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

FORM 10-K

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

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

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.

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

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.

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).

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

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

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

The aggregate market value of Northeast Utilities’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 Northeast Utilities’Eversource Energy's most recently completed second fiscal quarter (June 30, 2012)2015) was $12,177,646,948based$14,345,789,335 based on a closing salesmarket price of $38.81per$45.41per share for the 313,776,010315,916,964 common shares outstanding on June 30, 2012.  

Northeast Utilities, directly or indirectly, holds all of the 6,035,205 shares, 100 shares, 301 shares, and 434,653 shares of the outstanding common stock of The Connecticut Light and Power Company, NSTAR Electric Company, Public Service Company of New Hampshire and Western Massachusetts Electric Company, respectively.2015.  

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

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

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

20122015 FORM 10-K ANNUAL REPORT

TABLE OF CONTENTS

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NORTHEAST UTILITIESEVERSOURCE ENERGY AND SUBSIDIARIES

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARY

NSTAR ELECTRIC COMPANY AND SUBSIDIARIESSUBSIDIARY

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIESSUBSIDIARY

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES

LITIGATION REFORM ACT OF 1995

References in this Annual Report on Form 10-K to "NU,"Eversource," "the Company," "we," "our," and "us" refer to Northeast UtilitiesEversource and its consolidated subsidiaries, includingsubsidiaries.  On April 30, 2015, the Company's legal name was changed from Northeast Utilities to Eversource Energy.  CL&P, NSTAR LLCElectric, PSNH and its subsidiaries for periods after April 10, 2012.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:

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

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

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

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

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changes in economic conditions, including their impact on interest rates, bad debt expense,tax policies, and customer demand for our products and services,payment ability,

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changesfluctuations in weather patterns,

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changes in laws, regulations or regulatory policy,

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changes in levels andor timing of capital expenditures,

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

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developments in legal or public policy doctrines,

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technological developments,

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changes in accounting standards and financial reporting regulations,

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actions of rating agencies, and

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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 accompanyingManagement’sManagement's Discussion and Analysis of Financial Condition and Results of OperationsandCombined Notes to Consolidated Financial Statements.  We encourage you to review these items.

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NORTHEAST UTILITIESEVERSOURCE ENERGY AND SUBSIDIARIES

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

NSTAR ELECTRIC COMPANY AND SUBSIDIARIESSUBSIDIARY

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIESSUBSIDIARY

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

PART I

Item 1.

Business

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

NU,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:

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

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

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

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

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

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

NUCL&P, NSTAR Electric, PSNH and WMECO also owns certain unregulated businessesserve New England customers through its wholly owned subsidiaries, NU Enterprises and NSTAR LLC, which are included in its Parent and other companies’ results of operations.Eversource Energy's electric transmission business.

Although NU,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, weseparately.  We also include information in this report on a segment or line-of-business, basis.  The Regulated companies' segments include thebasis for Eversource Energy.  Eversource Energy recognizes three reportable segments: electric distribution, segment, theelectric transmission and natural gas distribution segment and the electric transmission segment.  Thedistribution.  Eversource Energy's electric distribution segment includes the generation businesses of PSNH and WMECO.  The Regulated companies'These three segments represented substantially all of NU'sEversource Energy's total consolidated revenues for the years ended December 31, 20122015 and 2011.  

MERGER WITH2014.  CL&P, NSTAR

On April 10, 2012, NU completed its merger with NSTAR (Merger).  Pursuant to the terms Electric, PSNH and conditions of the Agreement and Plan of Merger, as amended, NSTAR was merged with and into a wholly owned subsidiary of NU, which was subsequently renamed NSTAR LLC.  NU’s consolidated financial statements include the results of operations of NSTAR LLC and its subsidiaries for the period after April 10, 2012.WMECO do not report separate business segments.   

ELECTRIC DISTRIBUTION SEGMENT

General

NU’sEversource 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 20122015 electric franchise retail revenues for NU’sEversource Energy's electric distribution companies, collectively, based on categories of customers, including the electric franchise retail revenues of NSTAR Electric from the date of merger, April 10, 2012, through December 31, 2012:customers:

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A summary of our distribution companies’companies' retail electric GWh sales volumes and percentage changes for 2012,2015, as compared to 2011,2014, is as follows:

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NUOur 2015 consolidated retail electric sales include the sales of NSTAR Electric from the date of merger, April 10, 2012, through December 31, 2012.

Actual retail electric sales for CL&P, NSTAR Electric and WMECO decreased in 2012,volumes were slightly higher, as compared to 2011,2014, due primarily to the warmer than normalimpact of colder winter weather experienced in the first quarter of 2012, as compared to colder than normal2015 and warmer weather in the firstthird quarter of 2011, while actual retail electric sales for PSNH were 0.1 percent higher than last year.  In 2012, heating degree days were 11 percent lower in Connecticut and western Massachusetts, 7 percentlower2015, partially offset by milder winter weather in the Boston metropolitan area, and 9 percent lowerfourth quarter of 2015 throughout our service territories as well as an increase in New Hampshire, as compared to 2011.  On a weather normalized basis (based on 30-year average temperatures), the average NU combined consolidated total retail electric sales decreased 0.2 percent in 2012, as compared to 2011, assuming NSTAR Electric had been part of the NU combined electric distribution system for all periods under consideration.  We believe these decreases were due primarily to increasedcustomer conservation efforts, among all our customer classes andincluding the continued installationimpact of distributed generation at our commercial and industrial customers’ facilities.  For WMECO, the fluctuations in retail electric sales no longer impact earnings as the DPU approved a sales decoupling plan effective February 1, 2011.  Under this decoupling plan, WMECO now has an established annual level of baseline distribution delivery service revenues of $125.4 millionthat it is able to recover.  This effectively breaks the relationship between sales volume and revenues recognized.

Major Storms

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

On October 29, 2011, an unprecedented storm inundated our service territory with heavy snow causing significant damage to our distribution and transmission systems.  Approximately 1.2 million of CL&P, PSNH and WMECO’s electric distribution customers were without power at the peak of the outages, with 810,000 of those customers in Connecticut, 237,000 in New Hampshire, and 140,000 in western Massachusetts.  In terms of customer outages, this was the most severe storm in CL&P’s history, surpassing Tropical Storm Irene; the third most severe in PSNH’s history; and the most severe in WMECO's history.  The storm also caused approximately 200,000 customer outages on the NSTAR Electric distribution system.  

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

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

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On February 8, 2013, a blizzard caused damageFluctuations 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 electric delivery systems ofrelationship between sales volumes and revenues recognized.  CL&P and NSTAR Electric.  We have estimated that approximately 71,000WMECO 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 350,000 of CL&P and NSTAR Electric's distribution customers, respectively, were without powerthe actual amount incurred during ora 12-month period is adjusted through rates in the following the storm.  We believe that this storm will cost between $100 million to $120 million, with approximately 90 percent of those costs relating to NSTAR Electric.  Management expects the costs to meet the criteria for specific cost recovery in Connecticut and Massachusetts and, as a result, does not expect the storm to have a material impact on the results of operations of CL&P or NSTAR Electric.  Each operating company will seek recovery of these anticipated deferred storm costs through its applicable regulatory recovery process.period.

ELECTRIC DISTRIBUTION – CONNECTICUT

THE CONNECTICUT LIGHT AND POWER COMPANY

CL&P’s&P's distribution business consists primarily of the purchase, delivery and sale of electricity to its residential, commercial and industrial customers.  As of December 31, 2012,2015, 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 2012&P's 2015 electric franchise retail revenues based on categories of customers:

A summary of CL&P’s&P's retail electric GWh sales volumes and percentage changes for 2012,2015, as compared to 2011,2014, is as follows:

Rates

CL&P is subject to regulation by the PURA, which, among other things, has jurisdiction over rates, accounting procedures, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, standards of service management efficiency and construction and operation of facilities.  CL&P's present general rate structure consists of various rate and service classifications covering residential, commercial and industrial services.  CL&P's retail rates include a delivery service component, which includes distribution, transmission, conservation, renewables, CTA, SBC and other charges that are assessed on all customers.  Connecticut utilities are entitled under state law to charge rates that are sufficient to allow them an opportunity to recover their reasonable operationoperating 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’customers' bills.  

CL&P continues to supply approximately 3540 percent of its customer load at SS or LRS rates while the other 6560 percent of its customer load has migrated to competitive energy suppliers.  Because this customer migration is only for energy supply service, it has no impact on CL&P’s delivery&P's electric distribution business or its operating income.

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

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GSC charge (theAn electric generation services component)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 charge is adjusted periodically and reconciled semi-annually in accordance with the directivespolicies and procedures of PURA.  Expense/revenue reconciliation amounts arethe PURA, with any differences refunded to, or recovered in subsequent rates.

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from, customers.

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FMCCA 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.

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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.  

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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 costcosts approved by the PURA to reduce FMCC charges (with conditions) and reliability must run contracts.these charges.  The FMCC chargealso recovers costs associated with CL&P's system resiliency program.  The FMCC is adjusted periodically and reconciled semi-annually in accordance with the directivespolicies and procedures of PURA.  Expense/revenue reconciliation amounts arethe PURA, with any differences refunded to, or recovered in subsequent rates.from, customers.

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SBCA 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.

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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.

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

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

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

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C&LMA conservation charge, comprised of a statutory rate established to implement cost-effective energy conservation programs and market transformation initiatives.  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.

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Transmission adjustment clause, which reconciles on a semi-annual basis the transmission revenues billed to customers against the transmission costs of acquiring such services, to recover all of its transmission expenses on a timely basis.  

As required by regulation, CL&P, jointly with UI, has entered into fourthe 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):

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Four CfDs for a total of(totaling approximately 787 MW of capacity consisting ofcapacity) with three electric generation projectsunits and one demand response project.  The capacity CfDsproject, which extend through 2026 and obligate the utilities to pay the difference between a set price and the value that the projects receive in the ISO-NE markets.  The contracts have terms of up to 15 years beginning in 20092009.  The capacity CfDs obligate both CL&P and are subjectUI to make or receive payments on a sharing agreement with UI, whereby UI will havemonthly basis to or from the project and generation owners based on the difference between a 20 percent share ofcontractually set capacity price and the costscapacity market prices that the project and benefits of these contracts.  CL&P's portion ofgeneration owners receive in the costs and benefits of these contracts will be paid by or refunded to CL&P's customers.ISO-NE capacity markets.

CL&P, jointly with UI, has entered into three·

Three CfDs (each having a 80 percent to 20 percent sharing mechanism as described above), with developers of peaking generation units approved by the PURA (Peaker CfDs).  These units have a total of(totaling approximately 500 MW of peaking capacity.capacity) with three peaking generation units.  The Peakerthree peaker CfDs pay the developergeneration owners the difference between capacity, forward reserve and energy market revenues and a cost-of-servicecost-of service payment stream for 30 years.  The ultimate cost or benefit to CL&P under these contracts will depend on theyears beginning in 2008 (including costs of plant construction and operation and the prices that the projectsgeneration owners receive for capacity and other products in the ISO-NE markets.  CL&P's portionmarkets).  

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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 amounts paid or received under the Peaker CfDs will be recoverable from or refunded to CL&P's customers.  end of 2016.

On June 30, 2010,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 inthat approved a settlement agreement filed on May 19, 2015 between CL&P’s most recent retail distribution rate case approving distribution rates&P and establishing CL&P’s authorized distribution regulatory ROE at 9.4 percent.  the PURA Prosecutorial Staff, and which included an increase to total allowed annual revenue requirements of $18.4 million beginning December 1, 2014.

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

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Sources and Availability of Electric Power Supply

As noted above, CL&P does not own any generation assets and purchases energy to serve its SS and LRS loads from a variety of competitive sources through periodic requests for proposals.  CL&P enters into supply contracts for SS periodically for periods of up to three years to mitigate the risks associated with energy price volatility for its residential and small and medium load commercial and industrial customers.  CL&P enters into supply contracts for LRS for larger commercial and industrial customers every three months.  Currently, CL&P has contracts in place with various suppliers for all of its SS loads for the first half of 2013, and 70 percent of expected load for the second half of 2013.  CL&P intends to purchase 10 percent of the SS load for the second half of 2013.  None of the SS load for 2014 has been procured.  CL&P’s contracts for its LRS loads extend through the second quarter of 2013, and CL&P intends to purchase 10 percent of the LRS load for the third quarter of 2013.

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ELECTRIC DISTRIBUTION – MASSACHUSETTS

NSTAR ELECTRIC COMPANY

WESTERN MASSACHUSETTS ELECTRIC COMPANY

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

In 2009, WMECO was authorized by the DPU to install 6 MW of solar energy generation in its service territory.  In October 2010, WMECO completed development of a 1.8 MW solar generation facility on a site in Pittsfield, Massachusetts, and in December 2011 completed development of a 2.3 MW solar generation facility in Springfield, Massachusetts.  In connection with the Attorney General settlement agreement (as defined below) that approved the Merger in Massachusetts, WMECO committed to increase its solar generation capacity to 8 MW.  WMECO is continuing to evaluate sites suitable for development of the remaining 3.9 MW of capacity.  WMECO will sell all energy and other products from its solar generation facilities into the ISO-NE market.  NSTAR Electric does not own any solar generating facilities, but agreed to issue a request for proposals to enter into long-term contracts for 10 megawatts of solar power in connection with the Attorney General settlement agreement that approved the Merger in Massachusetts.  NSTAR Electric has entered in two contracts for 5 MW of capacity, which contracts are still pending approval at the DPU.  

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

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

Rates

NSTAR Electric and WMECO are each subject to regulation by the DPU, which has jurisdiction over, among other things, rates, accounting procedures, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, acquisition of securities, standards of service, management efficiency and construction and operation of distribution, production and storage facilities.  The present general rate structure for both NSTAR Electric and WMECO consists of various rate and service classifications covering residential, commercial and industrial services.  Massachusetts utilities are entitled under state law to charge rates that are sufficient to allow them an opportunity to recover their reasonable operation and capital costs, to attract needed capital and maintain their financial integrity, while also protecting relevant public interests.

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

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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, meter reading, billing, and customer service.

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

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

·

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

·

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

·

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

·

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

·

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

·

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

Rate Settlement Agreement

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

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

In WMECO’s January 31, 2011 rate decision, the DPU approved a revenue decoupling reconciliation mechanism that provides assurance that WMECO will recover a DPU pre-established level of baseline distribution delivery service revenue to manage all other distribution operating expenses and earn a level of return on its capital investment.  The rates under the January 31, 2011 rate decision are subject to a base distribution rate freeze through 2015 pursuant to the Attorney General settlement agreement .

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

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

Sources and Availability of Electric Power Supply

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

ELECTRIC DISTRIBUTION – NEW HAMPSHIRE

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE

PSNH’s distribution business consists primarily of the generation, delivery and sale of electricity to its residential, commercial and industrial customers.  As of December 31, 2012, PSNH furnished retail franchise electric service to approximately 500,000 retail customers in 211 cities and towns in New Hampshire, covering an area of 5,628 square miles. PSNH also owns and operates approximately 1,200 MW of primarily fossil fueled electricity generation plants.  Included in those electric generating plants is PSNH’s 50 MW wood-burning Northern Wood Power Project at its Schiller Station in Portsmouth, New Hampshire, and approximately 70 MW of hydroelectric generation.  PSNH’s distribution business includes the activities of its generation business.

The Clean Air Project, a wet flue gas desulphurization system (Scrubber), was constructed and placed in service by PSNH at its Merrimack Station in September 2011.  The cost of the Scrubber is expected to be recovered through PSNH's ES rates under New Hampshire law.  By November 2011, both of Merrimack Station’s coal-fired units were integrated with the Scrubber, and the Scrubber is now reducing emissions from the units.  PSNH completed remaining project construction activities in 2012 and the final cost of the project was approximately $421 million.

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

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

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

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Rates

PSNH is subject to regulation by the NHPUC, which has jurisdiction over, among other things, rates, certain dispositions of property and plant, mergers and consolidations, issuances of securities, standards of service, management efficiency and construction and operation of facilities.New Hampshire utilities are entitled under state law to charge rates that are sufficient to allow them an opportunity to recover their reasonable operation and capital costs, to attract needed capital and maintain their financial integrity, while also protecting relevant public interests.

Under New Hampshire law, all of PSNH's customers are entitled to choose competitive energy suppliers, with PSNH providing default energy service under its ES rate for those customers who do not elect to use a third party supplier.  Prior to 2009, PSNH experienced only a minimal amount of customer migration.  However, customer migration levels began to increase significantly in 2009 as energy costs decreased from their historic high levels and competitive energy suppliers with more pricing flexibility were able to offer electricity supply at lower prices than PSNH.  By the end of 2012, approximately 9.4 percent of all of PSNH’s customers (approximately 44 percent of load), mostly large commercial and industrial customers, had switched to competitive energy suppliers.  This was an increase from 2011, when 2.6 percent of customers (approximately 36 percent of load) had switched to competitive energy suppliers.  The increased level of migration has caused an increase in the ES rate, as fixed costs of PSNH’s generation assets must be spread over a smaller group of customers and lower sales volume.  The customers that did not choose a third party supplier, predominately residential and small commercial and industrial customers, are now paying a larger proportion of these fixed costs. On July 26, 2011, the NHPUC ordered PSNH to file a rate proposal that would mitigate the impact of customer migration expected to occur when the ES rate is higher than market prices.  On January 26, 2012, the NHPUC rejected the PSNH proposal and ordered PSNH to file a new proposal no later than June 30, 2012, addressing certain issues raised by the NHPUC.  On April 27, 2012, PSNH filed its proposed Alternative Default Energy Service Rate that addresses customer migration, with an effective date of July 1, 2012.  The proposal, if implemented, would result in no impact to earnings and would allow for an increased contribution to fixed costs for all ES customers.  Hearings were held on October 18, 2012 and November 26, 2012.  A final decision is expected in the first quarter of 2013.

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

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

·

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

·

SCRC, which allows PSNH to recover its stranded costs, including above-market expenses incurred under mandated power purchase obligations and other long-term investments and obligations.  PSNH has financed a significant portion of its stranded costs through securitization by issuing RRBs secured by the right to recover these stranded costs from customers over time. PSNH recovers the costs of these RRBs through the SCRC rate.  The amount of the RRB obligation decreases each quarter and the RRBs are scheduled to be retired as of May 1, 2013.

·

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

On an annual basis, PSNH files with the NHPUC an ES/SCRC cost reconciliation filing for the preceding year.  The difference between revenues and costs are included in the ES/SCRC rate calculations and refunded to or recovered from customers in the subsequent period approved by the NHPUC.  On December 28, 2012, the NHPUC issued orders approving PSNH’s requests to adjust its ES and SCRC rates effective with service rendered on and after January 1, 2013.  The orders approve an increase to the ES billing rate to reflect projected costs for 2013 and a decrease to the SCRC billing rate to reflect the full amortization of RRBs as of May 1, 2013.  The impact to customers that purchase energy from PSNH is a net increase of 1.287 cents per kWh in total rates.

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

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

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

Sources and Availability of Electric Power Supply

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:

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:

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 percentof 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 percentof 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 percentof 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:

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

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 2012,2015, approximately 5954 percent of PSNH’sPSNH's load was met through its own generation, long-term power supply provided pursuant to orders of the NHPUC, and contracts with third parties.competitive energy suppliers.  The remaining 41 percent of46 percentof 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 20132016 in a similar manner.  Included in the 5954 percent above are PSNH’sPSNH's obligations to purchase power from approximately two dozen IPPs, the output of which it either uses to serve its customer load or sells into the ISO-NE market.

NATURAL GAS DISTRIBUTION SEGMENT

General

NU’s natural gas distribution segment consists of the distribution businesses of NSTAR GasMerrimack and Yankee Gas, which are engaged in the distribution of natural gasSchiller Stations have recently operated at lower than typical capacity factors due to retail customers in eastern Massachusetts and Connecticut, respectively.  

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

⁽¹⁾

NSTAR Gas’ revenue for the full-year ended December 31, 2012,Hydro stations have been operating at high capacity factors. PSNH’s Energy Service Rate has been provided for comparative purposes only.

A summaryset at 9.99 cents per kWh effective January 1, 2016, which includes 1.27 cents per kWh reflecting full recovery of NSTAR Gas’ and Yankee Gas’ retail firm natural gas sales and percentage changes in million cubic feet for 2012, as compared to 2011, is as follows:

⁽¹⁾

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

⁽²⁾

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

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

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

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NSTAR GAS COMPANY

NSTAR Gas distributes natural gas to approximately 272,000 customers in 51 communities in central and eastern Massachusetts covering 1,067 square miles.  Total throughput (sales and transportation) in 2012 was approximately 60.5 Bcf.  NSTAR Gas provides firm natural gas sales service to retail customers who require a continuous natural gas supply throughout the year, such as residential customers who rely on gas for heating, hot water and cooking needs, and commercial and industrial customers who choose to purchase natural gas from NSTAR Gas.  

Rates

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

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

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

·

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

·

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

·

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

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

Sources and Availability of Natural Gas Supply

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

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

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

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

YANKEE GAS SERVICES COMPANY

Yankee Gas operates the largest natural gas distribution system in Connecticut as measured by number of customers (approximately 212,000 customers in 71 cities and towns), and size of service territory (2,187 square miles).  Total throughput (sales and transportation) in 2012 was approximately 51 Bcf.  Yankee Gas provides firm natural gas sales service to retail customers who require a continuous natural gas supply throughout the year, such as residential customers who rely on gas for heating, hot water and cooking needs, and commercial and industrial customers who choose to purchase natural gas from Yankee Gas.  Yankee Gas also owns a 1.2 Bcf LNG facility in Waterbury, Connecticut, which is used primarily to assist it in meeting its supplier-of-last-resort obligations and also enables it to make economic purchases of natural gas, which typically occur during periods of low demand.

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

Rates

Yankee Gas is subject to regulation by PURA, which has jurisdiction over, among other things, rates, accounting procedures, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, standards of service, affiliate transactions, management efficiency and construction and operation of distribution, production and storage facilities.

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

·

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

·

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

·

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

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

Sources and Availability of Natural Gas Supply

PURA requires that Yankee Gas meet the needs of its firm customers under all weather conditions.  Specifically, Yankee Gas must structure its supply portfolio to meet firm customer needs under a design day scenario (defined as the coldest day in 30 years) and under a design year scenario (defined as the average of the four coldest years in the last 30 years).  Yankee Gas also owns a 1.2 Bcf LNG facility in Waterbury, Connecticut, which is used primarily to assist Yankee Gas in meeting its supplier-of-last-resort obligations and also enables Yankee Gas to make economic purchases of natural gas, typically in periods of low demand.  Yankee Gas’ on-system stored LNG and underground storage supplies help to meet consumption needs during the coldest days of winter.  Yankee Gas obtains its interstate capacity from the three interstate pipelines that directly serve Connecticut: the Algonquin, Tennessee and Iroquois Pipelines.  Yankee Gas has long-term firm contracts for capacity on TransCanada Pipelines Limited Pipeline, Vector Pipeline, L.P., Tennessee Gas Pipeline, Iroquois Gas Transmission Pipeline, Algonquin Pipeline, Union Gas Limited, Dominion Transmission, Inc., National Fuel Gas Supply Corporation, Transcontinental Gas Pipeline Company, and Texas Eastern Transmission, L.P. pipelines.  Based on information currently available regarding projected growth in demand and estimates of availability of future supplies of pipeline natural gas, Yankee Gas believes that its present sources of natural gas supply are adequate to meet existing load and allow for future growth in sales.  

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ELECTRIC TRANSMISSION SEGMENT

General

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, generation owners and marketers are parties to a series of agreements that provide for coordinated planning and operation of the region's generation and transmission facilities and the rules by which they participate in the wholesale markets and acquire transmission services.  Under these arrangements, ISO-NE, a non-profit corporation whose board of directors and staff are independent of all market participants, has served since 2005serves as the regional transmission organization of the New England transmission system.  ISO-NE works to ensure the reliability

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Wholesale Transmission Revenues

A summary of the system, administers, subject to FERC approval, the independent system operator tariff, oversees the efficient and competitive functioning of the regionalEversource Energy's wholesale power market and determines which costs of all regional major transmission facilities are shared by consumers throughout New England.revenues is as follows:

Wholesale Transmission Rates

Wholesale transmission revenues are recovered through FERC approved formula rates that are approved by the FERC.  Our transmissionrates.  Transmission revenues are recoveredcollected from New England customers, through charges that recover coststhe majority of transmission and other transmission-related services provided by all regional transmission owners, with a portion of those revenues collected from thewhich are distribution businessescustomers of CL&P, NSTAR Electric, PSNH and WMECO.  TheseThe transmission rates provide for the annual reconciliation and recovery or refund of estimated costs to actual costs.  The differencefinancial impacts of differences between actual and estimated and actual costs isare deferred for future recovery from, or refunded to, transmission customers.

FERC Base ROE ProceedingsComplaints

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

On September 30, 2011, several New England state attorneys general, state regulatory commissions, consumer advocates, consumer groups, municipal parties and other parties filed a joint(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 withrefund periods stipulated in the separate complaints.  In 2014, the FERC under Sections 206ordered a 10.57 percent base ROE for the first complaint refund period and 306prospectively from October 16, 2014 and that a utility's total or maximum ROE shall not exceed the top of the Federal Power Act allegingnew 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 ROEplus anyincentive 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 usedshould 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 calculating formula rateslate 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 service undertariffs their rights of first refusal to build transmission.  On March 19, 2015, the ISO-NE Open Access Transmission TariffFERC acted on all rehearing requests filed by New England transmission owners,the NETOs, including CL&P, NSTAR Electric, PSNH and WMECO, is unjust and unreasonable.other parties and accepted the November 2013 compliance filing made by ISO-NE and the NETOs, subject to further compliance.  The complainants assertedFERC accepted our proposal that the current 11.14 percent rate,new competitive transmission planning process will not apply to certain projects, which became effectivehave 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 2006, is excessive due to changes inNovember 2015 and was accepted by the capital markets and are seeking an order to reduce the rate, which would be effective September 30, 2011 throughFERC on December 31, 2012.  In response, the New England transmission owners filed testimony and analysis based on standard FERC methodology and precedent, demonstrating that the base ROE of 11.14 percent remained just and reasonable.14, 2015.

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

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

As of December 31, 2012, CL&P, NSTAR Electric, PSNH, and WMECO had approximately $2.1 billion of aggregate shareholder equity invested in their transmission facilities.  As a result, each 10 basis point change in the authorized base ROE would change annual consolidated earnings by an approximate $2.1 million.  We cannot at this time predict the ultimate outcome of this proceeding or the estimated impact on CL&P’s, NSTAR Electric’s, PSNH’s, or WMECO’s respective financial position, results of operations or cash flows.

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FERC Order No. 1000:  On October 25, 2012, ISO-NE and a majority of the New England transmission owners, including  CL&P, NSTAR Electric, PSNH and WMECO, made a comprehensive compliance filing as required by FERC Order No. 1000 and Order No. 1000-A, issued on July 21, 2011 and May 17, 2012, respectively.  The compliance filing first seeks to preserve the existing reliability planning process in New England based oneven 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 previous approval of transmission owners’ rights under the Transmission Operating Agreement withdetermination that ISO-NE and the superiority of the current planning process, which has resulted in major transmission construction, large reliability benefits and reduction of market costs.  The filing also contains a new process forshould select public policy transmission planning that incorporates opportunities for competing, non-incumbent projects and cost allocation amongafter a competitive process.  The Court is expected to resolve the supporting states.  In mid-January 2013, ISO-NE and the majority of New England transmission owners filed answers to various stakeholders that submitted protests to the compliance filing.  We cannot predict the final outcome or impact on us; however implementation of FERC’s goalsappeals 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.2016.

Transmission Projects

NEEWS: GSRP, a project that involvesDuring 2015, we were involved in the planning, development and construction of 115 kV and 345 kV overhead lines by CL&P and WMECO from Ludlow, Massachusetts to Bloomfield, Connecticut, is the first, largest and most complicated project withina series of electric transmission projects, including the NEEWS family of projects.  The $718 million project is expected to be fully placed in service in late 2013.  As of December 31, 2012,projects; the project was approximately 93 percent complete and we have placed $298 million in service.  

The Interstate Reliability Project, which includes CL&P’s construction of an approximately 40-mile, 345 kV overhead line from Lebanon, Connecticut to the Connecticut-Rhode Island border in Thompson, Connecticut where it will connect to transmission enhancements being constructed by National Grid, is our second major NEEWS project.  All siting applications have been filed by CL&P and National Grid.  On January 2, 2013, the Connecticut Siting Council issued a final decision and order approving the Connecticut portion of the project.  Decisions in Rhode Island and Massachusetts are expected between the end of 2013 and early 2014.  The $218 million project is expected to be placed in service in late 2015.  

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

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

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

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Cape Cod Reliability Projects:  Transmission projects serving Cape Cod in the Southeastern Massachusetts (SEMA) reliability region consist

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

Northern Pass:  Northern Pass, which is NPT'sour 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 atHampshire; and the Québec-New Hampshire border withClean Energy Connect Project, which is a planned HQ HVDC transmission, line.  Effective April 10, 2012, as a result of the merger, NUTV owned 100 percent of NPT.  NPT has identified a new routewind 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 northern-most partaccompanying Item 7,Management's Discussion and Analysis of the project’s route where PSNH did not own any rightsFinancial Condition and Results of way.  We expect to file the new route with the DOE in the first quarter of 2013, and we believe that NPT will be completed in early 2017.

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

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

Transmission Rate Base

Under our FERC-approved tariff, 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 2012,2015, our estimated transmission rate base was approximately $4.2$5.2 billion, including approximately $2.2$2.4 billion at CL&P, $960 million$1.4 billion at NSTAR Electric, $412$548 million at PSNH, and $620$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:

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:

 ⁽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 $5$9.2 billion from 20132016 through 2015.2019.  Of the $5$9.2 billion, we expect to invest approximately $2.5$4.9 billion in our electric and natural gas distribution segments including our generation businesses, and $2.3$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 of approximately $1.6 billion from 2016 through 2017 in our electric transmission segment.related to Access Northeast or Clean Energy Connect.

FINANCING

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

As of December 31, 2012, approximately $7302015, a total of $200 million of NU'sEversource’s long-term debt, all at NSTAR Electric, will be paid in the next 12 months, consisting of $550 million for NU parent, $55 million for WMECO, and $125 million for CL&P.months.  

NUCLEAR DECOMMISSIONING

GeneralFUEL 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.  EachThe Yankee Company collectsCompanies 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.  These companies in turnThe 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.  

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

Our share of the obligations to support the Yankee Companies under FERC-approved contracts is the same as the ownership percentages above.  As a result of the Merger, weWe consolidate the assets and obligations of CYAPC and YAEC on our consolidated balance sheet.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.  PSNH owns approximately 1,200 MW of generation assets.  In 2011, PSNH’s Clean Air Project, the installation of a wet flue gas desulphurization system at its Merrimack coal station to reduce its mercury and sulfur dioxide emissions, was placed into service.  The Clean Air Project was fully operational by mid-2012 and is designed to capture more than 80 percent of the mercury in the coal from the coal burning stations and to reduce sulfur dioxide emissions by more than 90 percent, making Merrimack one of the cleanest coal-burning plants in the nation.  The final cost of the project was approximately $421 million.  Compliance with additional environmental laws and regulations, particularly air and water pollution control requirements, may cause changes in operations or require further investments in new equipment at existing facilities.  

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Water Quality Requirements

The Clean Water Act requires every “point source”"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 ourPSNH's generation facilities.  

In each1997, PSNH filed in a timely manner for a renewal of the last three years,NPDES permit for the costs incurred by PSNH related to compliance with NPDES and state discharge permits have not been material.

On September 29,Merrimack Station.  As a result, the existing permit was administratively continued.  In 2011, the EPA issued for public review and comment a draft renewal NPDES permit under the Clean Water Act for PSNH’sPSNH's Merrimack Station.Station for public review and comment.  The draftproposed permit contains many significant conditions to future operation.  The proposed permit would require PSNH to install a closed-cycle cooling system (including cooling towers) at the station.  The EPA estimated that the net present value cost to install this system and operate it over a 20-year period would be approximately $112 million.  On October 27, 2011, the EPA extended the initial 60-day public reviewPSNH and comment period on theother electric utility groups filed thousands of pages of comments contesting EPA's draft permit for an additional 90 days until February 28, 2012.  In its filed comments,requirements.  PSNH stated that the data and studies supplied to the EPA demonstratesdemonstrate 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 has nodoes not have a set deadline to consider comments and to issue a final permit.  Merrimack Station canis permitted to continue to operate under its currentpresent permit pending issuance of the final permit and subsequent resolution of appealsmatters appealed by PSNH and other parties.  Due to the site specific characteristics of PSNH's other fossil fueledcoal- and oil-fired electric generating stations, we believe it is unlikely that therethey would beface similar permit requirements imposed on them.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 December 2011, the EPA finalized the Mercury and Air Toxic Standards (MATS) that require the reduction of emissions of hazardous air pollutants from new and existing coal- and oil-fired electric generating units.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 coalcoal- and oil-fired units.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 fossil fueledcoal- and oil-fired electric generating unitsstations subject to MATS, including the two units at Merrimack Station, Newington Station and the two coal units at Schiller Station.  We believe the Clean Air Project at our Merrimack Station, together with existing equipment, will enable the facility to meet the MATS requirements.  A review of the potential impact of MATS on our other PSNH units is not yet complete.  Additional incrementalAt Schiller Station additional controls may be required forare being installed at the two coal firedcoal-fired units, at Schiller Station.  To date, the financial impactcost of this potential control has not been determined.

NU’s carbon emission inventory accounts for and reports all direct carbon dioxide (CO₂) methane (CH₄) nitrous oxide (N₂O) sulfur hexafluoride (SF₆) emissions for operations of NU and its subsidiaries in carbon dioxide equivalents.  Total carbon emissions include those from sources owned or operated by NU (Scope 1) and those that are a consequence of NU’s activities, but occur from sources owned or controlled by others, such as emissions from purchased electricity and line loss during the transmission and distribution of electricity (Scope 2).  NU emissions expressed in thousand metric tons of carbon dioxide equivalent (CO₂-e) for NU and its system companies for 2009 through 2011 are shown below.

Data was collected and calculated using the World Resource Institute greenhouse gas protocol tools except for stationary combustion emissions associated with electric generating units where more accurate Continuous Emissions Monitoring System data was available.  EPA reporting protocol was used for generation calculations where applicable.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’sHampshire's RPS provision requires increasing percentages of the electricity sold to retail customers to have direct ties to renewable sources.  In 2012,2015, the total RPS obligation was 138.3 percent and it will ultimately reach 26.524.8 percent in 2025.  Energy suppliers, like PSNH, purchasemust possess sufficient quantities of RECs from producers that generate energy from a qualifying resource and use them to satisfy the RPS requirements.  PSNH also owns renewable sources and uses a portion of internally generated RECs and purchased RECs to meet its RPS obligations.obligations and sells other internally generated RECs when it is economically beneficial to do so.  To the extent that a supplier, like PSNH, is unable to purchasedoes not possess sufficient RECs to satisfy its RPS requirements, it makes up the difference between the RECs purchased and its total obligationany shortfall by making an alternative compliance payment for eachat a rate per REC requirement for which PSNH is deficient.established by law.  The costs of both the RECs and alternative compliance payments are recovered by PSNH through its ESdefault energy service rates charged to customers.

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

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Similarly, Connecticut's RPS statute requires increasing percentages of the electricity sold to retail customers to have direct ties to renewable sources.  In 2012,2015, the total RPS obligation was 16 percent and19.5 percentand will ultimately reach 27 percent in 2020.  CL&P is permitted to recover any costs incurred in complying with RPS from its customers through rates.its GSCrate.

Massachusetts’Massachusetts' RPS program also requires electricity suppliers to meet renewable energy standards.  For 2012,2015, the requirement was 16.619.25 percent, and will ultimately reach 27.122.1 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’sWMECO's solar units are sold to other energy suppliers, and the proceeds from these sales are credited back to customers.

Hazardous Materials Regulations

Prior to the last quarter of the 20th century when environmental best practices and laws were implemented, utility companies often disposed of residues from operations by depositing or burying them on-site or disposing of them at off-site landfills or other facilities.  Typical materials disposed of include coal gasification byproducts, fuel oils, ash, and other materials that might contain polychlorinated biphenyls or that otherwise might be hazardous.  It has since been determined that deposited or buried wastes, under certain circumstances, could cause groundwater contamination or create other environmental risks.  We have recorded a liability for what we believe, based upon currently available information, is our estimatedreasonably estimable environmental investigation, remediation, and/or remediationNatural Resource Damages costs for waste disposal sites for which we expect to bear legalhave probable liability.  We continue to evaluate the environmental impact of our former disposal practices.  Under federal and state law, government agencies and private parties can attempt to impose liability on us for these practices.recovery of investigation and remediation costs at hazardous waste sites.  As of December 31, 2012,2015, the liability recorded by us for our reasonably estimable and probable environmental remediation costs for known sites needing investigation and/or remediation, exclusive of recoveries from insurance or from third parties, was approximately $39.4$51.1 million, representing 7764 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 through our subsidiaries, currently have partial or full ownership responsibilities at former MGP sites that have a reserve balance of $34.5$45.5 million of the total $39.4$51.1 million as of December 31, 2012.

HWP, a wholly owned subsidiary2015.  Many of NU, is continuing to evaluate additional potential remediation requirements at a river site in Massachusetts containing tar deposits associated with anthese MGP site that HWP sold to HG&E, a municipal electric utility, in 1902.  HWP is at least partially responsible for this site and has already conducted substantial investigative and remediation activities.  HWP's share of the remediation costs related to this site is notare recoverable from customers.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.

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

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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”"air pollution" that endangerendangers 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"cap and trade”trade" laws, carbon taxes, fuel and energy taxes, or regulations requiring additional capital expenditures at our generating facilities.  We expect that any costs of these rules and regulations would be recovered from customers.

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Connecticut, New Hampshire and Massachusetts are each members of the Regional Greenhouse Gas Initiative (RGGI), a cooperative effort by nine northeastern and mid-Atlantic states, to develop a regional program for stabilizing and reducing CO₂ emissions from fossil fueledcoal- 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.  AThe 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 demonstrate compliance100 percent of its remaining emissions for the three-year control period at the end of a three year compliance period that began in 2012.the period.

PSNH anticipates that its generating units will emit between twoone million and fourthree 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’sPSNH's Northern Wood Power Project.  New Hampshire legislation provides up to 1.5 million banked CO₂ allowances per year for PSNH’s fossil fueled electric generating plants during the 2012 through 2014 compliance period.Project, which emissions are an offset.  PSNH expects to satisfysatisfied its remaining RGGI requirements by purchasing CO₂ allowances at auction or in the secondary market.auction.  The cost of complying with RGGI requirements is recoverable from PSNH customers.  Current legislation provides athat the portion of the RGGI auction proceeds in excess of $1 per allowance will be refunded to customers.

Because none of NU’sEversource Energy's other subsidiaries, CL&P, NSTAR Electric or WMECO, currently owns any generating assets (other than twoWMECO's solar photovoltaic facilities owned by WMECO, whichthat 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 willare likely to be included in the overall wholesale rates charged, which costs are then recoverable from customers.

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

FERC Hydroelectric Project Licensing

Federal Power Act licenses may be issued for hydroelectric projects for terms of 30 to 50 years as determined by the FERC.  Upon the expiration of an existing license, (i) the FERC may issue a new license to the existing licensee, (ii) the United States may take over the project, or (iii) the FERC may issue a new license to a new licensee, upon payment to the existing licensee of the lesser of the fair value or the net investment in the project, plus severance damages, less certain amounts earned by the licensee in excess of a reasonable rate of return.

PSNH 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 involved withcompleting the early stages of relicensing atapplication for its 6.5 MW Eastman Falls Hydro Station, which is comprised of two units, totaling 6.5 MW.

Licensed operating hydroelectric projects are not generally subject to decommissioning during the license termfor which expires in the absence of a specific license provision that expressly permits the FERC to order decommissioning during the license term.  However, the FERC has taken the position that under appropriate circumstances it may order decommissioning of hydroelectric projects at relicensing or may require the establishment of decommissioning trust funds as a condition of relicensing.  The FERC may also require project decommissioning during a license term if a hydroelectric project is abandoned, the project license is surrendered or the license is revoked.  PSNH is not presently encountering any of these challenges.2017.

EMPLOYEES

As of December 31, 2012, we2015, Eversource Energy employed a total of approximately 8,8427,943 employees, excluding temporary employees, of which 1,7871,037 were employed by CL&P, 1,2041,240 were employed by NSTAR Electric, 694 were employed by PSNH, 348and 291 were employed by WMECO, and 1,619 employees employed by NSTAR Electric & Gas Corporation provided services to NSTAR Electric.WMECO.  Approximately 47.850 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 1314 collective bargaining agreements.

INTERNET INFORMATION

Our website address is www.nu.com.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 NU's,Eversource Energy's, CL&P's, NSTAR Electric’s,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 Northeast Utilities, 56 ProspectEversource Energy, 107 Selden Street, Hartford,Berlin, CT 06103.06037.  

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Item 1A.

Risk Factors

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

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

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

·

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

·

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

·

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

·

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

·

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

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

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

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

Actsbreaches, acts of war or terrorism, physical attacks or grid disturbances resulting from internal or external sources could target our generation, transmission, distribution and distributiongeneration facilities or our data managementinformation technology systems.  Such actions could impair our ability to manage these facilities, or operate our systemsystems 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.

Our goodwill is valuedStrategic development opportunities in both electric and recorded at an amount that, if impairednatural gas transmission may not be successful and written down,projects may not commence operation as scheduled or be completed, which could adversely affecthave a material adverse effect on our future operating results and total capitalization.business prospects.

We have a significant amount of goodwill on our consolidated balance sheet.  The carrying value of goodwill representsare pursuing broader strategic development investment opportunities that will benefit the fair value of an acquired business in excess of identifiable assets and liabilities as of the acquisition date.  As of December 31, 2012, goodwill totaled $3.5 billion, of which $3.2 billion was attributableNew England region related to the acquisitionconstruction of NSTAR in April 2012.  Total goodwill represented approximately 38 percentelectric and natural gas transmission facilities, interconnections to generating resources and other investment opportunities.  The development, construction and expansion of our $9.2 billion of shareholders’ equityelectric transmission and approximately 12 percent of our total assets of $28.3 billion.  We perform an analysis of our goodwill balances to test for impairment on an annual basis or whenever events occur or circumstances change that would indicate a potential for impairment.  A determination that goodwill is deemed to be impaired wouldnatural gas transmission facilities involve numerous risks.  Various factors could result in a non-cash charge that could materially adversely affectincreased 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 total capitalization.cash flows could be adversely affected or our future growth opportunities may not be realized as anticipated.

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

Severe weather, such as Tropical Storm Irene in August 2011, the October 29, 2011 snowstorm, Hurricane Sandy in October 2012, and the February 2013 blizzard, and other such major natural disasters, could cause widespread damage to our transmission and distribution facilities.  The resulting cost of repairing damage to our facilities and the potential disruption of our operations could exceed our financial reserves and insurance.  

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Tropical Storm Irene, the October 29, 2011 snowstorm, and Hurricane Sandy caused significant damage to our transmission and distribution systems.  As a result along with previously deferred costs from other storms,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 recorded approximately $548 million (approximately $414 million at CL&P)invested are not selected for estimated restoration costs as regulatory assets as of December 31, 2012, subject to future recovery from customers.  If, upon review, any of our state regulatory authorities finds that our actions were imprudent, some of those restoration costs may not be recoverable from customers.  The inability to recoverconstruction, it would have a significant amount of such costs could have anmaterial adverse effect on our future financial position, results of operations and cash flows.

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

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

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

The rates that our Regulatedelectric and gas companies charge their respective retail and wholesale customers are determined by their state utilityregulatory commissions and by FERC.  These commissions also regulate the companies’companies' accounting, operations, the issuance of certain securities and certain other matters.  FERC also regulates theirthe 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 commissions’ policiesFERC 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 actionsconsiderations, 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 Regulated companies’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, or failure of, or damage to operating equipment, information technology systems, or processes, (especiallyespecially due to age);age; labor disputes; disruptions in the delivery of electricity and natural gas, including impacts on us or our customers; increased capital expenditure requirements, including those due to environmental regulation; information security risk, such as a breach of our systems on which sensitive utility customer data and account information are stored; catastrophic events such as fires, explosions, or other similar occurrences; extreme weather conditions beyond equipment and plant design capacity; other unanticipated operations and maintenance expenses and liabilities; and potential claims for property damage or personal injuries beyond the scope of our insurance coverage.  TheMany 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.  At PSNH, outagesOutages 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.

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Difficulties in obtaining necessary rightsThe unauthorized access to and the misappropriation of way,confidential and proprietary customer, employee, financial or siting, design or other approvals for major transmission projects, environmental concerns or actions of regulatory authorities, communities or strategic partners may cause delays or cancellation of such projects, which wouldsystem operating information could adversely affect our earnings.business operations and adversely impact our reputation.

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

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

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

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

Manyprivacy protection liability insurance to cover limited damages and defense costs arising from unauthorized disclosure of, our transmission projects are expectedor failure to help alleviate identified reliability issues and reduce customers' costs.  However, if, due to economic events or factors or further regulatory or other delays, the in-service date for one or more of these projects is delayed, there may be increased risk of failures in the electricity transmission system and supply interruptions or blackouts, which could have an adverse effect on our earnings.

The FERC has followed a policy of providing incentives designed to encourage the construction of new transmission facilities, including higher returns on equity and allowing facilities under construction to be placed in rate base.  Our projected earnings and growth could be adversely affected were FERC to reduce these incentives in the future below the levels presently anticipated.

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

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

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

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

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

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

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

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

Under state law, our Regulated companies are entitled to charge rates that are sufficient to allow them an opportunity to recover their reasonable operating and capital costs, to attract needed capital and maintain their financial integrity, while also protecting relevant public interests.  Each of these companies prepares and submits periodic rate filings with their respective state regulatory commissions for review and approval.  There is no assurance that these state commissions will approve the recovery of all such costs incurred by our Regulated companies, such as for construction, operation and maintenance,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 return on investment on their respective regulated assets, includingbreach of private information.  This insurance covers amounts paid to avert, prevent or stop a network attack or the construction costs incurred by PSNH for the Clean Air Project at its Merrimack Station.  PSNH’s expenditures for the project are subject to prudence review by the NHPUC.  The amountdisclosure of costs incurred by the Regulated companies, coupled with increases in fuelpersonal information, and energy prices, could lead to consumer or regulatory resistance to the timely recovery of such costs, thereby adversely affecting our financial position, results of operations or cash flows.  

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

In addition, CL&P, NSTAR Electric and WMECO procure energy for a substantial portion of their customers’ needs via requests for proposal on an annual, semi-annual or quarterly basis.  CL&P, NSTAR Electric and WMECO receive approval to recover the costs of these contracts froma qualified forensics firm to determine the PURAcause, source and DPU, respectively.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 both regulatory agencieswe have consistently approved the solicitation processes, resultsimplemented measures designed to prevent cyber-attacks and recovery of costs, management cannot predict the outcome of future solicitation efforts or the regulatory proceedings related thereto.

PSNH meets most of its energy requirements through its own generation resources and fixed-price forward purchase contracts.  PSNH’s remaining energy needs are met primarily through spot market purchases.  Unplanned forced outages of its generating plants could increase the level of energy purchases needed by PSNH and therefore increase the market risk associated with procuring the energy to meet its requirements.  PSNH recovers these costs through its ES rate, subject to a prudence review by the NHPUC.  We cannot predict the outcome of future regulatory proceedings related to recovery of these costs.

Migration of customers from PSNH energy service to competitive energy suppliersmitigate their effects should they occur.  These measures may increase the cost to the remaining customers of energy produced by PSNH generation assets.

The competitiveness of PSNH’s ES rates are sensitive to the cost of fuels, most notably natural gas, and customer load.  Recently, PSNH’s ES rate has been higher than competitive energy prices offered to some customers. Further increases may occur as the costs associated with the Clean Air Project are fully phased into rates. Customers remaining on PSNH’s ES rate may experience an increase in costnot be effective due to the lower base over whichcontinually evolving nature of efforts to recover PSNH's fixed generation costs. Any such increase may in turn cause further migration and further impact PSNH’s ES rate.  This trend could lead to PSNH continuing to lose retail customers and increasing the burden of supporting the cost of its generation facilities on remaining customers and being unable to support the cost of its generation facilities through an ES rate.

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

Pursuant to New Hampshire law, PSNH placed the Clean Air Project in service at its Merrimack Station in Bow, New Hampshire. PSNH’s recovery of costs in constructing the project is subject to prudence review by the NHPUC.  A material prudence disallowance could adversely affect PSNH’s financial position, results of operations or cash flows.  While we believe we have prudently incurred all expenditures to date, we cannot predict the outcome of any prudence reviews.  Our projected earnings and growth could be adversely affected were the NHPUC to deny recovery of some or all of PSNH’s investment in the project.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 NUEversource parent or subsidiary level will continue to serve in any capacity for any particular period of time.  In addition, a significant portion of our workforce, including many workers with specialized skills maintaining and servicing the electrical infrastructure, will be eligible to retire over the next five to ten years.  Such highly skilled individuals cannot be quickly replaced due to the technically complex work they perform.  We have developed strategic workforce plans to identify key functions and proactively implement plans to assure a ready and qualified workforce, but cannot predict the impact of these plans on our ability to hire and retain key employees.

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

We provide a defined benefit pension plan and other post-retirementpostretirement benefits for a substantial number of employees, former employees and retirees.  Our future pension obligations, costs and liabilities are highly dependent on a variety of factors beyond our control.  These factors include estimated investment returns, interest rates, discount rates, health care cost trends, benefit changes, salary increases and the demographics of plan participants.  If our assumptions prove to be inaccurate, our future costs could increase significantly.  In 2008 and 2009, due to the financial crisis, the value of our pension assets declined.  As a result, we made a contribution of approximately $222 million in 2012 and expect to make an approximate $285 million contribution in 2013. In addition, various factors, including underperformance of plan investments and changes in law or regulation, could increase the amount of contributions required to fund our pension plan in the future.  Additional large funding requirements, when combined with the financing requirements of our construction program, could impact the timing and amount of future equity and debt financings and negatively affect our financial position, results of operations or cash flows. 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, installation of pollution control equipment, emission fees, maintenance and upgrading of facilities, remediation and permitting.  The costs of compliance with existing legal requirements or legal requirements not yet adopted may increase in the future.  An increase in such costs, unless promptly recovered, could have an adverse impact on our business and our financial position, results of operations or cash flows.

In addition, global climate change issues have received an increased focus from federal and state governments, which could potentially lead to additional rules and regulations that impact how we operate our business, both in terms of the power plants we own and operate as well as general utility operations.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, NU parent’sEversource parent's liquidity is dependent on dividends from its subsidiaries, primarily the Regulated companies, its commercial paper program, and its ability to access the long-term debt and equity capital markets.

NUEversource 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 NUEversource parent, and/or NU parent’sEversource parent's ability to access its commercial paper program or the long-term debt and equity capital markets.  Prior to funding NUEversource parent, the Regulatedsubsidiary companies have financial obligations that must be satisfied, including among others, their operating expenses, debt service, preferred dividends (in the case of CL&P and NSTAR Electric),certain subsidiaries, and obligations to trade creditors.  Additionally, the Regulatedsubsidiary companies could retain their free cash flow to fund their capital expenditures in lieu of receiving equity contributions from NUEversource parent.  Should the Regulatedsubsidiary companies not be able to pay dividends or repay funds due to NUEversource parent, or if NUEversource parent cannot access its commercial paper programs or the long-term debt and equity capital markets, NU parent’sEversource 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.