Item 1.

Business

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

Eversource Energy, headquartered in Boston, Massachusetts and Hartford, Connecticut, is a public utility holding company subject to regulation by the FERC under the Public Utility Holding Company Act of 2005.  We are engaged primarily in the energy delivery business through the following wholly owned utility subsidiaries:

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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.

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

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

WMECO are each doing business as Eversource Energy.

Eversource Energy, CL&P, NSTAR Electric, PSNH and WMECO each report their financial results separately.  We also include information in this report on a segment basis for Eversource Energy.  Eversource Energy recognizes three reportable segments: electric distribution, electric transmission and natural gas distribution.  Eversource Energy's electric distribution segment includes the generation businesses of PSNH and WMECO.  These three segments represented substantially all of Eversource Energy's total consolidated revenues for the years ended December 31, 2015 and 2014.  CL&P, NSTAR Electric, PSNH and WMECO do not report separate business segments.   

ELECTRIC DISTRIBUTION SEGMENT

General

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

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

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

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

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

ELECTRIC DISTRIBUTION – CONNECTICUT

THE CONNECTICUT LIGHT AND POWER COMPANY

CL&P's distribution business consists primarily of the purchase, delivery and sale of electricity to its residential, commercial and industrial customers.  As of December 31, 2015, CL&P furnished retail franchise electric service to approximately 1.2 million customers in 149 cities and towns in Connecticut, covering an area of 4,400 square miles.  CL&P does not own any electric generation facilities.  

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

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

Rates

CL&P is subject to regulation by the PURA, which, among other things, has jurisdiction over rates, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, standards of service and construction and operation of facilities.  CL&P's present general rate structure consists of various rate and service classifications covering residential, commercial and industrial services.  CL&P's retail rates include a delivery service component, which includes distribution, transmission, conservation, renewables, CTA, SBC and other charges that are assessed on all customers.  Connecticut utilities are entitled under state law to charge rates that are sufficient to allow them an opportunity to recover their reasonable operating and capital costs, in order to attract needed capital and maintain their financial integrity, while also protecting relevant public interests.

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

CL&P continues to supply approximately 40 percent of its customer load at SS or LRS rates while the other 60 percent of its customer load has migrated to competitive energy suppliers.  Because this customer migration is only for energy supply service, it has no impact on CL&P's electric distribution business or its operating income.

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

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

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

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

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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.

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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 associated with:  various hardship and low income programs; a program to compensate municipalities for losses in property tax revenue due to decreases in the value of electric generating facilities resulting directly from electric industry restructuring.  The SBC is reconciled annually to actual costs incurred and reviewed by the PURA, with any difference refunded to, or recovered from, customers.  

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

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

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

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

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

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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 end of 2016.

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

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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 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 percent of its customer load has migrated to competitive energy suppliers.  WMECO continues to supply approximately 41 percent of its customer load at basic service rates while the other 59 percent of its customer load has migrated to competitive energy suppliers.  Because customer migration is limited to energy supply service, it has no impact on the delivery business or operating income of NSTAR Electric and WMECO.

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

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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.

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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 its destination, as well as ongoing operating costs.

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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.

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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.

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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.

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

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

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

Pursuant to a 2008 DPU order, Massachusetts electric utilities must adopt rate structures that decouple the volume of energy sales from the utility's revenues in their next rate case.  WMECO is currently decoupled and NSTAR Electric will propose decoupling in its next rate case.  

NSTAR Electric and WMECO are each subject to service quality (SQ) metrics that measure safety, reliability and customer service, and could be required to pay to customers a SQ charge of up to 2.5 percent of annual transmission and distribution revenues for failing to meet such metrics.  Neither NSTAR Electric nor WMECO will be required to pay a SQ charge for its 2015 performance as each company achieved results at or above target for all of its respective SQ metrics in 2015.

Sources and Availability of Electric Power Supply

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

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ELECTRIC DISTRIBUTION – NEW HAMPSHIRE

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE

PSNH's distribution business consists primarily of the generation, delivery and sale of electricity to its residential, commercial and industrial customers.  As of December 31, 2015, PSNH furnished retail franchise electric service to approximately 503,000 retail customers in 211 cities and towns in New Hampshire, covering an area of approximately 5,630 square miles.  PSNH currently owns and operates approximately 1,200 MW of primarily coal-, natural gas-, and oil-fired electricity generation plants.  PSNH's distribution business includes the activities of its generation business.

The Clean Air Project, a wet flue gas desulphurization system (Scrubber), was constructed and placed in service by PSNH at its Merrimack Station in 2011.  The Scrubber reduces emissions of SO2 and mercury from Merrimack Station by over 90 percent, which is well in excess of state and federal requirements.  PSNH is permitted to recover prudent Scrubber costs through its default energy service rates under New Hampshire law.  Effective January 1, 2016, PSNH is recovering all Scrubber costs in rates charged to customers.  For further information, see "Regulatory Developments and Rate Matters – New Hampshire – Clean Air Project Prudence Proceeding" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations .

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

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:

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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.

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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.  

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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.

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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.  

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

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·

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

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

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

Generation Divestiture

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

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

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

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

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

Sources and Availability of Electric Power Supply

During 2015, approximately 54 percent of PSNH's load was met through its own generation, long-term power supply provided pursuant to orders of the NHPUC, and contracts with competitive energy suppliers.  The remaining 46 percent of PSNH's load was met by short-term (less than one year) purchases and spot purchases in the competitive New England wholesale power market.  PSNH expects to meet its load requirements in 2016 in a similar manner.  Included in the 54 percent above are PSNH's obligations to purchase power from approximately two dozen IPPs, the output of which it either uses to serve its customer load or sells into the ISO-NE market.

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

ELECTRIC TRANSMISSION SEGMENT

General

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

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Wholesale Transmission Rates

Wholesale transmission revenues are recovered through FERC approved formula rates.  Transmission revenues are collected from New England customers, the majority of which are distribution customers of CL&P, NSTAR Electric, PSNH and WMECO.  The transmission rates provide for the annual reconciliation of estimated to actual costs.  The financial impacts of differences between actual and estimated costs are deferred for future recovery from, or refunded to, transmission customers.

FERC Base ROE Complaints

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

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

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

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

FERC Order No. 1000

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

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

Transmission Projects

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

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development of Northern Pass, which is our planned HVDC transmission line from the Québec-New Hampshire border to Franklin, New Hampshire and an associated alternating current radial transmission line between Franklin and Deerfield, New Hampshire; and the Clean Energy Connect Project, which is a planned transmission, wind and hydro generation project that we intend to develop with experienced renewable generation companies. For further information, see "Business Development and Capital Expenditures – Electric Transmission Business" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations .

Transmission Rate Base

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

NATURAL GAS DISTRIBUTION SEGMENT

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

Yankee Gas owns a 1.2 Bcf LNG facility in Waterbury, Connecticut, which is used primarily to assist Yankee Gas in meeting its supplier-of-last-resort obligations and also enables it to provide economic supply and make economic refill of natural gas typically during periods of low demand.  

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

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

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

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

FINANCING

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

As of December 31, 2015, a total of $200 million of Eversource’s long-term debt, all at NSTAR Electric, will be paid in the next 12 months.  

NUCLEAR FUEL STORAGE

CL&P, NSTAR Electric, PSNH, WMECO and several other New England electric utilities are stockholders in three inactive regional nuclear generation companies, CYAPC, MYAPC and YAEC (collectively, the Yankee Companies).  The Yankee Companies have completed the physical decommissioning of their respective generation facilities and are now engaged in the long-term storage of their spent nuclear fuel.  The Yankee Companies have completed collection of their decommissioning and closure costs through the proceeds from the spent nuclear fuel litigation against the DOE and has refunded amounts to its member companies.  These proceeds were used by the Yankee Companies to offset the decommissioning and closure cost amounts due from their member companies or to decrease the wholesale FERC-approved rates charged under power purchase agreements with CL&P, NSTAR Electric, PSNH and WMECO and several other New England utilities.  The decommissioning rates charged by the Yankee Companies have been reduced to zero.  CL&P, NSTAR Electric, PSNH and WMECO can recover these costs from, or refund proceeds to, their customers through state regulatory commission-approved retail rates.  

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

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

OTHER REGULATORY AND ENVIRONMENTAL MATTERS

General

We are regulated in virtually all aspects of our business by various federal and state agencies, including FERC, the SEC, and various state and/or local regulatory authorities with jurisdiction over the industry and the service areas in which each of our companies operates, including the PURA, which has jurisdiction over CL&P and Yankee Gas, the NHPUC, which has jurisdiction over PSNH, and the DPU, which has jurisdiction over NSTAR Electric, NSTAR Gas and WMECO.

Environmental Regulation

We are subject to various federal, state and local requirements with respect to water quality, air quality, toxic substances, hazardous waste and other environmental matters.  Additionally, major generation and transmission facilities may not be constructed or significantly modified without a review of the environmental impact of the proposed construction or modification by the applicable federal or state agencies.  

Water Quality Requirements

The Clean Water Act requires every "point source" discharger of pollutants into navigable waters to obtain a National Pollutant Discharge Elimination System (NPDES) permit from the EPA or state environmental agency specifying the allowable quantity and characteristics of its effluent.  States may also require additional permits for discharges into state waters.  We are in the process of maintaining or renewing all required NPDES or state discharge permits in effect for PSNH's generation facilities.  

In 1997, PSNH filed in a timely manner for a renewal of the NPDES permit for the Merrimack Station.  As a result, the existing permit was administratively continued.  In 2011, the EPA issued a draft renewal NPDES permit for PSNH's Merrimack Station for public review and comment.  The proposed permit contains many significant conditions to future operation.  The proposed permit would require PSNH to install a closed-cycle cooling system (including cooling towers) at the station.  The EPA estimated that the net present value cost to install this system and operate it over a 20-year period would be approximately $112 million.  PSNH and other electric utility groups filed thousands of pages of comments contesting EPA's draft permit requirements.  PSNH stated that the data and studies supplied to the EPA demonstrate the fact that a closed-cycle cooling system is not warranted.  On April 18, 2015 EPA issued a revised section of the draft NPDES permit for Merrimack Station.  The revised portion of the draft permit deals solely with the treatment of wastewater from the flue gas desulfurization system.  On August 18, 2015 PSNH again submitted comments.  The EPA does not have a set deadline to consider comments and to issue a final permit.  Merrimack Station is permitted to continue to operate under its present permit pending issuance of the final permit and subsequent resolution of matters appealed by PSNH and other parties.  Due to the site specific characteristics of PSNH's other coal- and oil-fired electric generating stations, we believe it is unlikely that they would face similar permitting determinations.

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Air Quality Requirements

The Clean Air Act Amendments (CAAA), as well as New Hampshire law, impose stringent requirements on emissions of SO ₂ and NO _X for the purpose of controlling acid rain and ground level ozone.  In addition, the CAAA address the control of toxic air pollutants.  Requirements for the installation of continuous emissions monitors and expanded permitting provisions also are included.

In 2011, the EPA finalized the Mercury and Air Toxic Standards (MATS) that require the reduction of emissions of hazardous air pollutants from new and existing coal- and oil-fired electric generating stations.  Previously referred to as the Utility MACT (maximum achievable control technology) rules, it establishes emission limits for mercury, arsenic and other hazardous air pollutants from coal- and oil-fired electric generating stations.  MATS is the first implementation of a nationwide emissions standard for hazardous air pollutants across all electric generating units and provides utility companies with up to five years to meet the requirements.  PSNH owns and operates approximately 1,000 MW of coal- and oil-fired electric generating stations subject to MATS, including the two units at Merrimack Station, Newington Station and the two coal units at Schiller Station.  We believe the Clean Air Project at our Merrimack Station, together with existing equipment, will enable the facility to meet the MATS requirements.  At Schiller Station additional controls are being installed at the two coal-fired units, the cost of which is estimated to be approximately $2.5 million.

Each of the states in which we do business also has Renewable Portfolio Standards (RPS) requirements, which generally require fixed percentages of our energy supply to come from renewable energy sources such as solar, hydropower, landfill gas, fuel cells and other similar sources.  

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

Similarly, Connecticut's RPS statute requires increasing percentages of the electricity sold to retail customers to have direct ties to renewable sources.  In 2015, the total RPS obligation was 19.5 percent and will ultimately reach 27 percent in 2020.  CL&P is permitted to recover any costs incurred in complying with RPS from its customers through its GSC rate.

Massachusetts' RPS program also requires electricity suppliers to meet renewable energy standards.  For 2015, the requirement was 19.25 percent, and will ultimately reach 22.1 percent in 2020.  NSTAR Electric and WMECO are permitted to recover any costs incurred in complying with RPS from its customers through rates.  WMECO also owns renewable solar generation resources.  The RECs generated from WMECO's solar units are sold to other energy suppliers, and the proceeds from these sales are credited back to customers.

Hazardous Materials Regulations

We have recorded a liability for what we believe, based upon currently available information, is our reasonably estimable environmental investigation, remediation, and/or Natural Resource Damages costs for waste disposal sites for which we have probable liability.  Under federal and state law, government agencies and private parties can attempt to impose liability on us for recovery of investigation and remediation costs at hazardous waste sites.  As of December 31, 2015, the liability recorded for our reasonably estimable and probable environmental remediation costs for known sites needing investigation and/or remediation, exclusive of recoveries from insurance or from third parties, was approximately $51.1 million, representing 64 sites.  These costs could be significantly higher if additional remediation becomes necessary or when additional information as to the extent of contamination becomes available.

The most significant liabilities currently relate to future clean-up costs at former MGP facilities.  These facilities were owned and operated by our predecessor companies from the mid-1800's to mid-1900's.  By-products from the manufacture of gas using coal resulted in fuel oils, hydrocarbons, coal tar, purifier wastes, metals and other waste products that may pose risks to human health and the environment.  We currently have partial or full ownership responsibilities at former MGP sites that have a reserve balance of $45.5 million of the total $51.1 million as of December 31, 2015.  Many of these MGP costs are recoverable from customers through our rates.

Electric and Magnetic Fields  

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

In accordance with recommendations of various regulatory bodies and public health organizations, we reduce EMF associated with new transmission lines by the use of designs that can be implemented without additional cost or at a modest cost.  We do not believe that other capital expenditures are appropriate to minimize unsubstantiated risks.

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Global Climate Change and Greenhouse Gas Emission Issues

Global climate change and greenhouse gas emission issues have received an increased focus from state governments and the federal government.  The EPA initiated a rulemaking addressing greenhouse gas emissions and, on December 7, 2009, issued a finding that concluded that greenhouse gas emissions are "air pollution" that endangers public health and welfare and should be regulated.  The largest source of greenhouse gas emissions in the U.S. is the electricity generating sector.  The EPA has mandated greenhouse gas emission reporting beginning in 2011 for emissions for certain aspects of our business including stationary combustion, volume of gas supplied to large customers and fugitive emissions of SF ₆ gas and methane.

We are continually evaluating the regulatory risks and regulatory uncertainty presented by climate change concerns.  Such concerns could potentially lead to additional rules and regulations that impact how we operate our business, both in terms of the generating facilities we own and operate as well as general utility operations.  These could include federal "cap and trade" laws, carbon taxes, fuel and energy taxes, or regulations requiring additional capital expenditures at our generating facilities.  We expect that any costs of these rules and regulations would be recovered from customers.

Connecticut, New Hampshire and Massachusetts are each members of the Regional Greenhouse Gas Initiative (RGGI), a cooperative effort by nine northeastern and mid-Atlantic states, to develop a regional program for stabilizing and reducing CO ₂ emissions from coal- and oil-fired electric generating plants.  Because CO ₂ allowances issued by any participating state are usable across all nine RGGI state programs, the individual state CO ₂ trading programs, in the aggregate, form one regional compliance market for CO ₂ emissions.  The third three-year control period took effect on January 1, 2015 and extends through December 31, 2017.  In this control period, each regulated power plant must hold CO ₂ allowances equal to 50 percent of its emissions during each of the first two years of the three-year period, and hold CO ₂ allowances equal to 100 percent of its remaining emissions for the three-year control period at the end of the period.

PSNH anticipates that its generating units will emit between one million and three million tons of CO ₂ per year, depending on the capacity factor and the utilization of the respective generation plant, excluding emissions from the operation of PSNH's Northern Wood Power Project, which emissions are an offset.  PSNH satisfied its RGGI requirements by purchasing CO ₂ allowances at auction.  The cost of complying with RGGI requirements is recoverable from PSNH customers.  Current legislation provides that the portion of the RGGI auction proceeds in excess of $1 per allowance will be refunded to customers.

Because none of Eversource Energy's other subsidiaries, CL&P, NSTAR Electric or WMECO, currently owns any generating assets (other than WMECO's solar photovoltaic facilities that do not emit CO ₂ ), none of them is required to acquire CO ₂ allowances.  However, the CO ₂ allowance costs borne by the generating facilities that are utilized by wholesale energy suppliers to satisfy energy supply requirements to CL&P, NSTAR Electric and WMECO are likely to be included in the overall wholesale rates charged, which costs are then recoverable from customers.

FERC Hydroelectric Project Licensing

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

PSNH currently owns nine hydroelectric generating stations with a current claimed capability representing winter rates of approximately 71 MW, eight of which are licensed by the FERC under long-term licenses that expire on varying dates from 2017 through 2047.  PSNH and its hydroelectric projects are subject to conditions set forth in such licenses, the Federal Power Act and related FERC regulations, including provisions related to the condemnation of a project upon payment of just compensation, amortization of project investment from excess project earnings, possible takeover of a project after expiration of its license upon payment of net investment and severance damages and other matters.  PSNH is currently completing the relicensing application for its 6.5 MW Eastman Falls Hydro Station, the license for which expires in 2017.

EMPLOYEES

As of December 31, 2015, Eversource Energy employed a total of 7,943 employees, excluding temporary employees, of which 1,037 were employed by CL&P, 1,240 were employed by NSTAR Electric, 694 were employed by PSNH, and 291 were employed by WMECO.  Approximately 50 percent of our employees are members of the International Brotherhood of Electrical Workers, the Utility Workers Union of America or The United Steelworkers, and are covered by 14 collective bargaining agreements.

INTERNET INFORMATION

Our website address is www.eversource.com.  We make available through our website a link to the SEC's EDGAR website (http://www.sec.gov/edgar/searchedgar/companysearch.html), at which site Eversource Energy's, CL&P's, NSTAR Electric's, PSNH's and WMECO's Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to those reports may be reviewed.  Information contained on the Company's website or that can be accessed through the website is not incorporated into and does not constitute a part of this Annual Report on Form 10-K.  Printed copies of these reports may be obtained free of charge by writing to our Investor Relations Department at Eversource Energy, 107 Selden Street, Berlin, CT 06037.  

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Item 1A.

Risk Factors

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

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

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

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

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

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

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

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

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

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

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

Under state and federal law, our electric and gas companies are entitled to charge rates that are sufficient to allow them an opportunity to recover their reasonable operating and capital costs, to attract needed capital and maintain their financial integrity, while also protecting relevant public interests.  Each of these companies prepares and submits periodic rate filings with their respective regulatory commissions for review and approval.

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

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

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There is no assurance that the commissions will approve the recovery of all costs incurred by our electric and gas companies, including costs for construction, operation and maintenance, as well as a reasonable return on their respective regulated assets.  The amount of costs incurred by the companies, coupled with increases in fuel and energy prices, could lead to consumer or regulatory resistance to the timely recovery of such costs, thereby adversely affecting our financial position, results of operations or cash flows.

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

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

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

Our ability to properly operate our transmission, distribution and generation systems is critical to the financial performance of our business.  Our transmission, distribution and generation businesses face several operational risks, including the breakdown, failure of, or damage to operating equipment, information technology systems, or processes, especially due to age; labor disputes; disruptions in the delivery of electricity and natural gas, including impacts on us or our customers; increased capital expenditure requirements, including those due to environmental regulation; catastrophic events such as fires, explosions, or other similar occurrences; extreme weather conditions beyond equipment and plant design capacity; other unanticipated operations and maintenance expenses and liabilities; and potential claims for property damage or personal injuries beyond the scope of our insurance coverage.  Many of our transmission projects are expected to alleviate identified reliability issues and reduce customers' costs. However, if the in-service date for one or more of these projects is delayed due to economic events or factors, or regulatory or other delays, the risk of failures in the electricity transmission system may increase.  Any failure of our transmission, distribution and generation systems to operate as planned may result in increased capital costs, reduced earnings or unplanned increases in operation and maintenance costs.  Outages at generating stations may be deemed imprudent by the NHPUC resulting in disallowance of replacement power and repair costs.  Such costs that are not recoverable from our customers would have an adverse effect on our financial position, results of operations and cash flows.

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

Energy consumption is significantly impacted by the general level of economic activity and cost of energy supply.  Economic downturns or periods of high energy supply costs typically can lead to the development of legislative and regulatory policy designed to promote reductions in energy consumption and increased energy efficiency and self-generation by customers.  This focus on conservation, energy efficiency and self-generation may result in a decline in electricity and natural gas sales in our service territories.  Economic downturns or periods of high energy supply costs can also impact customers’ ability to pay their energy bills, resulting in increased bad debt expense.  If energy use were to decline or bad debt expense were to increase, without corresponding adjustments in rates at our electric and gas companies that do not currently have revenue decoupling, then our revenues would be reduced, which would have an adverse effect on our financial position, results of operations and cash flows.

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

Severe weather, such as ice and snow storms, hurricanes and other natural disasters, may cause outages and property damage, which may require us to incur additional costs that may not be recoverable from customers.  The cost of repairing damage to our operating subsidiaries' facilities and the potential disruption of their operations due to storms, natural disasters or other catastrophic events could be substantial, particularly as regulators and customers demand better and quicker response times to outages.  If, upon review, any of our state regulatory authorities finds that our actions were imprudent, some of those restoration costs may not be recoverable from customers.  The inability to recover a significant amount of such costs could have an adverse effect on our financial position, results of operations and cash flows.

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

We have a significant amount of goodwill on our consolidated balance sheet.  As of December 31, 2015, goodwill totaled $3.5 billion.  The carrying value of goodwill represents the fair value of an acquired business in excess of identifiable assets and liabilities as of the acquisition date.  We test our goodwill balances for impairment on an annual basis or whenever events occur or circumstances change that would indicate a potential for impairment.  A determination that goodwill is deemed to be impaired would result in a non-cash charge that could materially adversely affect our financial position, results of operations and total capitalization.  The annual goodwill impairment test in 2015 resulted in a conclusion that our goodwill is not impaired.

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

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

Limits on our access to and increases in the cost of capital may adversely impact our ability to execute our business plan.

We use short-term debt and the long-term capital markets as a significant source of liquidity and funding for capital requirements not obtained from our operating cash flow.  If access to these sources of liquidity becomes constrained, our ability to implement our business strategy could be adversely affected.  In addition, higher interest rates would increase our cost of borrowing, which could adversely impact our results of operations.  A downgrade of our credit ratings or events beyond our control, such as a disruption in global capital and credit markets, could increase our cost of borrowing and cost of capital or restrict our ability to access the capital markets and negatively affect our ability to maintain and to expand our businesses.

Our counterparties may not meet their obligations to us or may elect to exercise their termination rights, which could adversely affect our earnings.

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

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

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

The loss of key personnel or the inability to hire and retain qualified employees could have an adverse effect on our business, financial position and results of operations.

Our operations depend on the continued efforts of our employees.  Retaining key employees and maintaining the ability to attract new employees are important to both our operational and financial performance.  We cannot guarantee that any member of our management or any key employee at the Eversource parent or subsidiary level will continue to serve in any capacity for any particular period of time.  In addition, a significant portion of our workforce, including many workers with specialized skills maintaining and servicing the electrical infrastructure, will be eligible to retire over the next five to ten years.  Such highly skilled individuals cannot be quickly replaced due to the technically complex work they perform.  We have developed strategic workforce plans to identify key functions and proactively implement plans to assure a ready and qualified workforce, but cannot predict the impact of these plans on our ability to hire and retain key employees.

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

We provide a defined benefit pension plan and other postretirement benefits for a substantial number of employees, former employees and retirees.  Our future pension obligations, costs and liabilities are highly dependent on a variety of factors beyond our control.  These factors include estimated investment returns, interest rates, discount rates, health care cost trends, benefit changes, salary increases and the demographics of plan participants.  If our assumptions prove to be inaccurate, our future costs could increase significantly.   In addition, various factors, including underperformance of plan investments and changes in law or regulation, could increase the amount of contributions required to fund our pension plan in the future.  Additional large funding requirements, when combined with the financing requirements of our construction program, could impact the timing and amount of future financings and negatively affect our financial position, results of operations or cash flows.  For further information, see Note 9A, "Employee Benefits - Pensions and Postretirement Benefits Other Than Pensions," to the financial statements.

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Costs of compliance with environmental regulations, including climate change legislation, may increase and have an adverse effect on our business and results of operations.

Our subsidiaries' operations are subject to extensive federal, state and local environmental statutes, rules and regulations that govern, among other things, air emissions, water discharges and the management of hazardous and solid waste.  Compliance with these requirements requires us to incur significant costs relating to environmental monitoring, maintenance and upgrading of facilities, remediation and permitting.  The costs of compliance with existing legal requirements or legal requirements not yet adopted may increase in the future.  An increase in such costs, unless promptly recovered, could have an adverse impact on our business and our financial position, results of operations or cash flows.

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

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

Eversource parent is a holding company and as such, has no revenue-generating operations of its own.  Its ability to meet its debt service obligations and to pay dividends on its common shares is largely dependent on the ability of its subsidiaries to pay dividends to or repay borrowings from Eversource parent, and/or Eversource parent's ability to access its commercial paper program or the long-term debt and equity capital markets.  Prior to funding Eversource parent, the subsidiary companies have financial obligations that must be satisfied, including among others, their operating expenses, debt service, preferred dividends of certain subsidiaries, and obligations to trade creditors.  Additionally, the subsidiary companies could retain their free cash flow to fund their capital expenditures in lieu of receiving equity contributions from Eversource parent.  Should the subsidiary companies not be able to pay dividends or repay funds due to Eversource parent, or if Eversource parent cannot access its commercial paper programs or the long-term debt and equity capital markets, Eversource parent's ability to pay interest, dividends and its own debt obligations would be restricted.

Item 1B.