Item 1. Business

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

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

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

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

•	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;

•	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.

•	Aquarion Water Company (Aquarion), a regulated water utility holding company that serves residential, commercial, industrial and fire protection customers through its separate three regulated utilities, AWC-CT, AWC-MA and AWC-NH in parts of Connecticut, Massachusetts and New Hampshire;

CL&P, NSTAR Electric and PSNH also serve New England customers through Eversource Energy's electric transmission business, and are each doing business as Eversource Energy in their respective service territories.

On December 31, 2017, Western Massachusetts Electric Company, a former subsidiary of Eversource Energy, merged with and into NSTAR Electric, with NSTAR Electric as the surviving entity. As a result, NSTAR Electric serves all of Eversource Energy’s electric customers in Massachusetts. For purposes of this combined Annual Report on Form 10-K, the financial statements and financial information presented for prior years were retrospectively adjusted as if the merger had occurred on the first day of the earliest period presented. Upon the closing of the merger, all assets, contracts, rights and obligations of Western Massachusetts Electric Company were reflected as part of NSTAR Electric.

On December 4, 2017, Eversource acquired Macquarie Utilities Inc., subsequently renamed Eversource Aquarion Holdings, Inc., and its Aquarion Water Company subsidiaries. Collectively, these water utility companies serve residential, commercial, industrial and fire protection customers in parts of Connecticut, Massachusetts and New Hampshire.

Eversource Energy, CL&P, NSTAR Electric and PSNH 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 results of PSNH's generation facilities and NSTAR Electric's solar power facilities. The energy transmission and distribution segments represented substantially all of Eversource Energy's total consolidated revenues for the years ended December 31, 2017, 2016 and 2015. CL&P, NSTAR Electric and PSNH 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 and PSNH, which are engaged in the distribution of electricity to retail customers in Connecticut, Massachusetts and New Hampshire, respectively, plus the regulated electric generation facilities of PSNH and solar power facilities of NSTAR Electric.

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

(Thousands of Dollars)	2017				2016				2015
Residential	$	3,457,986			$	3,448,043			$	3,608,155
Commercial	2,459,985				2,465,664				2,476,686
Industrial	330,995				328,103				326,564
Other	94,091				139,527				151,195
Total Retail Electric Revenues	$	6,343,057			$	6,381,337			$	6,562,600

A summary of our distribution companies' retail electric GWh sales volumes and percentage changes for 2017, as compared to 2016, is as follows:

	2017			2016			Percentage Change
Residential	20,496			21,002			(2.4	)%
Commercial	26,570			27,206			(2.3	)%
Industrial	5,180			5,434			(4.7	)%
Total	52,246			53,642			(2.6	)%

Certain Eversource electric, natural gas and water companies, including CL&P and NSTAR Electric (for a portion of its customers), have a regulatory commission approved revenue decoupling mechanism ("decoupled companies"). Distribution revenues are decoupled from customer sales volumes, where applicable, which breaks the relationship between sales volumes and revenues recognized. The decoupled companies reconcile their annual base distribution rate recovery to pre-established levels of baseline distribution delivery service revenues. Any difference between the allowed level of distribution revenue and the actual amount realized is adjusted through rates in a subsequent period.

Retail electric sales volumes at our electric utilities with a traditional rate structure (the eastern region of NSTAR Electric and PSNH) were lower in 2017, as compared to 2016, due primarily to the mild summer weather in 2017, as compared to 2016. Cooling degree days in 2017 were 14.7 percent lower in the Boston metropolitan area and 22.7 percent lower in New Hampshire, as compared to 2016. Sales volumes were positively impacted by improved economic conditions across our service territories, but this trend was offset by lower customer usage driven by the impact of increased customer energy conservation efforts.

CL&P and NSTAR Electric (for its western Massachusetts customer rates) reconcile their annual base distribution rate recovery amounts to their pre-established levels of baseline distribution delivery service revenues of $1.059 billion and $132.4 million, respectively, through December 31, 2017. Effective February 1, 2018, NSTAR Electric, operating entirely under decoupled rates, will reconcile its annual base distribution rate recovery to its new baseline of $974.8 million.

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, 2017, 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 electric franchise retail revenues based on categories of customers:

	CL&P
(Thousands of Dollars)	2017				2016				2015
Residential	$	1,649,294			$	1,603,351			$	1,641,165
Commercial	883,904				858,965				841,093
Industrial	144,672				139,556				129,544
Other	29,144				47,672				62,704
Total Retail Electric Revenues	$	2,707,014			$	2,649,544			$	2,674,506

A summary of CL&P's retail electric GWh sales volumes and percentage changes for 2017, as compared to 2016, is as follows:

	2017			2016			Percentage Change
Residential	9,642			9,907			(2.7	)%
Commercial	9,161			9,461			(3.2	)%
Industrial	2,146			2,249			(4.6	)%
Total	20,949			21,617			(3.1	)%

Rates

CL&P is subject to regulation by the PURA, which, among other things, has jurisdiction over rates, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, standards of service and construction and operation of facilities. CL&P's present general rate structure consists of various rate and service classifications covering residential, commercial and industrial services. CL&P's retail rates include a delivery service component, which includes distribution, transmission, conservation, renewable energy programs and other charges that are assessed on all customers.

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 (residential customers and small and medium commercial and industrial customers), and LRS rates for customers with 500 kilowatts or more of demand (larger commercial and industrial customers), 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.

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 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).

Distribution Rates: On April 20, 2017, PURA approved the joint request of CL&P, the Connecticut Office of Consumer Counsel ("OCC") and the Connecticut Attorney General to amend the deadline to establish new electric distribution rates in the 2012 Connecticut merger settlement agreement from "no later than December 1, 2017" to "no later than July 1, 2018." On November 22, 2017, CL&P filed its application with PURA, which sought a rate increase of $255.8 million, $45.0 million and $36.0 million effective May 2018, 2019, and 2020, respectively. On December 15, 2017, CL&P, the Prosecutorial Unit of PURA, and the OCC reached a settlement in principle.

On January 11, 2018, CL&P filed the distribution rate case settlement agreement for approval by PURA, which included, among other things, rate increases of $97.1 million, $32.7 million and $24.7 million, effective May 1, 2018, 2019, and 2020, respectively, an authorized regulatory ROE of 9.25 percent, 53 percent common equity in CL&P's capital structure, and a new capital tracker through 2020 for capital additions, system resiliency, and grid modernization. The rate increases associated with the settlement agreement will be reduced by the impact of the decrease in the federal corporate income tax rate, as part of the "Tax Cuts and Jobs Act", which we currently estimate to average approximately $45 million to $50 million per year, while amounts related to ADIT will be addressed in a separate manner. We expect to receive final approval from PURA in the second quarter of 2018.

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 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.

CL&P periodically enters into full requirements contracts for SS loads for periods of up to one year. CL&P typically enters into full requirements contracts for LRS loads every three months. Currently, CL&P has full requirements contracts in place for 100 percent of its SS loads for the first half of 2018. For the second half of 2018, CL&P has 60 percent of its SS load under full requirements contracts, and intends to purchase an additional 40 percent of full requirements. None of the SS load for 2019 has been procured. CL&P has full requirements contracts in place for its LRS loads through June 2018 and intends to purchase 100 percent of full requirements for the remainder of 2018.

ELECTRIC DISTRIBUTION – MASSACHUSETTS

NSTAR ELECTRIC COMPANY

NSTAR Electric's distribution business consists primarily of the purchase, delivery and sale of electricity to residential, commercial and industrial customers within its franchise service territory. As of December 31, 2017, NSTAR Electric furnished retail franchise electric service to approximately 1.4 million customers in Boston and 139 cities and towns in eastern and western Massachusetts, including Cape Cod, Martha's Vineyard and the greater Springfield metropolitan area, covering an aggregate area of approximately 3,200 square miles. NSTAR Electric does not own any generating facilities used to supply customers and purchases its energy requirements from competitive energy suppliers.

On December 29, 2016, the DPU approved NSTAR Electric's application to develop 62 MW of new solar power facilities. Currently, NSTAR Electric owns 8 MW of solar power facilities on sites in Pittsfield, Springfield, and East Springfield, Massachusetts that were completed from 2010 through 2014. We expect development of the new facilities to be completed in 2018. Similar to NSTAR Electric’s current practice on the existing 8MW of solar power facilities, we expect that NSTAR Electric will sell energy from the new facilities into the ISO-NE market. We estimate our investment in these new facilities will be approximately $180 million.

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

	NSTAR Electric
(Thousands of Dollars)	2017				2016				2015
Residential	$	1,271,253			$	1,322,778			$	1,461,184
Commercial	1,278,739				1,310,743				1,322,674
Industrial	113,952				117,683				120,106
Other	45,347				54,666				53,388
Total Retail Electric Revenues	$	2,709,291			$	2,805,870			$	2,957,352

A summary of NSTAR Electric's retail electric GWh sales volumes and percentage changes for 2017, as compared to 2016, is as follows:

	NSTAR Electric
	2017			2016			Percentage Change
Residential	7,721			7,959			(3.0	)%
Commercial	14,127			14,404			(1.9	)%
Industrial	1,691			1,802			(6.2	)%
Total	23,539			24,165			(2.6	)%

In 2017 and 2016, NSTAR Electric operated under two different rate structures based on its service territory geography. For customers in eastern Massachusetts, including metropolitan Boston, Cape Cod and Martha's Vineyard, NSTAR Electric operated using Traditional rates. For customers in western Massachusetts, including the metropolitan Springfield region, NSTAR Electric operated using Decoupled rates. Effective February 1, 2018, all of NSTAR Electric's distribution revenues were decoupled as a result of the DPU-approved rate decision. See "Regulatory Developments and Rate Matters - Massachusetts - NSTAR Electric Distribution Rate Case Decision" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.

Rates

NSTAR Electric is 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 NSTAR Electric consists of various rate and service classifications covering residential, commercial and industrial services.

Under Massachusetts law, all customers of NSTAR Electric are entitled to choose their energy suppliers, while NSTAR Electric remains their electric distribution company. NSTAR Electric purchases power from competitive suppliers on behalf of, and passes the related cost through to, its customers who do not choose a competitive energy supplier (basic service). Most of the residential customers of NSTAR Electric have continued to buy their power from NSTAR Electric 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 50 percent of its Residential customer load, 41 percent of its Small Commercial and Industrial (C&I) customer load, and 9 percent of its Large C&I customer load at basic service rates. The remainder of its customer load is distributed between Municipal Aggregation and Competitive Supply. Because customer migration is limited to energy supply service, it has no impact on the delivery business or operating income of NSTAR Electric.

The rates established by the DPU for NSTAR Electric 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.

•	A revenue decoupling adjustment that reconciles distribution revenue, on an annual basis, to the amount of distribution revenue approved by the DPU. During 2017 only the western Massachusetts customer rates, including the metropolitan Springfield region,

were decoupled, which resulted in allowed distribution revenues of approximately $132.4 million. Effective February 1, 2018, NSTAR Electric is allowed to collect distribution revenues of $974.8 million annually, which covers its entire service territory.

•	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, including pension and PBOP benefits, low income customer discounts, lost revenue and credits associated with net-metering facilities installed by customers, costs associated with the solar power facilities, storms, long-term renewable contracts and energy efficiency programs.

As required by regulation, NSTAR Electric, 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 wind farm began operating in late 2015, and the other wind farm began operating in late 2016. In addition, NSTAR Electric 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.

Distribution Rates: On November 30, 2017, the DPU issued its decision in the NSTAR Electric distribution rate case, which approved an annual distribution rate increase of $37 million, with rates effective February 1, 2018. On January 3, 2018, NSTAR Electric filed a motion to reflect a revenue requirement reduction of $56 million (due to the decrease in the federal corporate income tax rate, as part of the "Tax Cuts and Jobs Act"), resulting in an annual net decrease in rates of $19 million.

In addition to its decision regarding rates, the DPU approved an authorized regulatory ROE of 10 percent, the establishment of a revenue decoupling rate mechanism for the portion of the NSTAR Electric business that did not previously have a decoupling mechanism, and the implementation of an inflation-based adjustment mechanism with a five-year stay-out until January 1, 2023.

Among other items, the DPU approved the recovery of previously expensed merger-related costs over a 10-year period and the recovery of previously deferred storm costs with carrying charges at the prime rate, but disallowed certain property taxes. The rate case decision resulted in the recognition of an aggregate $44.1 million pre-tax benefit recorded in 2017.

Service Quality Metrics: NSTAR Electric 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 transmission and distribution revenues for failing to meet such metrics. NSTAR Electric will not be required to pay a SQ charge for its 2017 performance as the company achieved results at or above target for all of its SQ metrics in 2017.

Sources and Availability of Electric Power Supply

As noted above, NSTAR Electric does not own any generation assets (other than solar power facilities), and it purchases its energy requirements from a variety of competitive sources through requests for proposals issued periodically, consistent with DPU regulations. NSTAR Electric enters into supply contracts for basic service for 50 percent of its residential and small commercial and industrial customers twice per year for twelve month terms. NSTAR Electric enters into supply contracts for basic service for 100 percent of large commercial and industrial customers every three months.

ELECTRIC DISTRIBUTION – NEW HAMPSHIRE

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE

PSNH's distribution business consists primarily of the generation, delivery and sale of electricity to its residential, commercial and industrial customers. As of December 31, 2017, PSNH furnished retail franchise electric service to approximately 515,000 retail customers in 211 cities and towns in New Hampshire, covering an area of approximately 5,630 square miles. As of December 31, 2017, PSNH owned and operated approximately 1,200 MW of coal-, natural gas-, oil-fired, and hydro electricity generation facilities. PSNH's distribution business included the activities of its generation facilities.

On October 11, 2017, PSNH entered into a Purchase and Sale Agreement for the sale of its thermal generation facilities and a separate Purchase and Sale Agreement for the sale of its hydroelectric generation facilities. On January 10, 2018, PSNH completed the sale of its thermal generation facilities. The thermal generation facilities included approximately 1,100 MW of coal, natural gas, biomass and oil-fired electricity generation facilities. The sale of the hydroelectric generation facilities is targeted to close by the end of the first quarter of 2018. For further information, see "Generation Divestiture" below.

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

	PSNH
(Thousands of Dollars)	2017				2016				2015
Residential	$	537,439			$	521,914			$	505,806
Commercial	297,342				295,956				312,918
Industrial	72,371				70,864				76,914
Other	19,600				37,188				35,103
Total Retail Electric Revenues	$	926,752			$	925,922			$	930,741

A summary of PSNH's retail electric GWh sales volumes and percentage changes for 2017, as compared to 2016, is as follows:

	2017			2016			Percentage Change
Residential	3,134			3,136			(0.1	)%
Commercial	3,282			3,342			(1.8	)%
Industrial	1,342			1,382			(2.9	)%
Total	7,758			7,860			(1.3	)%

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.

Under New Hampshire law, all of PSNH's customers are entitled to choose competitive energy suppliers. Prior to the Generation Divestiture, PSNH provided default energy service under its ES rate for those customers who did not choose a competitive energy supplier. At the end of 2017, approximately 26 percent of all of PSNH's customers (approximately 56 percent of load) were taking service from competitive energy suppliers, compared to 25 percent of customers (approximately 56 percent of load) at the end of 2016.

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. Through March 31, 2018, the default energy service charge recovers the costs of PSNH's generation, as well as purchased power, and includes an allowed ROE of 9.81 percent. Effective April 1, 2018, as a result of the divestiture of its generation assets, PSNH will obtain power for retail customers who have not chosen a competitive supplier through a periodic market solicitation with the rate set to recover the cost of that power and statutorily mandated renewable portfolio standard costs. Effective April 1, 2018, any remaining costs from ownership of generation will be recovered as part of the SCRC described below.

•

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. The stranded costs associated with the sale of the generation facilities, which are targeted to be sold in their entirety by the end of the first quarter of 2018, will be recovered in the SCRC rate charged to PSNH customers.

•	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 default energy service charge and SCRC rates change semi-annually and are reconciled annually in accordance with the policies and procedures of the NHPUC, with any differences refunded to, or recovered from, customers.

In New Hampshire, PSNH distribution rates were established in a settlement approved by the NHPUC in 2010. Prior to the expiration of that settlement on June 30, 2015, the NHPUC approved the continuation of those rates, and increased funding via rates, of PSNH's reliability enhancement program.

Generation Divestiture

In June 2015, Eversource and PSNH entered into the 2015 Public Service Company of New Hampshire Restructuring and Rate Stabilization Agreement, under the terms of which PSNH agreed to divest its generation assets, subject to NHPUC approval. The NHPUC approval for this agreement, as well as NHPUC approval of the final divestiture plan and auction process, were received in the second half of 2016. In October 2017, PSNH entered into two Purchase and Sale Agreements ("Agreements") to sell its thermal and hydroelectric generation assets to private investors at purchase prices of $175 million and $83 million, respectively, subject to adjustments as set forth in the Agreements. The NHPUC approved the Agreements in late November 2017.

On January 10, 2018, PSNH completed the sale of its thermal generation facilities. In accordance with the Purchase and Sale Agreement, the original purchase price of $175 million was adjusted to reflect working capital adjustments, closing date adjustments and proration of taxes and fees prior to closing, totaling $40.9 million, resulting in net proceeds of $134.1 million. We are targeting for PSNH to complete the sale of its hydroelectric generation facilities by the end of the first quarter of 2018 at a sale price of $83 million, subject to adjustment. On January 30, 2018, the NHPUC approved the issuance of rate reduction bonds up to $690 million to recover stranded costs, subject to an audit by the NHPUC Audit Staff. This order is subject to an appeal period of 30 days.

Upon completion of the divestiture, full recovery of PSNH's generation assets and transaction-related costs are expected to occur through a combination of cash flows during the remaining operating period, sales proceeds, and recovery of stranded costs via the issuance of bonds that will be secured by a non-bypassable charge or through recoveries in future rates billed to PSNH's customers.

Sources and Availability of Electric Power Supply

During 2017, approximately 47 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 53 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. Included in the 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. With the anticipated completion of the divestiture of its own generation facilities in the first quarter of 2018, PSNH will meet its load requirements in 2018 with purchases of energy requirements from competitive sources through requests for proposals issued periodically, consistent with NHPUC regulations.

ELECTRIC TRANSMISSION SEGMENT

General

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

Wholesale Transmission Revenues

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

(Thousands of Dollars)	2017				2016				2015
CL&P	$	609,880			$	575,735			$	513,025
NSTAR Electric	514,151				483,050				428,743
PSNH	177,821				151,354				127,509
Total Wholesale Transmission Revenues	$	1,301,852			$	1,210,139			$	1,069,277

Wholesale Transmission Rates

Wholesale transmission revenues are recovered through FERC-approved formula rates. Annual transmission revenue requirements include recovery of transmission costs and include a return on equity applied to transmission rate base. Transmission revenues are collected from New England customers, including distribution customers of CL&P, NSTAR Electric and PSNH. The transmission rates provide for an annual true-up 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

Four 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 (collectively the "Complainants"). In each of the first three

complaints, the Complainants challenged the NETOs' base ROE of 11.14 percent that had been utilized since 2005, and sought an order to reduce

it prospectively from the date of the final FERC order and for the 15-month complaint periods arising from the separate complaints. In the

fourth complaint, the Complainants challenged the NETOs' base ROE of 10.57 percent and the maximum ROE for transmission incentive ("incentive cap") of 11.74 percent, asserting that these ROEs were unjust and unreasonable. In response to appeals of the FERC decision in the first complaint filed by the NETOs and the Complainants, the D.C. Circuit Court of Appeals issued a decision on April 14, 2017 vacating and remanding the FERC's decision. 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.

Transmission Projects

During 2017, we were involved in the planning, development and construction of a series of electric transmission projects, including the Greater Hartford Central Connecticut projects and the Greater Boston Reliability Solutions, that will be built within the next five years and that will enhance system reliability and improve capacity. We were also involved in the planning and development of Northern Pass and the Seacoast Reliability Project. On February 1, 2018, the New Hampshire Site Evaluation Committee ("NHSEC") voted to deny Northern Pass’ siting application. Consistent with Eversource’s and HQ’s long-term relationship to bring clean energy into New England, Eversource and HQ continue to support Northern Pass and the many benefits this project will bring to our customers and region. Eversource intends to seek reconsideration of the NHSEC’s decision and to review all options for moving this critical clean energy project forward. 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

Transmission rate base under our FERC-approved tariff primarily consists of our investment in transmission net utility plant less accumulated deferred income taxes.

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 2017, our estimated transmission rate base was approximately $6 billion, including approximately $2.7 billion at CL&P, $2.5 billion at NSTAR Electric, and $765 million at PSNH.

NATURAL GAS DISTRIBUTION SEGMENT

NSTAR Gas distributes natural gas to approximately 292,000 customers in 51 communities in central and eastern Massachusetts covering 1,067 square miles, and Yankee Gas distributes natural gas to approximately 232,000 customers in 72 cities and towns in Connecticut covering 2,187 square miles. Total throughput (sales and transportation) in 2017 was approximately 69.4 Bcf for NSTAR Gas and 56.0 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 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 total Eversource Energy natural gas franchise retail revenues based on categories of customers:

(Thousands of Dollars)	2017				2016				2015
Residential	$	500,229			$	446,052			$	497,873
Commercial	312,034				279,001				327,439
Industrial	90,024				80,093				93,378
Total Retail Natural Gas Revenues	$	902,287			$	805,146			$	918,690

A summary of our firm natural gas sales volumes in million cubic feet and percentage changes for 2017, as compared to 2016, is as follows:

	2017			2016			Percentage Change
Residential	37,421			35,734			4.7	%
Commercial	42,992			41,895			2.6	%
Industrial	20,613			20,413			1.0	%
Total	101,026			98,042			3.0	%
Total, Net of Special Contracts (1)	96,617			93,346			3.5	%

(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. Consolidated firm natural gas sales volumes were higher in 2017, as compared to 2016, due primarily to colder winter weather in the fourth quarter of 2017, as compared to 2016. Heating degree days in 2017 were 2.5 percent higher in Connecticut, as compared to 2016. Sales volumes were also positively impacted by improved economic conditions across our natural gas service territories.

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.

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.

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.

•	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 2017 performance as it achieved results at or above target for all of its SQ metrics in 2017.

NSTAR Gas distribution rates were set in its 2015 DPU approved rate case, which included 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.

Yankee Gas' last rate case 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, 2017, Yankee Gas had not triggered any of the earnings sharing thresholds.

Massachusetts Natural Gas Replacement and Expansion

On July 7, 2014, Massachusetts enacted "An Act Relative to Natural Gas Leaks" (the "Act"). The Act established 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 enabled companies, including NSTAR Gas, to better manage the scheduling and costs of replacement. The Act called 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 $374.4 million for the period 2016 through 2020 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 (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. Yankee Gas filed its 2016 System Expansion Reconciliation in March 2017, which was approved by PURA on September 13, 2017.

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 gas 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. In addition to the firm transportation and natural gas storage 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, which connect to other upstream pipelines that transport gas from major gas producing regions, including the Gulf Coast, Mid-continent, Canadian regions and Appalachian Shale supplies.

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.

WATER BUSINESS

Eversource Water Ventures, Inc., a Connecticut corporation, through its wholly-owned subsidiary, Eversource Aquarion Holdings, Inc. (Aquarion), operates regulated water utilities in Connecticut (Aquarion Water Company of Connecticut, or “AWC-CT”), Massachusetts (Aquarion Water Company of Massachusetts, or “AWC -MA”) and New Hampshire (Aquarion Water Company of New Hampshire, or “AWC-NH”). These regulated companies provide water services to approximately 226,000 residential, commercial, industrial, municipal and fire protection and other customers, in 59 towns and cities in Connecticut, Massachusetts and New Hampshire. As of December 31, 2017, approximately 87 percent of Aquarion’s customers were based in Connecticut.

For the period from December 4, 2017, the date Aquarion was acquired by Eversource, through December 31, 2017, water franchise retail revenues based on categories of customers for residential, commercial, municipal and fire protection, industrial and other totaled $9.9 million, $2.3 million, $2.5 million, $0.2 million and $1.0 million, respectively.

Rates

Aquarion's water utilities are subject to regulation by the PURA, the DPU and the NHPUC in Connecticut, Massachusetts and New Hampshire, respectively. These regulatory agencies, have jurisdiction over, among other things, rates, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, standards of service and construction and operation of facilities.

Aquarion’s general rate structure consists of various rate and service classifications covering residential, commercial, industrial, and municipal and fire protection services.

The rates established by the PURA, DPU and NHPUC are comprised of the following:

•	A base rate, which is comprised of fixed charges based on meter/fire connection sizes, as well as volumetric charges based on the amount of water sold. Together these charges are designed to recover the full cost of service resulting from a general rate proceeding.

•	A revenue adjustment mechanism (“RAM”) that reconciles earned revenues, with certain allowed adjustments, on an annual basis, to the revenue requirement approved by the PURA in AWC-CT’s last rate case (2013), which is an annual amount of $178.0 million.

•	The water infrastructure conservation adjustment (“WICA”) charge, which is applied between rate case proceedings and seeks recovery of allowed costs associated with WICA-eligible capital projects placed in-service. The WICA is updated semiannually in Connecticut and annually in New Hampshire.

•	Treatment plant surcharges, which are a series of three surcharges in Massachusetts (one fixed and two volumetric in nature) that are designed to recover certain operating costs and the costs of the lease of the treatment plant located in Hingham. These surcharges are applicable only to customers in Hingham, Hull and Cohasset.

Sources and Availability of Water Supply

Our water utilities obtain their water supplies from owned surface water sources (reservoirs) and groundwater supplies (wells) with a total supply yield of approximately 131 million gallons per day, as well as water purchased from other water suppliers. Approximately 98 percent of our annual production is self-supplied and processed at 10 surface water treatment plants and numerous well stations, which are all located in Connecticut, Massachusetts, and New Hampshire.

The capacities of Aquarion’s sources of supply, and water treatment, pumping and distribution facilities, are considered sufficient to meet the present requirements of Aquarion’s customers under normal conditions. On occasion, drought declarations are issued for portions of Aquarion’s service territories in response to extended periods of dry weather conditions.

OFFSHORE WIND PROJECT

Bay State Wind is a proposed offshore wind project being jointly developed by Eversource and Denmark-based Ørsted. Bay State Wind will be located in a 300-square-mile area approximately 25 miles off the coast of Massachusetts that has the ultimate potential to generate more than 2,000 MW of clean, renewable energy. Eversource and Ørsted each hold a 50 percent ownership interest in Bay State Wind.

For more information regarding the clean energy legislation, see "Regulatory Developments and Rate Matters – Massachusetts – Massachusetts RFPs" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.

PROJECTED CAPITAL EXPENDITURES

We project to make capital expenditures of approximately $10.8 billion from 2018 through 2021, of which we expect approximately $5.7 billion to be in our electric and natural gas distribution segments, approximately $4.1 billion to be in our electric transmission segment and $0.4 billion to be in our water utility business. We also project to invest approximately $0.5 billion in information technology and facilities upgrades and enhancements. These projections do not include any expected investments related to Bay State Wind.

FINANCING

Our credit facilities and indentures require that Eversource parent and certain of its subsidiaries, including CL&P, NSTAR Electric, PSNH, NSTAR Gas, and Yankee Gas, and Aquarion 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, 2017, $961.0 million of Eversource's long-term debt, including $450.0 million, $300.0 million, $110.0 million, $100.0 million and $1.0 million for Eversource parent, CL&P, PSNH, Yankee Gas and Aquarion, respectively, will be paid within the next 12 months.

NUCLEAR FUEL STORAGE

CL&P, NSTAR Electric, PSNH, 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 and PSNH and several other New England utilities. The decommissioning rates charged by the Yankee Companies have been reduced to zero. CL&P, NSTAR Electric and PSNH 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.

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, Yankee Gas, and Aquarion, the NHPUC, which has jurisdiction over PSNH and Aquarion, and the DPU, which has jurisdiction over NSTAR Electric, NSTAR Gas, and Aquarion.

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.

Air Quality Requirements

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. Following the completion of the sale of PSNH’s thermal generation facilities on January 10, 2018, we no longer own facilities subject to the provisions of the CAAA.

Renewable Portfolio Standards

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, wind, 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 2017, the total RPS obligation was 17.6 percent and it will ultimately reach 25.2 percent in 2025. The costs of the RECs are recovered by PSNH through 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 2017, the total RPS obligation was 22.5 percent and will ultimately reach 28 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 2017, the requirement was 22.34 percent, and will ultimately reach 26.1 percent in 2020. NSTAR Electric is permitted to recover any costs incurred in complying with RPS from its customers through rates. NSTAR Electric also owns renewable solar power facilities. The RECs generated from NSTAR Electric's solar power facilities 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, 2017, 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 $54.9 million, representing 59 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 $49.0 million of the total $54.9 million as of December 31, 2017. MGP costs are recoverable through rates charged to our customers.

Electric and Magnetic Fields

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

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

Global Climate Change and Greenhouse Gas Emission Issues

Global climate change and greenhouse gas emission issues have received an increased focus from state governments and the federal government. The EPA initiated a rulemaking addressing greenhouse gas emissions and, on December 7, 2009, issued a finding that concluded that greenhouse gas emissions are "air pollution" that 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 extended 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.

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 generation facilities with a current claimed capability representing winter rates of approximately 71 MW, eight of which are licensed by the FERC under long-term licenses. PSNH and its hydroelectric facilities 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. We are targeting for PSNH to close on the sale of its hydroelectric generation facilities by the end of the first quarter of 2018.

EMPLOYEES

As of December 31, 2017, Eversource Energy employed a total of 8,084 employees, excluding temporary employees, of which 1,270 were employed by CL&P, 1,922 were employed by NSTAR Electric, and 918 were employed by PSNH. 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.

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 and PSNH'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.