EVERSOURCE ENERGY (ES) Business, 2016

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

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

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

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

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

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

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

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

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

CL&P, NSTAR Electric, PSNH and WMECO are each doing business as Eversource Energy in their respective service territories.

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 results of PSNH and WMECO. These three segments represented substantially all of Eversource Energy's total consolidated revenues for the years ended December 31, 2016, 2015 and 2014. CL&P, NSTAR Electric, PSNH and WMECO do not report separate business segments.

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 assets of PSNH and WMECO.

The following table shows the sources of 2016 electric franchise retail revenues for Eversource Energy's electric distribution companies, collectively, based on categories of customers:

(Thousands of Dollars, except percentages) 2016 % of Total Residential $ 3,448,043 54 % Commercial 2,465,664 39 % Industrial 328,103 5 % Other 139,527 2 % Total Retail Electric Revenues $ 6,381,337 100 %

A summary of our distribution companies' retail electric GWh sales volumes and percentage changes for 2016, as compared to 2015, is as follows:

2016 2015 PercentageChange Residential 21,002 21,441 (2.0 )% Commercial 27,206 27,598 (1.4 )% Industrial 5,434 5,577 (2.6 )% Total 53,642 54,616 (1.8 )%

For 2016, retail electric sales volumes at our electric utilities with a traditional rate structure (NSTAR Electric and PSNH) were lower, as compared to 2015, due primarily to the impact of increased customer energy conservation efforts, including those resulting from company-sponsored energy efficiency programs. Fluctuations in retail electric sales volumes at NSTAR Electric and PSNH impact earnings as they operate under a traditional rate structure, where sales volume, impacted by weather, has a direct impact on revenue recognized.

For CL&P and WMECO, fluctuations in retail electric sales volumes do not impact earnings due to their respective regulatory commission approved distribution 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 of $1.059 billion and $132.4 million, respectively. Any difference between the allowed level of distribution revenue for CL&P and WMECO and the actual amount delivered during a 12-month period is adjusted through rates in the following period.

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, 2016, 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 2016 electric franchise retail revenues based on categories of customers:

CL&P (Thousands of Dollars, except percentages) 2016 % of Total Residential $ 1,603,351 61 Commercial 858,965 32 Industrial 139,556 5 Other 47,672 2 Total Retail Electric Revenues $ 2,649,544 100 %

A summary of CL&P's retail electric GWh sales volumes and percentage changes for 2016, as compared to 2015, is as follows:

2016 2015 PercentageChange Residential 9,907 10,094 (1.9 )% Commercial 9,461 9,635 (1.8 )% Industrial 2,249 2,342 (4.0 )% Total 21,617 22,071 (2.1 )%

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, renewable energy programs 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 purchased power to customers through a combined charge on customers' bills.

CL&P continues to supply approximately 42 percent of its customer load at SS or LRS rates while the other 58 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.

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

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

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

• A distribution charge, which includes a fixed customer charge and a demand and/or energy charge to collect the costs of building and expanding the infrastructure to deliver electricity to customers, as well as ongoing operating costs to maintain the infrastructure.

• An FMCC, which recovers any costs imposed by the FERC as part of the New England Standard Market Design, including locational marginal pricing, locational installed capacity payments, and any costs approved by the PURA to reduce these charges. The FMCC also recovers costs associated with CL&P's system resiliency program. The FMCC is adjusted periodically and reconciled semi-annually in accordance with the policies and procedures of the PURA, with any differences refunded to, or recovered from, customers.

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

• A CTA charge, 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.

• An SBC, established to fund expenses associated with various hardship and low income programs and a program that compensates municipalities for lost property tax revenues due to decreased values of generating facilities caused by electric industry restructuring. The SBC is reconciled annually to actual costs incurred and reviewed by the PURA, with any difference refunded to, or recovered from, customers.

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

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

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

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

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

• Long-term commitment to purchase 20 MW of solar power from a multi-site project in Connecticut. This project is expected to be operational by the end of 2017.

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 included 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.

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 70 percent of its SS loads for the first half of 2017 and has bilateral purchases in place to self-manage the remaining 30 percent. For the second half of 2017, CL&P has 50 percent of its SS load under full requirements contracts, and intends to purchase an additional 20 to 30 percent of full requirements and will self-manage the remainder as needed. None of the SS load for 2018 has been procured. CL&P has full requirements contracts in place for its LRS loads through the second quarter of 2017 and intends to purchase 100 percent of full requirements for the third and fourth quarters of 2017.

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, 2016, 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 210,000 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 currently sells all energy and other products from its solar generation facilities into the ISO-NE market. NSTAR Electric does not own any solar generation facilities. On December 29, 2016, the DPU approved the NSTAR Electric and WMECO application to develop 35 MW and 27 MW, respectively, of solar generation facilities, in addition to WMECO's existing 8 MW of solar generation facilities. We expect development of the facilities to be completed by the end of 2017. We expect that NSTAR Electric and WMECO will sell energy from the new solar generation facilities into the ISO-NE market. We estimate our investment in these new facilities will be between approximately $180 million to $200 million.

The following table shows the sources of the 2016 electric franchise retail revenues of NSTAR Electric and WMECO based on categories of customers:

NSTAR Electric WMECO (Thousands of Dollars, except percentages) 2016 % of Total 2016 % of Total Residential $ 1,097,093 45 $ 225,685 58 Commercial 1,190,597 49 120,146 31 Industrial 84,834 4 32,849 9 Other 46,756 2 7,910 2 Total Retail Electric Revenues $ 2,419,280 100 % $ 386,590 100 %

A summary of NSTAR Electric's and WMECO's retail electric GWh sales volumes and percentage changes for 2016, as compared to 2015, is as follows:

NSTAR Electric WMECO 2016 2015 PercentageChange 2016 2015 PercentageChange Residential 6,518 6,687 (2.5 )% 1,441 1,465 (1.6 )% Commercial 12,925 13,120 (1.5 )% 1,479 1,478 0.1 % Industrial 1,176 1,248 (5.8 )% 626 620 1.0 % Total 20,619 21,055 (2.1 )% 3,546 3,563 (0.5 )%

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.

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 31 percent of its customer load at basic service rates while the other 69 percent of its customer load has migrated to competitive energy suppliers. WMECO 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. Because customer migration is limited to energy supply service, it has no impact on the delivery business or operating income of NSTAR Electric and WMECO.

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

• A basic service charge that represents the collection of energy costs, including costs related to charge-offs of uncollectible energy costs from customers. Electric distribution companies in Massachusetts are required to obtain and resell power to retail customers through basic service for those who choose not to buy energy from a competitive energy supplier. Basic service rates are reset every six months (every three months for large commercial and industrial customers). Additionally, the DPU has authorized NSTAR Electric to recover the cost of its NSTAR Green wind contracts through the basic service charge. Basic service costs are reconciled annually, with any differences refunded to, or recovered from, customers.

• A distribution charge, which includes a fixed customer charge and a demand and/or energy charge to collect the costs of building and expanding the distribution infrastructure to deliver power to its destination, as well as ongoing operating costs.

• For WMECO, a revenue decoupling adjustment that reconciles distribution revenue, on an annual basis, to the amount of distribution revenue approved by the DPU in its last rate case in 2011. Currently, WMECO is allowed to collect $132.4 million annually.

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

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

• A renewable energy charge that represents a legislatively-mandated charge to support the Massachusetts Renewable Energy Trust Fund.

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

• Reconciling adjustment charges that recover certain DPU-approved costs as follows: pension and PBOP benefits, low income customer discounts, lost revenue and credits associated with net-metering facilities installed by customers, storms, consultants retained by the attorney general, long-term renewable contracts and energy efficiency programs and lost base revenue associated with energy efficiency measures. In addition to these adjustments common to both NSTAR Electric and WMECO, NSTAR Electric has reconciling adjustment charges that collect costs associated with certain safety and reliability projects. 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. One unit began operating in late 2015, and the other unit began operating in late 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 began operating 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 has proposed decoupling in its current rate case, which will occur in the second half of 2017, for rates effective January 1, 2018.

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 2016 performance as each company achieved results at or above target for all of its respective SQ metrics in 2016.

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.

Eversource has proposed to merge WMECO into NSTAR Electric with an anticipated effective date of January 1, 2018. On January 13, 2017, Eversource made two filings with FERC related to the proposed merger. One filing requests FERC approval of the merger, and the other filing requests FERC approval of NSTAR Electric's assumption of WMECO's short-term debt obligations. It is expected that FERC will act on these filings by mid-2017.

On January 17, 2017, NSTAR Electric and WMECO jointly filed an application with the DPU for approval of new base distribution rates, effective January 1, 2018. Among other things, the application proposes to streamline and align rate classifications between NSTAR Electric and WMECO, and request a revenue decoupling rate mechanism for NSTAR Electric. WMECO has a revenue decooffupling mechanism in place. For further information, see "Regulatory Developments and Rate Matters - Massachusetts - Distribution Rates" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.

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, 2016, PSNH furnished retail franchise electric service to approximately 511,000 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 assets.

The following table shows the sources of PSNH's 2016 electric franchise retail revenues based on categories of customers:

PSNH (Thousands of Dollars, except percentages) 2016 % of Total Residential $ 521,914 56 Commercial 295,956 32 Industrial 70,864 8 Other 37,188 4 Total Retail Electric Revenues $ 925,922 100 %

A summary of PSNH's retail electric GWh sales volumes and percentage changes for 2016, as compared to 2015, is as follows:

2016 2015 PercentageChange Residential 3,136 3,195 (1.8 )% Commercial 3,342 3,365 (0.7 )% Industrial 1,382 1,367 1.1 % Total 7,860 7,927 (0.8 )%

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 2016, approximately 25 percent of all of PSNH's customers (approximately 56 percent of load) were taking service from competitive energy suppliers, compared to 21 percent of customers (approximately 53 percent of load) at the end of 2015.

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

• A default energy service charge which recovers energy-related costs incurred as a result of providing electric generation service supply to all customers that have not migrated to competitive energy suppliers. These charges recover the costs of PSNH's generation, as well as purchased power, and include an allowed ROE of 9.81 percent.

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

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

• An 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.

• An SBC, which funds energy efficiency programs for all customers, as well as assistance programs for residential customers within certain income guidelines.

• An electricity consumption tax, which is a state mandated tax on 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. As part of the 2015 settlement over the cost of the pollution-control equipment at PSNH's Merrimack facility, and the ability of PSNH to divest itself of its generation assets (as further described under "Generation Divestiture," below), PSNH 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.

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. Under the terms of the Agreement, PSNH agreed to divest its generation assets, subject to NHPUC approval. The Agreement provided for 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 agreed to forego recovery of $25 million of the equity return related to the Clean Air Project. In addition, PSNH will not seek a general distribution rate increase effective before July 1, 2017 and will contribute $5 million to create a clean energy fund, which will not be recoverable from its customers. In 2015, PSNH recorded the $5 million contribution as a long-term liability on the balance sheet and an increase to Operations and Maintenance expense on the statement of income.

On July 1, 2016, the NHPUC approved the Agreement in an order that, among other things, instructs PSNH to begin the process to divest its generation assets. The NHPUC selected an auction adviser to assist with the divestiture, and a final plan and auction process was approved by the NHPUC in November 2016. In December 2016, certain intervenors asked the NHPUC to reconsider certain aspects of its divestiture plan; the NHPUC rejected that request on December 23, 2016. On January 10, 2017, these intervenors appealed the NHPUC's decision to the New Hampshire Supreme Court, alleging procedural deficiencies, and complaining that the auction schedule and process were unreasonable. PSNH and the New Hampshire Attorney General's office acting on behalf of the NHPUC requested the Court to reject this appeal. On February 10, 2017, the New Hampshire Supreme Court issued an order declining to accept the appeal. We continue to believe the assets will be sold by the end of 2017.

As of December 31, 2016, PSNH's energy service rate base subject to divestiture, was approximately $625 million. This rate base will be reduced by the amount of the sales proceeds from the generation assets that are divested and sold. Upon completion of the divestiture process, full recovery of PSNH's generation assets is probable through a combination of cash flows during the remaining operating period, sales proceeds upon divestiture, and recovery of stranded costs via bonds that will be secured by a non-bypassable charge or through recoveries in future rates billed to PSNH's customers. For further information, see "Regulatory Developments and Rate Matters - New Hampshire - Generation Divestiture" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.

During 2016, approximately 48 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 52 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 2017 in a similar manner. Included in the 48 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 historical capacity factors due to moderate regional temperatures. The Hydro stations' annual generation was lower than average due to low river flows. PSNH's Energy Service Rate has been set at 11.17 cents per kWh effective January 1, 2017, which includes full recovery of costs related to the Clean Air Project.

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.

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

(Thousands of Dollars) 2016 CL&P $ 575,735 NSTAR Electric 337,947 PSNH 151,354 WMECO 145,103 Total Wholesale Transmission Revenues $ 1,210,139

Wholesale transmission revenues are recovered through FERC approved formula rates. Transmission revenues are collected from New England customers, including 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.

Four separate complaints have been filed at FERC by combinations of New England state attorneys general, state regulatory commissions, consumer advocates, consumer groups, municipal parties and other parties. Each complaint challenges the NETOs' previous base ROE of 11.14 percent or current base ROE of 10.57 percent and seeks to reduce it both for the four separate 15-month complaint periods and prospectively. 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.

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, to allow for competition. ISO-NE and the NETOs, including CL&P, NSTAR Electric, PSNH and WMECO made compliance filings to address this policy, which included exemption from competition for certain transmission solutions previously evaluated by ISO-NE, and the NETOs' rights to retain use and control of existing right of ways. This compliance was accepted by the FERC on December 14, 2015. At the same time, the NETOs filed an appeal to the D.C. Circuit Court of Appeals, challenging FERC's removal of the right of first refusal. State regulators have also filed an appeal, challenging the FERC's

determination that ISO-NE should select public policy transmission projects after a competitive process. Oral arguments were heard by the Court on January 13, 2017, and the Court is expected to resolve the appeals in 2017.

During 2016, we were involved in the planning, development and construction of a series of electric transmission projects, including the Greater Hartford Central Connecticut 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 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 Seacoast Reliability Project, a transmission line within several New Hampshire communities, which proposes to use a combination of overhead, underground and underwater line design to help meet the growing demand for electricity in the Seacoast region. 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.

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 2016, our estimated transmission rate base was approximately $5.7 billion, including approximately $2.5 billion at CL&P, $1.5 billion at NSTAR Electric, $698 million at PSNH, and $722 million at WMECO.

NSTAR Gas distributes natural gas to approximately 289,000 customers in 51 communities in central and eastern Massachusetts covering 1,067 square miles, and Yankee Gas distributes natural gas to approximately 229,000 customers in 72 cities and towns in Connecticut covering 2,187 square miles. Total throughput (sales and transportation) in 2016 was approximately 63,186 MMBtu for NSTAR Gas and 55,679 MMBtu 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 natural 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 2016 total Eversource Energy natural gas franchise retail revenues based on categories of customers:

(Thousands of Dollars, except percentages) 2016 % of Total Residential $ 446,052 55 Commercial 279,001 35 Industrial 80,093 10 Total Retail Natural Gas Revenues $ 805,146 100 %

A summary of our firm natural gas sales volumes in million cubic feet and percentage changes for 2016, as compared to 2015, is as follows:

2016 2015 PercentageChange Residential 35,734 38,455 (7.1 )% Commercial 41,895 43,006 (2.6 )% Industrial 20,413 21,538 (5.2 )% Total 98,042 102,999 (4.8 )% Total, Net of Special Contracts (1) 93,346 98,458 (5.2 )%

(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 2016, our consolidated firm natural gas sales volumes were lower, as compared to 2015. The 2016 firm natural gas sales volumes were negatively impacted by warmer than normal weather in the first quarter of 2016, as compared to the much colder than normal temperatures in the first quarter of 2015, throughout our natural gas service territories. Heating degree days for 2016 were five percent lower in Connecticut, as compared to 2015.

For NSTAR Gas, the DPU approved a distribution revenue decoupling mechanism effective January 1, 2016. Natural gas distribution revenues are decoupled from their customer sales volumes, where applicable, which breaks the relationship between sales volumes and revenues recognized. As a result, fluctuations in natural gas sales volumes in Massachusetts do not impact earnings.

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.

• 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 the New York Mercantile Exchange ("NYMEX") natural gas futures in order to reduce cash flow variability associated with the purchase price for approximately one-third of its normal winter season natural gas supplies. 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 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 2016 performance as it achieved results at or above target for all of its SQ metrics in 2016.

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, which motion remains pending.

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. As of December 31, 2016, Yankee Gas had not triggered any of the earnings sharing thresholds.

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 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.

In 2013, in accordance with Connecticut law and regulations, the PURA approved a comprehensive joint natural gas infrastructure expansion plan (the "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 Expansion 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 November 30, 2016, Yankee Gas received PURA approval of its initial 2014 System Expansion Reconciliation as well as its 2015 Reconciliation after a combined review of the reconciliations by PURA. The PURA approval allowed for the recovery of the 2014 and 2015 combined deficiency balance of $3.65 million.

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.

Access Northeast is a natural gas pipeline and storage project being developed jointly by Eversource, Spectra Energy Partners, LP and National Grid plc, through Algonquin Gas Transmission, LLC. Access Northeast is expected to enhance the Algonquin and Maritimes & Northeast pipeline systems using existing routes and is expected to include two new LNG storage tanks and liquefaction and vaporization facilities in Acushnet, Massachusetts that are currently expected to be connected to the Algonquin natural gas pipeline. For further information, see "Business Development and Capital Expenditures – Access Northeast" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.

Bay State Wind is a proposed off-shore wind project being jointly developed by Eversource and Denmark-based DONG Energy. Bay State Wind will be located in a 300-square-mile area approximately 15 to 25 miles south of Martha's Vineyard that has the ultimate potential to generate at least 2,000 MW of wind power energy. Both Eversource and DONG Energy have a 50 percent ownership interest in Bay State Wind. In August 2016, Massachusetts passed clean energy legislation that requires EDCs to jointly solicit RFPs and enter into long-term contracts for off-shore wind, creating contracting opportunities for projects like Bay State Wind. The initial RFP is due to be released by June 30, 2017 and Bay State Wind will be bid into that RFP.

We project to make capital expenditures of approximately $9.6 billion from 2017 through 2020, of which we expect approximately $5.3 billion to be in our electric and natural gas distribution segments and approximately $3.9 billion to be in our electric transmission segment. We also project to invest approximately $0.4 billion in information technology and facilities upgrades and enhancements. These projections do not include any expected investments related to either Access Northeast or Bay State Wind.

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, 2016, a total of $745 million of Eversource's long-term debt is classified as current liabilities, $250 million, $400 million, $70 million and $25 million for CL&P, NSTAR Electric, PSNH and NSTAR Gas, respectively, and will be paid in the next 12 months.

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 – Spent Nuclear Fuel Obligations – Yankee Companies," in the accompanying Item 8, Financial Statements and Supplementary Data.

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.

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.

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.

The Clean Air Act Amendments ("CAAA"), as well as New Hampshire law, impose stringent requirements on emissions of SO2 and NOX 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. The Clean Air Project at our Merrimack Station, together with existing equipment, has enabled the facility to meet the MATS requirements. In 2016, additional controls were also installed at the two coal-fired units at Schiller Station.

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 2016, the total RPS obligation was 9.0 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 2016, the total RPS obligation was 21.0 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 2016, the requirement was 21.03 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.

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, 2016, 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 $65.8 million, representing 61 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 $59.0 million of the total $65.8 million as of December 31, 2016. MGP costs are recoverable through rates charged to our customers.

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

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

Global climate change and greenhouse gas emission issues have received an increased focus from state governments and the federal government. The EPA initiated a rulemaking addressing greenhouse gas emissions and, on December 7, 2009, issued a finding that concluded that greenhouse gas emissions are "air pollution" that endangers public health and welfare and should be regulated. The largest source of greenhouse gas emissions in the U.S. is the electricity generating sector. The EPA has mandated greenhouse gas emission reporting beginning in 2011 for emissions for certain aspects of our business including stationary combustion, volume of gas supplied to large customers and fugitive emissions of SF6 gas and methane.

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

Connecticut, New Hampshire and Massachusetts are each members of the Regional Greenhouse Gas Initiative (RGGI), a cooperative effort by nine northeastern and mid-Atlantic states, to develop a regional program for stabilizing and reducing CO2 emissions from coal- and oil-fired electric generating plants. Because CO2 allowances issued by any participating state are usable across all nine RGGI state programs, the individual state CO2 trading programs, in the aggregate, form one regional compliance market for CO2 emissions. The third three-year control period took effect on January 1, 2015 and extends through December 31, 2017. In this control period, each regulated power plant must hold CO2 allowances equal to 50 percent of its emissions during each of the first two years of the three-year period, and hold CO2 allowances equal to 100 percent of its remaining emissions for the three-year control period at the end of the period.

PSNH anticipates that its generating units will emit between one million and three million tons of CO2 per year, depending on the capacity factor and the utilization of the respective generation plant, excluding emissions from the operation of PSNH's Northern Wood Power Project, which emissions are an offset. PSNH satisfied its RGGI requirements by purchasing CO2 allowances at auction. The cost of complying with RGGI requirements is recoverable from PSNH customers. Current legislation provides that the portion of the RGGI auction proceeds in excess of $1 per allowance will be refunded to customers.

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

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.

As of December 31, 2016, Eversource Energy employed a total of 7,762 employees, excluding temporary employees, of which 1,258 were employed by CL&P, 1,627 were employed by NSTAR Electric, 928 were employed by PSNH, and 297 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 11 collective bargaining agreements.

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.