Item 1. Business

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Item 1. Business

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.

On February 2, 2015, NU and each of its wholly owned utility subsidiaries listed below commenced doing business as Eversource Energy. NU, headquartered in Boston, Massachusetts and Hartford, Connecticut, is a public utility holding company subject to regulation by 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 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 NU's electric transmission business.

NU, 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 NU. NU recognizes three reportable segments, which are electric distribution, electric transmission and natural gas distribution. NU's electric distribution segment includes the generation businesses of PSNH and WMECO. These three segments represented substantially all of NU's total consolidated revenues for the years ended December 31, 2014 and 2013. CL&P, NSTAR Electric, PSNH and WMECO do not report separate business segments.

ELECTRIC DISTRIBUTION SEGMENT

General

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

The following table shows the sources of 2014 electric franchise retail revenues for NU's electric distribution companies, collectively, based on categories of customers:


(Thousands of Dollars, except percentages)		2014	% of Total
Residential	$	3,288,313	53
Commercial		2,471,440	40
Industrial		348,698	6
Other and Eliminations		125,830	1
Total Retail Electric Revenues	$	6,234,281	100%

A summary of our distribution companies' retail electric GWh sales volumes and percentage changes for 2014, as compared to 2013, is as follows:


	2014	2013	Percentage Change
Residential	21,317	21,896	(2.6)%
Commercial	27,449	27,787	(1.2)%
Industrial	5,676	5,648	0.5 %
Total	54,442	55,331	(1.6)%

Our 2014 consolidated retail electric sales volumes were lower, as compared to 2013, due primarily to cooler summer weather in 2014 as well as an increase in customer conservation efforts primarily by our residential customers, including the impact of energy efficiency programs sponsored by CL&P, NSTAR Electric and WMECO.

For WMECO and CL&P (effective December 1, 2014), fluctuations in retail electric sales volumes do not impact earnings due to the regulatory commission approved revenue decoupling mechanisms. Distribution revenues are decoupled from their customer sales volumes. CL&P and WMECO 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 incurred during a 12-month period is adjusted through rates in the following period. The decoupling mechanism effectively breaks the relationship between sales volumes and revenues recognized. Prior to December 1, 2014, CL&P recognized LBR related to reductions in sales volume as a result of successful energy efficiency programs. LBR was recovered from retail customers through the FMCC. Effective December 1, 2014, CL&P no longer recognizes LBR due to its revenue decoupling mechanism.

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, 2014, 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 2014 electric franchise retail revenues based on categories of customers:


	CL&P
(Thousands of Dollars, except percentages)		2014	% of Total
Residential	$	1,474,181	58
Commercial		879,343	35
Industrial		149,220	6
Other		43,050	1
Total Retail Electric Revenues	$	2,545,794	100%

A summary of CL&P's retail electric GWh sales volumes and percentage changes for 2014, as compared to 2013, is as follows:


	2014	2013	Percentage Change
Residential	10,026	10,314	(2.8)%
Commercial	9,643	9,770	(1.3)%
Industrial	2,377	2,320	2.5 %
Total	22,046	22,404	(1.6)%

Rates

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

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

CL&P continues to supply approximately 45 percent of its customer load at SS or LRS rates while the other 55 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 generation services charge (GSC), which recovers energy-related costs incurred as a result of providing electric generation service supply to all customers that have not migrated to competitive energy suppliers. The GSC is adjusted periodically and reconciled semi-annually in accordance with the directives of PURA.

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 $1.041 billion.

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

A federally-mandated congestion charge (FMCC), which recovers any costs imposed by the FERC as part of the New England Standard Market Design, including locational marginal pricing, locational installed capacity payments, and any costs approved by 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 directives of PURA.

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

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

A systems benefits charge (SBC), established to fund expenses associated with: various hardship and low income programs; a program to compensate municipalities for losses in property tax revenue due to decreases in the value of electric generating facilities resulting directly from electric industry restructuring; and unfunded storage and disposal costs for spent nuclear fuel generated before 1983. The SBC is reconciled annually to actual costs incurred and reviewed by PURA, with any difference refunded to, or recovered from, customers.

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

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

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

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

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

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

On December 17, 2014, PURA approved CL&P's application to amend customer rates, effective December 1, 2014, for a total distribution rate increase of $134 million, which includes an authorized ROE of 9.02 percent for the first twelve month period and 9.17 percent thereafter. The distribution rate increase included a revenue decoupling reconciliation mechanism effective December 1, 2014, and the recovery of 2011 and 2012 storm restoration costs and system resiliency costs. In addition, as part of the rate case, CL&P began recovering the 2013 storm costs and residual 2012 Storm Sandy costs over a seven-year period beginning December 1, 2014. As of December 31, 2014, all of CL&P's deferred storm costs have been addressed by regulatory proceedings.

Sources and Availability of Electric Power Supply

As noted above, CL&P does not own any generation assets and purchases energy supply to serve its SS and LRS loads from a variety of competitive sources through requests for proposals. CL&P periodically enters into full requirements contracts for the majority of SS loads for periods of up to one year for its residential customers and small and medium commercial and industrial customers. CL&P is authorized to supply the remainder of the SS loads through a self-managed process that includes bilateral purchases and spot market purchases. CL&P typically enters into full requirements contracts for LRS for larger commercial and industrial customers every three months. Currently, CL&P has full requirements contracts

in place for 80 percent of its SS loads for the first half of 2015 and has bilateral purchases in place to self-manage the remaining 20 percent. For the second half of 2015, CL&P has 50 percent of its SS load under full requirements contracts, 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 2016 has been procured. CL&P has full requirements contracts in place for its LRS loads through the second quarter of 2015 and intends to purchase 100 percent of full requirements for the third and fourth quarters of 2015.

ELECTRIC DISTRIBUTION – MASSACHUSETTS

NSTAR ELECTRIC COMPANY

WESTERN MASSACHUSETTS ELECTRIC COMPANY

The electric distribution businesses of NSTAR Electric and WMECO consist primarily of the purchase, delivery and sale of electricity to residential, commercial and industrial customers within their respective franchise service territories. As of December 31, 2014, 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 208,000 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 coal-fired, oil-fired, or hydro-electric generating facilities, and each purchases its respective energy requirements from competitive energy suppliers.

In 2009, WMECO was authorized by the DPU to install solar energy generation in its service territory. From 2010 through 2014, WMECO completed development of a total of 8 MW solar generation facilities on sites in Pittsfield, Springfield, and East Springfield, Massachusetts. WMECO will sell all energy and other products from its solar generation facilities into the ISO-NE market. NSTAR Electric does not own any solar generation facilities.

The following table shows the sources of the 2014 electric franchise retail revenues of NSTAR Electric and WMECO based on categories of customers:


		NSTAR Electric		WMECO
(Thousands of Dollars, except percentages)		2014	% of Total	2014		% of Total
Residential	$	1,101,704	46	$	233,675	56
Commercial		1,161,466	49		131,093	31
Industrial		89,643	4		37,211	9
Other		29,765	1		15,470	4
Total Retail Electric Revenues	$	2,382,578	100%	$	417,449	100%

A summary of NSTAR Electric's and WMECO's retail electric GWh sales volumes and percentage changes for 2014, as compared to 2013, is as follows:


	NSTAR Electric			WMECO
	2014	2013	Percentage Change	2014	2013	Percentage Change
Residential	6,625	6,831	(3.0)%	1,494	1,544	(3.2)%
Commercial	13,009	13,163	(1.2)%	1,466	1,496	(2.0)%
Industrial	1,291	1,312	(1.6)%	626	643	(2.5)%
Total	20,925	21,306	(1.8)%	3,586	3,683	(2.6)%

Rates

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

Under Massachusetts law, all customers of each of NSTAR Electric and WMECO are entitled to choose their energy suppliers, while NSTAR Electric or WMECO remains their electric distribution company. Both NSTAR Electric and WMECO purchase power from competitive suppliers on behalf of, and pass the related cost through to, their respective customers who do not choose a competitive energy supplier (basic service). Most of the residential and small commercial and industrial customers of NSTAR Electric and WMECO have continued to buy their power from NSTAR Electric or WMECO at basic service rates. Most large 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 44 percent of its customer load at basic service rates while the other 56 percent of its customer load has migrated to competitive energy suppliers. WMECO continues to supply approximately 51 percent of its customer load at basic service rates

while the other 49 percent of its customer load has migrated to competitive energy suppliers. Because customer migration is limited to energy supply service, it has no impact on the delivery business or operating income of NSTAR and WMECO.

The 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 uncollected energy costs from customers. Electric distribution companies in Massachusetts are required to obtain and resell power to retail customers through basic service for those who choose not to buy energy from a competitive energy supplier. Basic service rates are reset every six months (every three months for large commercial and industrial customers). Additionally, the DPU has authorized NSTAR Electric to recover the cost of its Dynamic Pricing Smart Grid Pilot Program through the basic service charge. Basic service costs are reconciled annually.

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

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

Reconciling adjustment charges that recover certain DPU-approved costs as follows: pension and PBOP benefits, low income customer discounts, lost revenue and credits associated with net-metering facilities installed by customers, storms, consultants retained by the attorney general, and energy efficiency programs and lost base revenue not recovered in the energy efficiency charge. 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, a Smart Grid pilot program, and long-term renewable contracts. WMECO has a reconciling adjustment charge that recovers costs associated with certain solar projects owned and operated by WMECO.

As required by regulation, NSTAR Electric and WMECO, along with two other Massachusetts electric utilities, signed long-term commitments to purchase a combined estimated generating capacity of approximately 334 MW of wind power from two wind farms in Maine over 15 years. The projects are in various stages of permitting or development and are expected to begin operation in 2015 and 2016.

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

NSTAR Electric and WMECO are each subject to service quality (SQ) metrics that measure safety, reliability and customer service, and could be required to pay to customers a SQ charge of up to 2.5 percent of annual transmission and distribution revenues for failing to meet such metrics. Neither NSTAR Electric nor WMECO will be required to pay a SQ charge for its 2014 performance as each company achieved results at or above target for all of its respective SQ metrics in 2014.

Sources and Availability of Electric Power Supply

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

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, 2014, PSNH furnished retail franchise electric service to approximately 504,000 retail customers in 211 cities and towns in New Hampshire, covering an area of approximately 5,630 square miles. PSNH also owns and operates approximately 1,200 MW of primarily coal- and oil-fired electricity generation plants. PSNH's distribution business includes the activities of its generation business.

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

The following table shows the sources of PSNH's 2014 electric franchise retail revenues based on categories of customers:


	PSNH
(Thousands of Dollars, except percentages)		2014	% of Total
Residential	$	478,753	54
Commercial		299,538	34
Industrial		72,624	8
Other		37,544	4
Total Retail Electric Revenues	$	888,459	100%

A summary of PSNH's retail electric GWh sales volumes and percentage changes for 2014, as compared to 2013, is as follows:


	2014	2013	Percentage Change
Residential	3,172	3,208	(1.1)%
Commercial	3,332	3,357	(0.8)%
Industrial	1,382	1,373	0.6 %
Total	7,886	7,938	(0.7)%

Rates

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

Under New Hampshire law, all of PSNH's customers are entitled to choose competitive energy suppliers, with PSNH providing default energy service under its ES rate for those customers who do not choose a competitive energy supplier. At the end of 2014, approximately 21 percent of all of PSNH's customers (approximately 46 percent of load) were taking service from competitive energy suppliers, compared to 25 percent of customers (approximately 54 percent of load) at the end of 2013.

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

A default energy service charge (ES) is charged to customers who have selected not to receive their energy supply from a competitive energy supplier. These charges recover the costs of PSNH's generation, as well as purchased power, and include the NHPUC allowed ROE of 9.81 percent on PSNH's generation investment.

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 stranded cost recovery charge (SCRC), which allows PSNH to recover its stranded costs, including above-market expenses incurred under mandated power purchase obligations and other long-term investments and obligations. PSNH had financed a significant portion of its stranded costs through securitization by issuing RRBs secured by the right to recover these stranded costs from customers over the life of the RRBs. The costs of the RRBs, which were retired on May 1, 2013, were recovered through the SCRC rate.

A systems benefits charge (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 energy consumption.

The energy charge and SCRC rates change semi-annually and are reconciled annually and recovered in subsequent rates. The Rate ADE reconciliation amount is incorporated into the ES reconciliation.

PSNH is currently operating under the 2010 NHPUC approved distribution rate case settlement, which is effective through June 30, 2015. Under the settlement, PSNH is permitted to file a request to collect certain exogenous costs and step increases on an annual basis.

Generation Assets

In 2013, the NHPUC opened a docket that initiated a series of actions throughout 2013 and 2014 regarding the potential divestiture of PSNH's generating plants, including actions by the NHPUC staff, the State of New Hampshire Legislative Oversight Committee on Electric Utility Restructuring (Oversight Committee), a valuation expert, and the New Hampshire Legislature. During the 2014 Legislative session, in response to an NHPUC staff recommendation to harmonize existing laws regarding divestiture, energy service, and cost recovery, the Legislature enacted changes to the laws governing divestiture of PSNH's generation assets, effective September 30, 2014. The new law required the NHPUC to initiate a

proceeding before January 1, 2015, to determine whether all or some of PSNH's generation assets should be divested. The NHPUC opened its docket DE 14-238 on September 16, 2014. A progress report from the NHPUC must be provided to the Oversight Committee by March 31, 2015. The law gives the NHPUC express authority to order the divestiture of all or some of PSNH's generation assets if the NHPUC finds it is in the economic interest of customers to do so. The law also clarified the definition of "stranded costs" to include costs approved for recovery by the NHPUC in connection with the divestiture or retirement of PSNH's generation assets. In the event of generation asset divestiture or retirement, present law and the PSNH Restructuring Settlement Agreement approved in 2000 require that the NHPUC provide recovery of any stranded costs by PSNH. For further information, see "Regulatory Developments and Rate Matters – New Hampshire - Generation" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.

Sources and Availability of Electric Power Supply

During 2014, approximately 59 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 41 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 2015 in a similar manner. Included in the 59 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, Schiller and the Hydro stations have been operating at very high capacity factors during this current winter season, As a result of our diverse fuel mix, PSNH's Energy Service rate has been set at 10.56 cents per kWh, well below the winter default service rates in excess of 15 cents per kWh for the two other investor owned utilities in the state.

MAJOR STORMS

CL&P, NSTAR Electric, PSNH and WMECO experienced several significant storm events, including Tropical Storm Irene in 2011, the October 2011 snowstorm, Storm Sandy in 2012, the February 2013 blizzard, and a November 2014 snowstorm. As a result of these storm events, each company suffered extensive damage to its distribution and transmission systems resulting in customer outages. Each company incurred significant costs to repair damage and restore customers' service.

The magnitude of these storm restoration costs met the criteria for cost deferral in Connecticut, Massachusetts, and New Hampshire. As a result, the storms had no material impact on the results of operations of CL&P, NSTAR Electric, PSNH and WMECO. We believe the storm restoration costs were prudent and meet the criteria for specific cost recovery in Connecticut, Massachusetts and New Hampshire, and that recovery from customers is probable through the applicable regulatory recovery process. Each electric utility has sought, or is seeking, recovery of its deferred storm restoration costs through its applicable regulatory recovery process. For further information, see "Regulatory Developments and Rate Matters" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.

ELECTRIC TRANSMISSION SEGMENT

General

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

Wholesale Transmission Revenues

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


(Thousands of Dollars)		2014
CL&P	$	507,182
NSTAR Electric		275,377
PSNH		114,963
WMECO		120,803
Total Wholesale Transmission Revenues	$	1,018,325

Wholesale Transmission Rates

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

FERC Base ROE Complaints

Beginning in 2011, several New England state attorneys general, state regulatory commissions, consumer advocates, consumer groups, municipal parties and other parties (the "Complainants") jointly filed three separate complaints at FERC. In the first complaint, filed in 2011, the Complainants alleged that the NETOs' base ROE of 11.14 percent that was utilized since 2006 was unjust and unreasonable, asserted that the rate was excessive due to changes in the capital markets, and sought an order to reduce it prospectively from the date of the final FERC order and for the 15-month period beginning October 1, 2011 to December 31, 2012 (the "first complaint refund period"). In the pursuant second and third complaints, filed in 2012 and 2014, respectively, the Complainants challenged the NETOs' base ROE and sought refunds for the 15-month periods beginning December 27, 2012 and July 31, 2014, respectively.

In 2014, the FERC determined that the base ROE should be set at 10.57 percent for the first complaint refund period and that a utility's total or maximum ROE should not exceed the top of the new zone of reasonableness (7.03 percent to 11.74 percent). The FERC ordered the NETOs to provide refunds to customers for the first complaint refund period and set the new base ROE of 10.57 percent prospectively from October 16, 2014. In late 2014, the NETOs made a compliance filing, and began refunding amounts from the first complaint period, inclusive of incentive ROE adders that exceeded the 11.74 percent as compared to the total company transmission ROE. Complainants have challenged the compliance filing.

As a result of the actions taken by the FERC and other developments in this matter, NU recorded reserves in 2013 and 2014 to recognize the potential financial impacts of the first and second complaints. The Company is unable to determine any amount related to the third complaint. The aggregate after-tax net charge to 2014 earnings resulting from the 2014 FERC orders totaled $22.4 million at NU. In 2013, the aggregate after-tax charge to earnings totaled $14.3 million at NU.

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

FERC Order No. 1000

On August 15, 2014, the D.C. Circuit Court of Appeals upheld 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. FERC has not yet ruled on the comprehensive compliance filings made in November 2013 by the NETOs, including CL&P, NSTAR Electric, PSNH and WMECO. We cannot predict the final outcome or impact on us; however, implementation of FERC's goals in New England, including within our service territories, may expose us to competition for construction of transmission projects, additional regulatory considerations, and potential delay with respect to future transmission projects. While the FERC Orders may bring new challenges, we believe there are also opportunities for us to compete for transmission reliability projects outside of our service territories.

Transmission Projects

During 2014, we were involved in the planning, development and construction of a series of transmission projects, including the NEEWS family of projects, Northern Pass, which is NU's planned HVDC transmission line from the Québec-New Hampshire border to Franklin, New Hampshire and an associated alternating current radial transmission line between Franklin and Deerfield, New Hampshire, 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. For further information, see "Business Development and Capital Expenditures – Transmission Business" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.

Transmission Rate Base

Under our FERC-approved tariff, and with the exception of transmission projects that received specific FERC approval to include CWIP in rate base, transmission projects generally enter rate base after they are placed in commercial operation. At the end of 2014, our estimated transmission rate base was approximately $4.9 billion, including approximately $2.4 billion at CL&P, $1.3 billion at NSTAR Electric, $535 million at PSNH, and $611 million at WMECO.

NATURAL GAS DISTRIBUTION SEGMENT

NSTAR Gas distributes natural gas to approximately 282,000 customers in 51 communities in central and eastern Massachusetts covering 1,067 square miles and Yankee Gas distributes natural gas to approximately 222,000 customers in 71 cities and towns in Connecticut covering 2,187 square miles. Total throughput (sales and transportation) in 2014 was approximately 60.5 Bcf for NSTAR Gas and 55 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 NU'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 NU. The facilities consist of an LNG liquefaction and vaporization plant and three above-ground cryogenic storage tanks in Hopkinton, Massachusetts having an aggregate capacity of 3.0 Bcf of liquefied natural gas. NSTAR Gas also has access to facilities in Acushnet, Massachusetts that include additional storage capacity of 0.5 Bcf and additional vaporization capacity. Yankee Gas owns a 1.2 Bcf LNG facility in Waterbury, Connecticut, which is used primarily to assist Yankee Gas in meeting its supplier-of-last-resort obligations and also enables it to provide economic supply and make economic refill of natural gas typically during periods of low demand.

NSTAR Gas and Yankee Gas generate revenues primarily through the sale and/or transportation of natural gas. Predominantly all residential customers in the NSTAR Gas service territory buy gas supply and delivery from NSTAR Gas while all customers may choose their 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 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 2014 total NU natural gas franchise retail revenues based on categories of customers:


(Thousands of Dollars, except percentages)		2014	% of Total
Residential	$	520,410	55
Commercial		332,414	35
Industrial		94,861	10
Total Retail Natural Gas Revenues	$	947,685	100%

A summary of our firm natural gas sales volumes in million cubic feet and percentage changes for 2014, as compared to 2013, is as follows:


			Percentage
	2014	2013	Change
Residential	38,969	36,777	6.0%
Commercial	42,977	40,215	6.9%
Industrial	22,245	21,266	4.6%
Total	104,191	98,258	6.0%
Total, Net of Special Contracts (1)	99,500	94,083	5.8%

(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 are subject to many of the same influences as our retail electric sales. In addition, they have benefited from favorable natural gas prices and customer growth across both operating companies. Our 2014 consolidated firm natural gas sales volumes, consisting of the firm natural gas sales volumes of Yankee Gas and NSTAR Gas, were higher, as compared to 2013, due primarily to colder weather in the first quarter of 2014, as compared to the same period in 2013, and increased customer growth in 2014, as compared to 2013. Weather-normalized NU consolidated firm natural gas sales volumes increased 2.9 percent in 2014, as compared to 2013.

Rates

NSTAR Gas and Yankee Gas are subject to regulation by the DPU and 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 NU'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 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 energy efficiency program costs, environmental costs, pension and PBOP related costs, energy efficiency costs, attorney general consultant costs, and costs associated with low income customers. The LDAC is reset annually and provides for the recovery of certain costs applicable to both sales and transportation customers.

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

Conservation Adjustment Mechanism (CAM) at Yankee Gas, which allows 100 percent recovery of conservation costs through this mechanism including program incentives to promote energy efficiency, as well as recovery of any lost revenues associated with implementation of energy conservation measures. A reconciliation of CAM revenues to expenses is performed annually with any difference being recovered from or refunded to customers, with carrying charges, during the following year.

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

NSTAR Gas is subject to 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 2014 performance as it achieved results at or above target for all of its SQ metrics in 2014.

On December 17, 2014, NSTAR Gas filed an application with the DPU requesting an increase in rates, effective January 1, 2016. NSTAR Gas requested an increase in base distribution rates of $33.9 million. Based on the current schedule, we expect a final decision in the fourth quarter of 2015.

In 2011, PURA approved Yankee Gas' rate proceeding. The final decision approved a regulatory ROE of 8.83 percent and allowed for a substantial increase in annual spending for bare steel and cast iron pipeline replacement.

Massachusetts Natural Gas Replacement and Expansion

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

NSTAR Gas filed the Gas System Enhancement Program (GSEP) with the DPU on October 31, 2014. NSTAR Gas' program accelerates the replacement of certain natural gas distribution facilities in the system within 25 years. The GSEP includes a new tariff that provides NSTAR Gas an opportunity to collect the costs for the program on an annual basis through a newly designed reconciling factor to be approved by the DPU. We expect a decision on the program in April 2015.

Connecticut Natural Gas Expansion Plan

In 2013, in accordance with Connecticut law and regulation, PURA approved a comprehensive joint natural gas infrastructure expansion plan (expansion plan) filed by Yankee Gas and other Connecticut natural gas distribution companies. The expansion plan described how Yankee Gas expects to add approximately 82,000 new natural gas heating customers over the next 10 years. Yankee Gas estimates that its portion of the plan will cost approximately $700 million over 10 years. In January 2015, 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.

Sources and Availability of Natural Gas Supply

NSTAR Gas maintains a flexible resource portfolio consisting of natural gas supply contracts, transportation contracts on interstate pipelines, market area storage and peaking services. NSTAR Gas purchases transportation, storage, and balancing services from Tennessee Gas Pipeline Company and Algonquin Gas Transmission Company, as well as other upstream pipelines that transport gas from major producing regions in the U.S., including the Gulf Coast, Mid-continent region, and Appalachian Shale supplies to the final delivery points in the NSTAR Gas service area. NSTAR Gas purchases all of its natural gas supply under a firm portfolio management contract with a term of one year, which has a maximum quantity of approximately 154,700 MMBtu/day of firm flowing natural gas supplies and 76,700 MMBtu/day of firm natural gas storage supplies.

In addition to the firm transportation and natural gas supplies mentioned above, NSTAR Gas utilizes contracts for underground storage and LNG facilities to meet its winter peaking demands. The LNG facilities, described below, are located within NSTAR Gas' distribution system and are used to liquefy and store pipeline natural gas during the warmer months for vaporization and use during the heating season. During the summer injection season, excess pipeline capacity and supplies are used to deliver and store natural gas in market area underground storage facilities located in the

New York and Pennsylvania regions. Stored natural gas is withdrawn during the winter season to supplement flowing pipeline supplies in order to meet firm heating demand. NSTAR Gas has firm underground storage contracts and total storage capacity entitlements of approximately 6.6 Bcf.

A portion of the storage of natural gas supply for NSTAR Gas during the winter heating season is provided by Hopkinton LNG Corp., which owns an LNG liquefaction and vaporization plant and three above-ground cryogenic storage tanks having an aggregate capacity of 3.0 Bcf of liquefied natural gas. NSTAR Gas also has access to facilities that include additional storage capacity of 0.5 Bcf and additional vaporization capacity.

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 expansion projects will be required in order for it to meet current and future sales growth opportunities.

NATURAL GAS PIPELINE EXPANSION

On September 16, 2014, NU and Spectra Energy Corp announced Access Northeast, a natural gas pipeline expansion project. Access Northeast will enhance the Algonquin and Maritimes pipeline systems using existing routes and is expected to be capable of delivering approximately one billion cubic feet of natural gas per day to New England. NU and Spectra Energy Corp will have equal ownership interest in the project with the option of additional investors joining in the future. On February 18, 2015, NU, Spectra Energy Corp and National Grid announced the addition of National Grid as a co-developer in the project for a total ownership interest of 20 percent, with NU and Spectra Energy Corp each owning 40 percent. The total project cost, subject to FERC approval, is expected to be approximately $3 billion and has an anticipated in-service date of November 2018.

On December 8, 2014, NU and Spectra Energy Corp announced an alliance with Iroquois Gas Transmission for the Access Northeast project. This alliance will provide New England natural gas distribution companies and generators with additional access to natural gas supplies from multiple, diverse receipt points along the Algonquin pipeline system, including the Iroquois pipeline system.

PROJECTED CAPITAL EXPENDITURES

We project to make capital expenditures of approximately $8.4 billion from 2015 through 2018. Of the $8.4 billion, we expect to invest approximately $4.2 billion in our electric and natural gas distribution segments and $3.9 billion in our electric transmission segment. In addition, we project to invest approximately $360 million in information technology and facilities upgrades and enhancements. These projections do not include capital expenditures related to Access Northeast.

FINANCING

Our credit facilities and indentures require that NU 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, 2014, a total of $216.7 million of NU's long-term debt will be paid in the next 12 months, consisting of $162 million for CL&P, $4.7 million for NSTAR Electric and $50 million or WMECO.

NUCLEAR FUEL STORAGE

CL&P, NSTAR Electric, PSNH, WMECO and several other New England electric utilities are stockholders in three inactive regional nuclear generation companies, CYAPC, MYAPC and YAEC (collectively, the Yankee Companies). The Yankee Companies have completed the physical decommissioning of their respective generation facilities and are now engaged in the long-term storage of their spent nuclear fuel. Each Yankee Company has completed its collection of decommissioning and closure costs through the proceeds from the spent nuclear fuel litigation against the DOE. These proceeds were used by the Yankee Companies to offset the decommissioning and closure cost receivables 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 eliminated. 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.

As a result of the merger with NSTAR, we consolidate the assets and obligations of CYAPC and YAEC on our consolidated balance sheet.

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

OTHER REGULATORY AND ENVIRONMENTAL MATTERS

General

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

Environmental Regulation

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

Water Quality Requirements

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

In 1997, PSNH filed in a timely manner for a renewal of the NPDES permit for the Merrimack Station. As a result, the existing permit was administratively continued. In 2011, the EPA issued a draft renewal NPDES permit for PSNH's Merrimack Station for public review and comment. The proposed permit contains many significant conditions to future operation. The proposed permit would require PSNH to install a closed-cycle cooling system (including cooling towers) at the station. The EPA estimated that the net present value cost to install this system and operate it over a 20-year period would be approximately $112 million. PSNH and other electric utility groups filed thousands of pages of comments contesting EPA's draft permit requirements. PSNH stated that the data and studies supplied to the EPA demonstrate the fact that a closed-cycle cooling system is not warranted. On April 18, 2014 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, 2014 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.

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.

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

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

New Hampshire's RPS provision requires increasing percentages of the electricity sold to retail customers to have direct ties to renewable sources. In 2014, the total RPS obligation was 9.7 percent and it will ultimately reach 24.8 percent in 2025. Energy suppliers, like PSNH, purchase RECs from producers that generate energy from a qualifying resource and use them to satisfy the RPS requirements. PSNH also owns renewable sources and uses a portion of internally generated RECs to meet its RPS obligations. To the extent that PSNH is unable to purchase sufficient RECs, it makes up the difference between the RECs purchased and its total obligation by making an alternative compliance payment for each REC requirement for which PSNH is deficient. The costs of both the RECs and alternative compliance payments are recovered by PSNH through its ES rates charged to customers.

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

Similarly, Connecticut's RPS statute requires increasing percentages of the electricity sold to retail customers to have direct ties to renewable sources. In 2014, the total RPS obligation was 18 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 2014, the requirement was 16.1 percent, and will ultimately reach 22.1 percent in 2020. NSTAR Electric and WMECO are permitted to recover any costs incurred in complying with RPS from its customers through rates. WMECO also owns renewable solar generation resources. The RECs generated from WMECO's solar units are sold to other energy suppliers, and the proceeds from these sales are credited back to customers.

Hazardous Materials Regulations

Prior to the last quarter of the 20th century, when environmental best practices laws and regulations were implemented, utility companies often disposed of residues from operations by depositing or burying them on-site or disposing of them at off-site landfills or other facilities. Typical materials disposed of include coal gasification byproducts, fuel oils, ash, and other materials that might contain polychlorinated biphenyls or that otherwise might be hazardous. It has since been determined that deposited or buried wastes, under certain circumstances, could cause groundwater contamination or create other environmental risks. We have recorded a liability for what we believe, based upon currently available information, is our reasonably estimable environmental investigation and/or remediation costs for waste disposal sites for which we have probable liability. We continue to evaluate the environmental impact of our former disposal practices. Under federal and state law, government agencies and private parties can attempt to impose liability on us for these practices. As of December 31, 2014, 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 $43.3 million, representing 65 sites. These costs could be significantly higher if 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 $38.8 million of the total $43.3 million as of December 31, 2014. Predominantly all of these MGP costs are recoverable from customers through our rates.

Electric and Magnetic Fields

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

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

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 endanger 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. A regulated power plant must hold CO2 allowances equal to its emissions to demonstrate compliance at the end of a three year compliance period that ended on December 31, 2014.

PSNH anticipates that its generating units will emit two million to 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. New Hampshire legislation provided up to 1.5 million banked CO2 allowances per year for PSNH's coal- and oil-fired electric generating plants during the 2012 through 2014 compliance period. PSNH satisfied its remaining RGGI requirements by purchasing CO2 allowances at auction or in the secondary market. 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 NU'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 will likely be included in the overall wholesale rates charged, which costs are then recoverable from customers.

FERC Hydroelectric Project Licensing

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

PSNH 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 in the early stages of relicensing its 6.5 MW Eastman Falls Hydro Station, the license for which expires in 2017.

EMPLOYEES

As of December 31, 2014, NU employed a total of 8,248 employees, excluding temporary employees, of which 1,548 were employed by CL&P, 1,717 were employed by NSTAR Electric 1,048 were employed by PSNH, and 310 were employed by WMECO. Approximately 51 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 13 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 NU'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 Northeast Utilities, 107 Selden Street, Berlin, CT 06037.

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