gas.  

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

Eversource Parent

Baa1

Stable

A

Stable

BBB+

Stable

CL&P

Baa1

Stable

A

Stable

BBB+

Positive

NSTAR Electric

A2

Stable

A

Stable

A

Stable

PSNH

Baa1

Positive

A

Stable

BBB+

Positive

WMECO

A3

Positive

A

Stable

BBB+

Positive

A summary of the current credit ratings and outlooks by Moody's, S&P and Fitch for senior unsecured debt of Eversource 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

Eversource Parent

Baa1

Stable

A-

Stable

BBB+

Stable

CL&P

A2

Stable

A+

Stable

A

Positive

NSTAR Electric

A2

Stable

A

Stable

A+

Stable

PSNH

A2

Positive

A+

Stable

A

Positive

WMECO

A3

Positive

A

Stable

A-

Positive

Business Development and Capital Expenditures

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 $1.9 billion in 2015, $1.7 billion in 2014, and $1.6 billion in 2013.  These amounts included $102 million in 2015, $58.3 million in 2014, and $44.7 million in 2013 related to information technology and facilities upgrades and enhancements, primarily at Eversource Service and The Rocky River Realty Company.

Natural Gas Transmission Business:  

Access Northeast:  Access Northeast is a natural gas pipeline and storage project (the "Project") being developed jointly by Eversource, Spectra Energy Corp and National Grid.  Access Northeast will enhance the Algonquin and Maritimes & Northeast pipeline systems using existing routes and will include two new LNG storage tanks and liquefaction and vaporization facilities in Acushnet, Massachusetts that will be connected to the Algonquin gas pipeline.  The Project is expected to be capable of delivering approximately 900 million cubic feet of additional natural gas per day to New England on peak demand days.  Eversource and Spectra Energy Corp each own a 40 percent interest in the Project, with the remaining 20 percent interest owned by National Grid.  The total projected cost for both the pipeline and the LNG storage is expected to be approximately $3 billion with anticipated in-service dates commencing in November 2018.  The Project is subject to FERC and other federal and state regulatory approvals.  On November 17, 2015, the FERC accepted the Project’s request to initiate the pre-filing review process.  Upon completion of the pre-filing review, a certificate application will be filed with the FERC.  In late 2015, the Project bid into the New England Natural Gas Pipeline Capacity RFP conducted by certain EDCs in Massachusetts and Rhode Island, including NSTAR Electric and WMECO in Massachusetts, and in December 2015 and January 2016, those Massachusetts EDCs filed with the DPU seeking approval of the contracts for pipeline and storage capacity with the Project.  We expect the Rhode Island EDC to file its selected contracts with the Rhode Island regulatory agencies in the first half of 2016.  In February 2016, PSNH filed for approval with the NHPUC, its proposed contract for natural gas pipeline capacity and storage with the Project.  For further information on the RFP process, see "Regulatory Developments and Rate Matters – General – New England Natural Gas Pipeline Capacity" in this Management's Discussion and Analysis of Financial Conditions and Results of Operations.  

Electric Transmission Business:  Our consolidated electric transmission business capital expenditures increased by $106 million in 2015, as compared to 2014.  A summary of electric transmission capital expenditures by company is as follows:  

		For the Years Ended December 31,
(Millions of Dollars)		2015			2014			2013
CL&P		$	252.9		$	259.2		$	211.9
NSTAR Electric			238.2			223.8			220.8
PSNH			161.2			120.8			99.7
WMECO			116.0			68.5			87.2
NPT			38.3			28.3			39.9
Total Electric Transmission Segment		$	806.6		$	700.6		$	659.5

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NEEWS:  The Interstate Reliability Project (IRP), the second project within the NEEWS family of projects, was fully energized on December 18, 2015.  The project involved CL&P's construction of an approximately 40-mile, 345-kV overhead line from Lebanon, Connecticut to the Connecticut-Rhode Island border where it connects to transmission enhancements constructed by National Grid in Rhode Island.  IRP was placed in service in December 2015 at a final cost to CL&P of $192.6 million.  Through December 31, 2015, CL&P and WMECO capitalized $377.9 million and $570.6 million, respectively, in costs associated with NEEWS.  

GHCC:  The Greater Hartford Central Connecticut (GHCC) solutions are comprised of 27 projects and are expected to cost approximately $350 million and be placed in service from 2016 through 2018.  ISO-NE posted the final Solutions Study for GHCC in late February 2015 and approved our Proposed Plan Applications on April 16, 2015.  Through December 31, 2015, we have filed siting applications for five projects all of which have been approved by the Connecticut Siting Council.  During 2016, fifteen projects are expected to be in active construction, and three additional siting applications are expected to be filed.  All GHCC projects are expected to be completed by late 2018.  As of December 31, 2015, CL&P had capitalized $50.6 million in costs associated with GHCC.  

Northern Pass:  Northern Pass is Eversource'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.  On July 21, 2015, the DOE issued the draft Environmental Impact Statement (EIS) for Northern Pass representing a key milestone in the permitting process.  On August 18, 2015, a revised route was announced with an additional 52 miles of the route underground in and around the White Mountain National Forest region.  As a result, the NPT project cost estimate increased from $1.4 billion to $1.6 billion.  Concurrently, NPT announced the Forward NH Plan, which is a commitment to allocate $200 million to projects associated with economic development, community betterment, and clean energy innovations to benefit the state of New Hampshire.  This commitment is contingent upon the Northern Pass transmission line going into commercial operation.  

On October 19, 2015, NPT filed its NH SEC application, which was accepted as complete by the NH SEC on December 18, 2015, allowing the formal siting process to move forward.  In response to requests by the New Hampshire congressional delegation, the DOE announced that it would issue a supplement to the draft EIS.  Public hearings on the draft EIS will be held in March 2016.  The DOE has asked for comments by April 4, 2016.  The project is expected to be operational in the first half of 2019.  On January 28, 2016, NPT bid into the three-state Clean Energy RFP process.  For further information on the RFP process, see "Regulatory Developments and Rate Matters – General – Clean Energy RFP" in this Management's Discussion and Analysis of Financial Conditions and Results of Operations.    

Clean Energy Connect:  The Clean Energy Connect project is a planned transmission, wind and hydro generation project that we plan to co-develop with experienced renewable generation companies.  On January 28, 2016, the Clean Energy Connect project was bid into the three-state Clean Energy RFP process.  Our investment, should the Clean Energy Connect Project be selected in the RFP process, is currently estimated to be at least $400 million, and would involve the construction of a new 25-mile, 345kV transmission line with a 600 MW capacity from western Massachusetts to eastern New York.

Greater Boston Reliability Solutions:  In February 2015, ISO-NE selected Eversource's and National Grid's proposed Greater Boston and New Hampshire Solution (Solution) to satisfy the requirements identified in the Greater Boston study.  The Solution consists of a portfolio of electric transmission upgrades straddling southern New Hampshire and northern Massachusetts in the Merrimack Valley and continuing into the greater Boston metropolitan area.  We are pursuing the necessary regulatory approvals and have filed several siting applications in Massachusetts and New Hampshire.  We estimate our portion of the investment in the Solution will be $544 million.

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Distribution Business:  A summary of distribution capital expenditures by company is as follows:

	For the Years Ended December 31,
(Millions of Dollars)	2015			2014			2013
CL&P:
Basic Business	$	141.1		$	120.2		$	60.9
Aging Infrastructure		151.0			118.0			160.7
Load Growth		42.2			66.3			76.9
Total CL&P		334.3			304.5			298.5
NSTAR Electric:
Basic Business		108.7			99.0			98.5
Aging Infrastructure		103.1			104.2			110.6
Load Growth		51.9			43.1			53.6
Total NSTAR Electric		263.7			246.3			262.7
PSNH:
Basic Business		59.2			62.1			22.7
Aging Infrastructure		57.3			45.3			50.5
Load Growth		25.5			27.1			29.3
Total PSNH		142.0			134.5			102.5
WMECO:
Basic Business		18.2			19.0			7.9
Aging Infrastructure		18.5			16.1			24.6
Load Growth		6.6			6.1			9.2
Total WMECO		43.3			41.2			41.7
Total - Electric Distribution (excluding Generation)		783.3			726.5			705.4
Other Distribution		-			-			0.7
PSNH Generation		33.3			13.1			9.7
WMECO Generation		-			7.6			4.5
Natural Gas		212.6			193.7			175.2
Total Electric and Natural Gas Distribution Segment	$	1,029.2		$	940.9		$	895.5

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, plant 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.  

Natural Gas Distribution Business Expansion and Enhancement:  In 2013, in accordance with Connecticut law and regulations, PURA approved a comprehensive joint natural gas infrastructure expansion plan (expansion plan) filed 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 a 10-year period.  Yankee Gas estimated that its portion of the plan would cost approximately $700 million over 10 years.  In January 2015, the PURA approved a joint settlement agreement proposed by Yankee Gas and other Connecticut natural gas distribution companies and regulatory agencies that clarified the procedures and oversight criteria applicable to the expansion plan.  On March 20, 2015, Yankee Gas filed its initial System Expansion (SE) Rate reconciliation for 2014.  The proposed SE rate was approved by the PURA for implementation as of April 1, 2015, pending final PURA approval following a contested hearing.     

In October 2014, pursuant to new legislation, NSTAR Gas filed the Gas System Enhancement Program (GSEP) with the DPU.  NSTAR Gas' program accelerates the replacement of certain natural gas distribution facilities in the system to within 25 years.  The GSEP includes a new tariff effective January 1, 2016 that provides NSTAR Gas an opportunity to collect the costs for the program on an annual basis through a newly designed reconciling factor.  On April 30, 2015, the DPU approved the GSEP.  We expect capital expenditures of approximately $255 million for the period 2016 through 2019 for the GSEP.  

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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 2016 through 2019, including information technology and facilities upgrades and enhancements on behalf of the Regulated companies, is as follows:

	Years
(Millions of Dollars)	2016			2017			2018			2019			2016-2019 Total
CL&P Transmission	$	351		$	250		$	215		$	157		$	973
NSTAR Electric Transmission		302			216			238			149			905
PSNH Transmission		112			65			38			56			271
WMECO Transmission		115			78			22			40			255
NPT		31			684			636			149			1,500
Total Electric Transmission	$	911		$	1,293		$	1,149		$	551		$	3,904
Electric Distribution	$	892		$	963		$	888		$	840		$	3,583
Generation		20			-			-			-			20
Natural Gas		284			318			339			357			1,298
Total Distribution	$	1,196		$	1,281		$	1,227		$	1,197		$	4,901
Information Technology and All Other	$	105		$	88		$	82		$	87		$	362
Total	$	2,212		$	2,662		$	2,458		$	1,835		$	9,167

The projections do not include capital investments related to Access Northeast or Clean Energy Connect.  Actual capital expenditures could vary from the projected amounts for the companies and years above.

FERC Regulatory Issues

FERC ROE Complaints:  Three separate complaints have been filed at FERC by combinations of New England state attorneys general, state regulatory commissions, consumer advocates, consumer groups, municipal parties and other parties (the "Complainants").  In these three separate complaints, the Complainants challenged the NETOs' base ROE of 11.14 percent that had been utilized since 2006 and sought an order to reduce it prospectively from the date of the final FERC order and for the 15-month complaint refund periods stipulated in the separate complaints.  In 2014, the FERC ordered a 10.57 percent base ROE for the first complaint refund period and prospectively from October 16, 2014, and that a utility's total or maximum ROE shall not exceed the top of the new zone of reasonableness, which was set at 11.74 percent.  The NETOs and the Complainants sought rehearing from FERC.  In late 2014, the NETOs made a compliance filing and the Company began issuing refunds to customers from the first complaint period.  

As a result of the actions taken by the FERC and other developments in the first complaint matter, the Company recorded reserves at its electric subsidiaries in 2015, 2014 and 2013. In 2015, Eversource recognized an after-tax charge to earnings (excluding interest) of $12.4 million, of which $7.9 million was recorded at CL&P, $1.4 million at NSTAR Electric, $0.6 million at PSNH, and $2.5 million at WMECO.  The net aggregate after-tax charge to earnings (excluding interest) in 2014 totaled $22.4 million, of which $12.4 million was recorded at CL&P, $4.9 million at NSTAR Electric, $1.7 million at PSNH and $3.4 million at WMECO.  The aggregate after-tax charge to earnings (excluding interest) in 2013 totaled $14.3 million, of which $7.7 million was recorded at CL&P, $3.4 million at NSTAR Electric, $1.4 million at PSNH and $1.8 million at WMECO.  The NETOs and Complainants have filed appeals to the D.C. Circuit Court of Appeals.  A court decision is expected in late 2016.  

For the second and third complaints, the state parties, municipal utilities and FERC trial staff each believe that the base ROE should be reduced to an amount lower than 10.57 percent.  The NETOs believe that the Complainants' positions are without merit, and the existing base ROE of 10.57 percent is just and reasonable and should be maintained.  The FERC ALJ’s initial recommendation is expected by March 31, 2016.  A final FERC order is expected in late 2016 or early 2017.

As of December 31, 2015, CL&P, NSTAR Electric, PSNH, and WMECO had approximately $2.7 billion of aggregate shareholder equity invested in their transmission facilities.  As a result, each 10 basis point change in the authorized base ROE would change annual consolidated earnings by an approximate $2.7 million.  Although we are uncertain on the final outcome of the second and third complaints regarding the ROE, we believe the current reserves established are appropriate to reflect probable and reasonably estimable refunds.

FERC Order No. 1000:  On August 15, 2014, the D.C. Circuit Court of Appeals upheld the FERC's authority to order major changes to transmission planning and cost allocation in FERC Order No. 1000 and Order No. 1000-A, including transmission planning for public policy needs, and the requirement that utilities remove from their transmission tariffs their rights of first refusal to build transmission.  On March 19, 2015, the FERC acted on all rehearing requests filed by the NETOs, including CL&P, NSTAR Electric, PSNH and WMECO, and other parties and accepted the November 2013 compliance filing made by ISO-NE and the NETOs, subject to further compliance.  The FERC accepted our proposal that the new competitive transmission planning process will not apply to certain projects, which have been declared as the preferred solution by ISO-NE, unless ISO-NE later decides a solution must be re-evaluated.  The FERC determined on rehearing that we can restore provisions that recognize the NETOs’ rights to retain use and control of their existing rights of ways.  Final compliance was filed by the NETOs in November 2015 and was accepted by the FERC on December 14, 2015.

Additionally, the FERC affirmed that it can eliminate our right of first refusal to build transmission in New England even though the FERC previously approved and granted special protections to these rights.  The NETOs filed an appeal to the D.C. Circuit Court of Appeals, challenging this FERC ruling.  State regulators also filed an appeal, challenging FERC’s determination that ISO-NE should select public policy transmission projects after a competitive process.  The Court is expected to resolve the appeals in 2016.  

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Regulatory Developments and Rate Matters

General:

Clean Energy RFP:  In February 2015, pursuant to clean energy goals established in three New England states (Connecticut, Massachusetts and Rhode Island), CL&P, NSTAR Electric, WMECO, other EDCs, and state agencies in the three states jointly developed and issued a draft request for proposal (RFP) for clean energy resources (including Class I renewable generation and large hydroelectric generation).  The draft RFP solicits offers for clean energy and the transmission to deliver that energy to the three states.  The procurement will allow the states to identify large-scale projects that may offer the potential to meet their clean energy goals in a cost-effective manner when entered into jointly, while complying with the clean energy statutes within the three states.  

The DPU and the Rhode Island Public Utilities Commission (PUC) approved the draft RFP that was jointly submitted by certain EDCs.  The draft RFP encompassed the timetable and method for the solicitation and execution of any associated long-term contracts.  On August 31, 2015, the DEEP issued a notice of proceeding on the Connecticut portion of the draft RFP and accepted public comment through September 30, 2015.  On November 12, 2015, the DEEP and the Massachusetts and Rhode Island EDCs issued the RFP to a wide range of potentially interested bidders.  In late January 2016, bidders submitted project proposals, among which were the Northern Pass and Clean Energy Connect projects, selection of which will take place between April and July 2016.  The expected timeframe within which EDCs will execute contracts and submit them for regulatory commission approval from the respective state regulators is from June through October 2016 with approval expected in late 2016.  

New England Natural Gas Pipeline Capacity:  In 2014, the six New England states began to explore ways to address and mitigate winter natural gas price volatility and the associated impact on electric power supply costs attributable to winter pipeline capacity constraints.  Five states are currently pursuing natural gas capacity expansion efforts.  In 2014, Rhode Island approved legislation authorizing the Rhode Island Division of Public Utilities and Carriers and the Office of Energy Resources to participate in the RFP process and file proposals with the PUC.  In late 2015, Access Northeast bid on the natural gas pipeline and storage RFP issued by the Rhode Island EDC.  We expect the EDC will file their selected contracts with the PUC in the first half of 2016.  The Massachusetts DPU determined that it has the authority to allow EDCs to contract for natural gas pipeline capacity and in late 2015, certain Massachusetts EDCs, including NSTAR Electric and WMECO, issued a natural gas pipeline capacity RFP.  In December 2015 and January 2016, those Massachusetts EDCs filed with the DPU seeking approval of the contracts for pipeline and storage capacity, including Access Northeast.  On January 19, 2016, the NHPUC issued an order accepting a staff report that concluded that the NHPUC could approve contracts between pipelines and EDCs if they were shown to reduce electricity costs and be in the public interest.  In February 2016, PSNH filed for approval with the NHPUC, its proposed contract for natural gas pipeline capacity and storage with Access Northeast.  The Connecticut DEEP expects to provide an opportunity for public comment on a natural gas pipeline capacity RFP in the first quarter of 2016.  

Electric and Natural Gas Base Distribution Rates:  

Each Eversource 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.  The Regulated companies' distribution rates are set by their respective state regulatory commissions, and their tariffs include mechanisms for periodically adjusting their rates for the recovery of specific incurred costs.  

In Connecticut, CL&P distribution rates were established in a 2014 PURA approved rate case.  Yankee Gas distribution rates were established in a 2011 PURA approved rate case.  In Massachusetts, electric utility companies are required 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 those companies are limited to one settlement agreement in any 10-year period.  NSTAR Electric and WMECO were subject to a base distribution rate freeze through December 31, 2015.  NSTAR Gas distribution rates effective January 1, 2016 were established in an October 30, 2015 DPU distribution rate order.  See Massachusetts – NSTAR Gas Distribution Rates in this Regulatory Developments and Rate Matters section for further information.  In New Hampshire, PSNH distribution rates were established in a settlement approved by the NHPUC in 2010.  Prior to the expiration of that settlement, the NHPUC approved the continuation, and increased funding via rates, of PSNH’s reliability enhancement program.  See New Hampshire - Distribution Rates in this Regulatory Developments and Rate Matters section for further information.

Electric and Natural Gas Retail Rates:

The Eversource EDCs obtain and resell power to retail customers who choose not to buy energy from a competitive energy supplier.  The natural gas distribution companies procure natural gas for firm and seasonal customers.  These energy supply procurement costs are recovered from customers in energy supply rates that are approved by the respective state regulatory commission.  The rates are reset periodically and are fully reconciled to their costs.  Each electric and natural gas distribution company fully recovers its energy supply costs through approved regulatory rate mechanisms and, therefore, such costs have no impact on earnings.

The electric and natural gas distribution companies also recover certain costs on a fully reconciling basis through regulatory commission-approved cost tracking mechanisms and, therefore, such costs have no impact on earnings.  Costs recovered through costs tracking mechanisms include energy efficiency program costs, electric transmission charges, electric federally mandated congestion charges, system resiliency costs, certain uncollectible hardship bad debt expenses, and restructuring and stranded costs resulting from deregulation.  The reconciliation filings compare the total actual costs allowed to revenue requirements related to these services and the difference between the costs incurred (or the rate recovery allowed) and the actual costs allowed is deferred and included, to be either recovered or refunded, in future customer rates.  

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Connecticut:

CL&P Distribution Rates:  In December 2014, the PURA granted a re-opener request to CL&P’s base distribution rate application for further review of the appropriate balance of ADIT utilized in the calculation of rate base.  On July 2, 2015, the PURA issued a final order that approved a settlement agreement filed on May 19, 2015 between CL&P and the PURA Prosecutorial Staff.  The order allows for an increase to rate base of approximately $163 million associated with ADIT, including a regulatory asset to recover the incremental revenue requirement for the period December 1, 2014 through November 30, 2015 over a subsequent 24-month period.  The rate base increase provided an increase to total allowed annual revenue requirements of $18.4 million beginning December 1, 2014.  As part of the settlement agreement, the $18.4 million for the period December 1, 2014 through November 30, 2015 was recorded as a regulatory asset with a corresponding increase in Operating Revenues, and is being collected from customers in rates over a 24-month period beginning December 1, 2015.

CL&P and Yankee Gas Conservation and Load Management Plan:  On December 31, 2015, DEEP approved the three-year electric and natural gas C&LM plan filed by CL&P and Yankee Gas, which was jointly developed with the Connecticut EDCs and natural gas distribution companies.  The C&LM plan, which covers the years 2016 through 2018, was built upon the continued success and momentum of the previous C&LM plans and includes performance incentives totaling $24 million over the three-year period related to proposed savings goals for CL&P and Yankee Gas.

Yankee Gas Settlement Agreement:  On April 29, 2015, the PURA approved a settlement agreement entered into among Yankee Gas, the Connecticut Office of Consumer Counsel, and the PURA Staff, which eliminated the requirement to file a base distribution rate case in 2015.  Under the terms of the settlement agreement, Yankee Gas provided a $1.5 million rate credit to firm customers beginning in December 2015 and continued through February 2016, and established an earnings sharing mechanism whereby Yankee Gas and its customers will share equally in any earnings exceeding a 9.5 percent ROE in a twelve month period commencing with the period from April 1, 2015 through March 31, 2016.  Additionally, Yankee Gas shall forgo its right to file a rate case for an increase in its base distribution rates prior to January 1, 2017.  This does not impact the rates charged under the Connecticut comprehensive energy strategy (CES) program.  The settlement agreement also resolved two pending regulatory proceedings before the PURA pertaining to a review of Yankee Gas’ overearnings.  In 2015, Yankee Gas recorded the $1.5 million expected refund to customers as a reduction to operating revenues.  

Massachusetts:

NSTAR Electric and NSTAR Gas Comprehensive Settlement Agreement:  On March 2, 2015, the DPU approved the comprehensive settlement agreement between NSTAR Electric, NSTAR Gas and the Massachusetts Attorney General (the "Settlement") as filed with the DPU on December 31, 2014.  The Settlement resolved the outstanding NSTAR Electric CPSL program filings for 2006 through 2011, the NSTAR Electric and NSTAR Gas PAM and energy efficiency-related customer billing adjustments reported in 2012, and the recovery of LBR related to NSTAR Electric's energy efficiency programs for 2009 through 2011 (11 dockets in total).  In the first quarter of 2015, as a result of the DPU order, NSTAR Electric and NSTAR Gas commenced refunding a combined $44.7 million to customers, which was recorded as a regulatory liability.  Refunds to customers will continue through December 2016.  As a result of the Settlement, NSTAR Electric increased its operating revenues and decreased its amortization expense in 2015, resulting in the recognition of a $13 million after-tax benefit.

NSTAR Electric Basic Service Bad Debt Adder:  On January 7, 2015, the DPU issued an order concluding that NSTAR Electric had removed energy-related bad debt costs from base distribution rates effective January 1, 2006.  As a result of the DPU order, in the first quarter of 2015, NSTAR Electric increased its regulatory assets and reduced its operations and maintenance expense by an under recovered amount of $24.2 million for energy-related bad debt costs through 2014, resulting in after-tax earnings of $14.5 million.  NSTAR Electric filed for recovery of the energy-related bad debt costs regulatory asset from customers and on November 20, 2015, the DPU approved NSTAR Electric’s proposed rate increase to recover these costs over a 12-month period, beginning January 1, 2016.

NSTAR Electric and WMECO Grid Modernization Plan:  As part of the DPU’s investigation into the modernization of the electric grid, in August 2015, NSTAR Electric and WMECO filed a comprehensive ten-year plan with the DPU.  The plan focuses on technologies and investments that modernize the grid with proposed investments in equipment that reduces the frequency and duration of power outages, optimizes and manages electrical demand, integrates distributed energy resources, and improves workforce and asset management.  The plan includes incremental spending of approximately $430 million over the first five years, which would be recovered from customers in rates, and is pending DPU review and approval.  There is currently no timeline for the DPU to take any action on this plan.  

NSTAR Electric, WMECO and NSTAR Gas Energy Efficiency Plan:  The Massachusetts EDCs and natural gas distribution companies have increased their energy efficiency savings achievements significantly since the enactment of the Green Communities Act in 2008, with electric savings almost tripling between 2008 and 2014.  On January 28, 2016, the DPU issued an order approving NSTAR Electric’s, WMECO’s, and NSTAR Gas’ three-year electric and natural gas energy efficiency plan, which was jointly developed with other Massachusetts EDCs and natural gas distribution companies.  As part of this plan, which covers the years 2016 through 2018, NSTAR Electric, WMECO, and NSTAR Gas will maintain aggressive savings goals.  The plan includes the ability to earn performance incentives related to these aggressive savings goals totaling $58 million over the three-year period for NSTAR Electric, WMECO and NSTAR Gas, as well as recovery of LBR of approximately $50 million on an annual basis for NSTAR Electric until it is operating under a decoupled rate structure.  

NSTAR Electric DPU Safety and Reliability Programs:  The safety and reliability programs allowed NSTAR Electric to recover $15 million per year, through December 31, 2015, related to DPU approved safety and reliability programs, which are designed to mitigate stray voltage and repair and replace portions of the system to increase and enhance customer safety.    

NSTAR Gas Distribution Rates:  On October 30, 2015, the DPU issued its order in the NSTAR Gas distribution rate case, which approved an annualized base rate increase of $15.8 million, plus other increases of approximately $11.5 million, mostly relating to recovery of pension and PBOP expenses and the Hopkinton Gas Service Agreement (GSA), effective January 1, 2016.  In the order, the DPU also approved an authorized regulatory

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ROE of 9.8 percent, the establishment of a revenue decoupling mechanism, the recovery of certain bad debt expenses, and a 52.1 percent equity component of its capital structure.  On November 19, 2015, NSTAR Gas filed a motion for reconsideration of the order with the DPU seeking the correction of mathematical errors and other plant and cost of service items.

As a result of this order, Eversource recorded regulatory deferrals for costs that have been approved for recovery or are expected to be approved for recovery in future rate proceedings, which resulted in the recognition of a $10.3 million after-tax benefit in 2015.  Included in this amount is a $6.3 million after-tax benefit recorded at NSTAR Electric for certain uncollectible hardship accounts receivable that are expected to be recovered in future rates given the allowed recoveries of uncollectible hardship accounts receivable by WMECO and NSTAR Gas.

NSTAR Gas - Gas Service Agreement:  On April 29, 2015, the DPU approved the GSA, subject to DPU modifications, between NSTAR Gas and Hopkinton LNG Corp. (HOPCO), an indirect, wholly-owned subsidiary of Eversource.  On October 30, 2015, the DPU issued its order in the NSTAR Gas distribution rate case that required minor changes to the GSA.  On May 22, 2015 and November 17, 2015, we filed revised GSAs with the DPU reflecting these modifications.  The GSA effectively replaces the former gas services agreement in place between NSTAR Gas and HOPCO, maintains NSTAR Gas Company's entitlement to 100 percent of the current capacity of the HOPCO facilities, and provides for the recovery of costs associated with planned capital expenditures at the HOPCO facilities.  We currently estimate the HOPCO facilities’ capital expenditures to be approximately $200 million, most of which will be invested and placed into service in the first five years of the GSA.  The GSA has a 30-year term commencing on January 1, 2016.  

New Hampshire:

Distribution Rates:  PSNH distribution rates were established in a settlement approved by the NHPUC in 2010.  Rates established therein will continue until changed by the NHPUC in a subsequent distribution rate proceeding.  In June 2015, PSNH sought and obtained approval for a distribution rate increase to fund continuation of the reliability enhancement program beyond the end of the PSNH's 2010 distribution rate settlement.  

Generation Divestiture:  

On June 10, 2015, Eversource and PSNH entered into the 2015 Public Service Company of New Hampshire Restructuring and Rate Stabilization Agreement (the Agreement) with the New Hampshire Office of Energy and Planning, certain members of the NHPUC staff, the Office of Consumer Advocate, two State Senators, and several other parties.  The Agreement was filed with the NHPUC on the same day.  Under the terms of the Agreement, PSNH has agreed to divest its generation assets upon NHPUC approval.  The Agreement is designed to provide a resolution of issues pertaining to PSNH's generation assets in pending regulatory proceedings before the NHPUC.  The Agreement provided for the Clean Air Project prudence proceeding to be resolved and all remaining Clean Air Project costs to be included in rates effective January 1, 2016.  As part of the Agreement, PSNH has agreed to forego recovery of $25 million of the deferred equity return related to the Clean Air Project.  In addition, PSNH will not seek a general distribution rate increase effective before July 1, 2017 and will contribute $5 million to create a clean energy fund, which will not be recoverable from its customers.  In 2015, PSNH recorded the $5 million contribution as a long-term liability and an increase to Operations and Maintenance expense on the statements of income.

Upon completion of the divestiture process, all remaining stranded costs will be recovered via bonds that will be secured by a non-bypassable charge or through other recoveries in rates billed to PSNH's customers.  For further information on the securitization legislation that was signed into law on July 9, 2015, see "Legislative and Policy Matters – New Hampshire" in this Management's Discussion and Analysis of Financial Conditions and Results of Operations.

On January 26, 2016, Advisory Staff of the NHPUC and the parties to the Agreement filed a stipulation with the NHPUC agreeing that near-term divestiture of PSNH’s generation was in the public interest and that the Agreement should be approved.  Implementation of the Agreement is subject to NHPUC approval, which is expected in early 2016.  

We believe that full recovery of PSNH's generation assets is probable through a combination of cash flows during the remaining operating period, sales proceeds upon divestiture, and recovery of stranded costs in future rates.

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, pursuant to state law, was placed in service in September 2011.  In April 2012, the NHPUC issued an order authorizing temporary rates to recover a significant portion of the Clean Air Project costs.  

Pursuant to the Agreement, on December 22, 2015, the NHPUC approved PSNH’s request to increase its default energy service rate for full recovery of costs (including a return) related to the Clean Air Project, as well as a deferred equity return, effective January 1, 2016.  The approved energy supply portion of the 2016 rate is 9.99 cents per kWh (including all Clean Energy Project-related costs), and the SCRC rate for 2016 is a credit to customers of 0.017 cents per kWh.

Legislative and Policy Matters

Federal:  On December 18, 2015, the "Protecting Americans from Tax Hikes" Act became law, which extended the accelerated deduction of depreciation to businesses from 2015 through 2019.  This extended stimulus provides us with cash flow benefits of approximately $275 million (including approximately $105 million for CL&P) due to a refund of taxes paid in 2015 and lower expected tax payments in 2016 of approximately $300 million.  

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New Hampshire:  On July 9, 2015, the Governor of New Hampshire signed "An Act Relative to Electric Rate Reduction Financing" (the Act) permitting the NHPUC to issue finance orders that authorize the issuance of rate reduction bonds in accordance with the PSNH divestiture agreement and the expected NHPUC divestiture order, regarding cost recovery of the Clean Air project and divestiture of PSNH’s remaining generation plants.  

Connecticut:  In 2015, the state of Connecticut enacted several changes to its corporate tax laws.  Among the changes, commencing as of January 1, 2015, is the reduction in the amount of tax credits that corporations can utilize against its tax liability in a year and a continuation of the corporate income tax surcharge through 2018, which effectively increases the state corporate tax rate to 9 percent for the years 2016 and 2017 and 8.25 percent for 2018.  Also, effective January 1, 2016, all Connecticut companies have a mandatory unitary tax filing requirement.  We continue to review the tax law changes and their impact on the effective tax rates of Eversource and CL&P.  

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 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:  Our Regulated companies are subject to rate-regulation that is based on cost recovery and meets the criteria for application of accounting guidance for rate-regulated operations, which considers the effect of regulation on the timing of the recognition of certain revenues and expenses.  The Regulated companies' financial statements 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 each of the Regulated companies will recover the regulatory assets that have been recorded.  If we determine that we can no longer apply the accounting guidance applicable to rate-regulated enterprises to our operations, or that we cannot conclude it is probable that costs will be recovered from customers in future rates, the costs would be charged to earnings in the period in which the determination is made.

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 our 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 or when there is a change in our estimates.  

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 factors such as energy demand, weather and changes in the composition of customer classes that can significantly impact the amount of revenues recorded at NSTAR Electric and PSNH because they do not have a revenue decoupling mechanism.  CL&P and WMECO record a regulatory deferral to reflect the actual allowed amount of revenue for decoupling, and unbilled revenues estimation is not critical to CL&P and WMECO.

Pension and PBOP:  We sponsor Pension and PBOP Plans to provide retirement benefits to our employees.  Effective January 1, 2015, the two Pension Plans were merged into one Pension Plan, sponsored by Eversource Service, and our PBOP Plans were merged into one PBOP Plan, sponsored by Eversource Service.  For each of these plans, several significant assumptions are used to determine the projected benefit obligation, funded status and net periodic benefit cost.  These assumptions include the expected long-term rate of return on plan assets, discount rate, compensation/progression rate, mortality assumptions, and health care cost trend rates.  We evaluate these assumptions at least annually and adjust them as necessary.  Changes in these assumptions could have a material impact on our financial position, results of operations or cash flows.  

Pre-tax net periodic benefit expense for the Pension Plan (excluding the SERP Plans) was $124.2 million, $118.4 million and $236.3 million for the years ended December 31, 2015, 2014 and 2013, respectively.  The pre-tax net periodic benefit expense for the PBOP Plan was $2.4 million, $8.1 million and $32.6 million for the years ended December 31, 2015, 2014 and 2013, respectively.  

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Expected Long-Term Rate of Return on Plan Assets:  In developing this assumption, we consider historical and expected returns as well as 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, 2015, 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 2016 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.

Discount Rate:  Payment obligations related to the Pension and PBOP Plans are discounted at interest rates applicable to the expected timing of each plan's cash flows.  The discount rate that was utilized in determining the 2015 pension and PBOP obligations was based on a yield-curve approach.  This approach utilizes 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.  As of December 31, 2015, the discount rates used to determine the funded status were 4.6 percent for the Pension Plan and 4.62 percent for the PBOP Plan.  As of December 31, 2014, the discount rates used were 4.2 percent for the Pension Plans and 4.22 percent for the PBOP Plans.  The increase in the discount rate used to calculate the funded status resulted in a decrease on the Pension and PBOP Plan's liability of approximately $267 million and $60 million, respectively, as of December 31, 2015.  

Compensation/Progression Rate:  This assumption reflects the expected long-term salary growth rate, including consideration of the levels of increases built into collective bargaining agreements, and impacts the estimated benefits that Pension Plan participants receive in the future.  As of both December 31, 2015 and 2014, the compensation/progression rate used to determine the funded status was 3.5 percent.  

Mortality Assumptions:  Assumptions as to mortality of the participants in our Pension and PBOP Plans are a key estimate in measuring the expected payments a participant may receive over their lifetime and the corresponding plan liability we need to record.  During 2014, the Society of Actuaries released a series of updated mortality tables resulting from studies that measured mortality rates for various groups of individuals.  The updated mortality tables released in 2014 increased the life expectancy of plan participants by three to five years and had the effect of increasing the estimated benefits to be provided to plan participants.  The impact of adopting the updated mortality tables on Eversource's liability as of December 31, 2014 was an increase of approximately $340 million and $82 million for the Pension and PBOP Plans, respectively.  In 2015, a revised scale for the mortality table was released having the effect of decreasing the estimate of benefits to be provided to plan participants.  The impact of the adoption of the new mortality scale resulted in a decrease of $48 million and $23 million for the Pension and PBOP Plans' liability, respectively, as of December 31, 2015.

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, and amortization of actuarial gains and losses, offset by the expected return on plan assets.  Actuarial gains and losses represent differences between assumptions and actual information or updated assumptions.

The expected return on plan assets is determined by applying the assumed long-term rate of return to the Pension and PBOP Plan asset balances.  This calculated expected return is compared to the actual return or loss on plan assets at the end of each year to determine the investment gains or losses to be immediately reflected in unrecognized actuarial gains and losses.  

Forecasted Expenses and Expected Contributions:  We estimate that the expense for the Pension Plan (excluding the SERP Plans) will be approximately $65 million and income for the PBOP Plan will be approximately $7.7 million, respectively, in 2016.  Effective January 1, 2016, we elected to transition the discount rate to the spot rate methodology from the yield-curve approach for the service and interest cost components of Pension and PBOP expense because it provides a more precise measurement by matching projected cash flows to the corresponding spot rates on the yield curve.  Historically, these components were estimated using the same weighted-average discount rate as for the funded status.  The discount rates used to estimate the 2016 service costs are 4.91 percent and 5.14 percent for the Pension and PBOP Plans, respectively.  The discount rates used to estimate the 2016 interest costs are 3.80 percent and 3.72 percent for the Pension and PBOP Plans, respectively.  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.  

Our policy is to annually fund the Pension Plan in an amount at least equal to the amount that will satisfy all federal funding requirements.  We contributed $154.6 million to the Pension Plan in 2015.  We currently estimate approximately $146 million of contributions to the Pension Plan in 2016.  

For the PBOP Plan, it is our policy to annually fund the PBOP Plan though tax deductible contributions to external trusts.  We contributed $7.9 million to the PBOP Plan in 2015.  We currently estimate approximately $9.5 million in contributions to the PBOP Plan in 2016.

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

(Millions of Dollars)		Increase in Pension Plan Cost						Increase in PBOP Plan Cost
Assumption Change		As of December 31,
Eversource			2015			2014		2015			2014
Lower expected long-term rate of return		$	20.6		$	19.3		$	4.2		$	4.0

Lower discount rate		$	26.3		$	19.1		$	6.2		$	2.2

Higher compensation rate		$	12.4		$	10.2			N/A			N/A

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Health Care Cost:  As of December 31, 2015, the health care cost trend rate assumption used to determine the PBOP Plan's year end funded status was 6.25 percent, subsequently decreasing to an ultimate rate of 4.5 percent in 2023. 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 $8.5 million in 2015, and a $115.3 million increase to the PBOP obligation.  

Goodwill:  We have recorded approximately $3.5 billion of goodwill associated with previous mergers and acquisitions. We have identified our 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 Distribution reporting unit includes the carrying values of NSTAR Gas and Yankee Gas.  As of December 31, 2015, 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 values 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 of goodwill as of October 1, 2015 for the Electric Distribution, Electric Transmission and Natural Gas Distribution reporting units.  This evaluation required the consideration 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. Key considerations include discount rates, utility sector market performance and merger transaction multiples, and internal estimates of future cash flows and net income.  

The 2015 goodwill impairment test resulted in a conclusion that goodwill is not impaired and no reporting unit is at risk of a goodwill impairment.  

Income Taxes:  Income tax expense is estimated for each of the jurisdictions in which we operate and is recorded each quarter using an estimated annualized effective tax rate.  This process to record income tax expense 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 that directly impact income tax expense as a result of 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.

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.  The determination of whether a tax position meets the recognition threshold under applicable accounting guidance is based on facts and circumstances available to us.  Once a tax position meets the recognition threshold, the tax benefit is measured using a cumulative probability assessment.  Assigning probabilities in measuring a recognized tax position and evaluating new information or events in subsequent periods requires significant judgment and could change previous conclusions used to measure the tax position estimate.  New information or events may include tax examinations or appeals (including information gained from those examinations), developments in case law, settlements of tax positions, changes in tax law and regulations, rulings by taxing authorities and statute of limitation expirations.  Such information or events may have a significant impact on our financial position, results of operations and cash flows.  

Accounting for Environmental Reserves:  Environmental reserves are accrued when assessments indicate 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 an adverse 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.  If a most likely action plan cannot yet be determined, we estimate the liability based on the low end of a range of possible action plans. A significant portion of our environmental sites and reserve amounts relate to former MGP sites that were operated several decades ago and manufactured gas from coal and other processes, which resulted in certain by-products remaining in the environment that may pose a potential risk to human health and the environment.  As assessments on these sites are performed, we may receive new information to be considered in our estimates related to the extent and nature of the contamination and the costs of required remediation.

Our estimates also 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.  

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 not elected or designated as "normal purchases or normal sales" (normal), to marketable securities held in trusts, to our investments in our Pension and PBOP Plans, and to nonfinancial assets such as goodwill and AROs.  This guidance was also applied in estimating the fair value of preferred stock and long-term debt.

Changes in fair value of the Regulated company derivative contracts are recorded as Regulatory Assets or Liabilities, as we recover the costs of these contracts in rates charged to customers.  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.  

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We use quoted market prices when available to determine the fair value 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 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.  

Other Matters

Accounting Standards:  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, 2015 is summarized annually through 2020 and thereafter as follows: