Item 1.

Business

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

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:

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

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

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

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

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

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

NU also owns certain unregulated businesses through its wholly owned subsidiary, NU Enterprises, which is included in its Parent and other companies’ results of operations.

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, 2013 and 2012.  CL&P, NSTAR Electric, PSNH and WMECO do not report separate business segments.   

MERGER WITH NSTAR

On April 10, 2012, NU completed its merger with NSTAR (Merger).  Pursuant to the terms and conditions of the Agreement and Plan of Merger, as amended, NSTAR and its subsidiaries became wholly-owned subsidiaries of NU.  NU’s consolidated financial statements include the results of operations of NSTAR and its subsidiaries (NSTAR) for the period after April 10, 2012.

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.  

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The following table shows the sources of 2013 electric franchise retail revenues for NU’s electric distribution companies, collectively, based on categories of customers:

⁽¹⁾    Commercial retail electric revenue includes Streetlighting and Railroad retail revenue.

A summary of our distribution companies’ retail electric GWh sales and percentage changes for 2013, as compared to 2012, is as follows:

⁽¹⁾

Results include retail electric sales of NSTAR Electric for all of 2012 for comparative purposes only.  

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  Commercial retail electric GWh sales include Streetlighting and Railroad retail sales.

Our 2013 consolidated retail electric sales were higher, as compared to 2012, due primarily to colder weather in the first and fourth quarters of 2013.  The 2013 retail electric sales for CL&P, NSTAR Electric and PSNH increased while they remained unchanged for WMECO, as compared to 2012, due primarily to colder weather in the first and fourth quarters of 2013.  In 2013, heating degree days were 17 percent higher in Connecticut and western Massachusetts, 16 percent higher in the Boston metropolitan area, and 15 percent higher in New Hampshire, and cooling degree days were 7 percent lower in Connecticut and western Massachusetts, 2 percent higher in the Boston metropolitan area, and 9 percent lower in New Hampshire, as compared to 2012.  On a weather-normalized basis (based on 30-year average temperatures), 2013 retail electric sales for CL&P and PSNH increased, while they decreased for NSTAR Electric and WMECO, as compared to 2012.  The 2013 weather-normalized NU consolidated total retail electric sales remained relatively unchanged, as compared to 2012.

For WMECO, fluctuations in retail electric sales do not impact earnings due to the DPU-approved revenue decoupling mechanism.  Under this decoupling mechanism, WMECO has an overall fixed annual level of distribution delivery service revenues of $132.4 million, comprised of customer base rate revenues of $125.4 million and a baseline low income discount recovery of $7 million.  These two mechanisms effectively break the relationship between sales volume and revenues recognized.

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, 2013, 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 2013 electric franchise retail revenues based on categories of customers:

⁽¹⁾     Commercial retail electric revenue includes Streetlighting and Railroad retail revenue.

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A summary of CL&P’s retail electric GWh sales and percentage changes for 2013, as compared to 2012, is as follows:

⁽¹⁾     Commercial retail electric GWh sales include Streetlighting and Railroad retail sales.

Rates

CL&P is subject to regulation by PURA, which, among other things, has jurisdiction over rates, accounting procedures, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, standards of service 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 operation and capital costs, 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 56 percent of its customer load at SS or LRS rates while the other 44 percent of its customer load has migrated to competitive energy suppliers.  Because this customer migration is only for energy supply service, it has no impact on CL&P’s delivery business or its operating income.

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

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An electric generation services 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.  This charge is adjusted periodically and reconciled semi-annually in accordance with the directives of PURA.

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

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A federally-mandated congestion charge, or 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.  This charge also recovers costs associated with CL&P’s system resiliency program.  This charge is adjusted periodically and reconciled semi-annually in accordance with the directives of PURA.

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

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

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A system benefits charge 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.  This charge is reconciled annually to actual costs incurred and reviewed by PURA, with any difference refunded to, or recovered from, customers.  

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

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

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Expense/revenue reconciliation amounts for the electric generation services charge and the FMCC are recovered in subsequent rates.

CL&P, jointly with UI, has entered into four CfDs for a total of approximately 787 MW of capacity consisting of three electric generation units and one demand response project.  The capacity CfDs extend through 2026 and obligate the utilities to pay the difference between a set price and the value that the generation units receive in the ISO-NE markets.  The contracts have terms of up to 15 years beginning in 2009 and are subject to a sharing agreement with UI, whereby UI will have a 20 percent share of the costs and benefits of these contracts.  CL&P's portion of the costs and benefits of these contracts will be paid by or refunded to CL&P's customers through the FMCC charge.  The amounts of these payments are subject to changes in capacity and forward reserve prices that the projects receive in the ISO-NE capacity markets.

In 2008, CL&P entered into three CfDs with developers of peaking generation units approved by the PURA (Peaker CfDs). These units have a total of approximately 500 MW of peaking capacity. As directed by the PURA, CL&P and UI have entered into a sharing agreement, whereby CL&P is responsible for 80 percent and UI for 20 percent of the net costs or benefits of these CfDs. The Peaker CfDs pay the developer the difference between capacity, forward reserve and energy market revenues and a cost-of service payment stream for 30 years. The ultimate cost or benefit to CL&P under these contracts will depend on the costs of plant operation and the prices that the projects receive for capacity and other products in the ISO-NE markets. CL&P's portion of the amounts paid or received under the Peaker CfDs will be recoverable from or refunded to CL&P's customers.  

On June 30, 2010, PURA issued a final order in CL&P’s most recent retail distribution rate case approving distribution rates and establishing CL&P’s authorized distribution regulatory ROE at 9.4 percent.  

On March 13, 2012, NU and NSTAR reached a comprehensive settlement agreement with the Connecticut Attorney General and the Connecticut Office of Consumer Counsel related to the merger.  The settlement agreement covered a variety of matters, including a CL&P base distribution rate freeze until December 1, 2014.

On September 19, 2013, CL&P, along with another Connecticut utility, signed long-term commitments, as required by regulation, to purchase approximately 250 MW of wind power from a Maine wind farm and 20 MW of solar power from sites in Connecticut, at a combined average price of less than $0.08 per kWh. On October 23, 2013, PURA issued a final decision accepting the contracts. The two projects are expected to be operational by the end of 2016.

Sources and Availability of Electric Power Supply

As noted above, CL&P does not own any generation assets and purchases energy to serve its SS and LRS loads from a variety of competitive sources through periodic requests for proposals.  CL&P enters into supply contracts for SS periodically for periods of up to one year for its residential and small and medium load commercial and industrial customers.  CL&P enters into supply contracts for LRS for larger commercial and industrial customers every three months.  Currently, CL&P has contracts in place with various wholesale suppliers for firm requirements service for 70 percent of its SS loads for the first half of 2014, and has energy contracts in place to self-supply the remaining 30 percent for the first half of 2014.  For the second half of 2014, CL&P has 50 percent of its SS load under contract with various wholesale suppliers for firm requirements service and energy contracts in place to self-supply 10 percent.  CL&P intends to purchase 20 to 30 percent of the SS load for the second half of 2014 from wholesale suppliers for firm requirements service and will self-supply the remainder needed.  None of the SS load for 2015 has been procured.  CL&P has contracts in place for its LRS loads through the second quarter of 2014, and CL&P intends to purchase 100 percent of the LRS load for the third and fourth quarter of 2014 from wholesale suppliers for firm requirements service.

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, 2013, 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 1,702 square miles.  WMECO provides retail franchise electric service to approximately 207,000 retail customers in 59 cities and towns in the western region of Massachusetts, covering an area of 1,500 square miles.  Neither NSTAR Electric nor WMECO owns any fossil or hydro-electric generating facilities, and each purchases its respective energy requirements from third party suppliers.  

In 2009, WMECO was authorized by the DPU to install 6 MW of solar energy generation in its service territory.  In October 2010, WMECO completed development of a 1.8 MW solar generation facility on a site in Pittsfield, Massachusetts, and in December 2011 completed development of a 2.3 MW solar generation facility in Springfield, Massachusetts.  On September 4, 2013, the DPU approved WMECO's proposal to build a third solar generation facility and expand its solar energy portfolio from 6 MW to 8 MW.  On October 22, 2013, WMECO announced it would install a 3.9 MW solar generation facility on a site in East Springfield, Massachusetts.  The facility is expected to be completed in mid-2014 with an estimated cost of approximately $15 million.  WMECO will sell all energy and other products from its solar generation facilities into the ISO-NE market.  NSTAR Electric does not own any solar generating facilities, but agreed to enter into long-term contracts for 10 megawatts of solar power in connection with the Department of Energy Resources settlement agreement that approved the Merger in Massachusetts.  NSTAR Electric has entered in two contracts for 5 MW of capacity,

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which were approved by the DPU in May, 2013.  However these contracts were terminated on November 6, 2013 by mutual agreement of the parties.  NSTAR Electric expects to meet its merger commitment by issuing a request for proposals to enter into long-term contracts for additional renewable solar generation.  

The following table shows the sources of the 2013 electric franchise retail revenues of NSTAR Electric and WMECO based on categories of customers:

⁽¹⁾     Commercial retail electric revenue includes Streetlighting and Railroad retail revenue.

A summary of NSTAR Electric’s and WMECO’s retail electric GWh sales and percentage changes for 2013, as compared to 2012, is as follows:

⁽¹⁾     Commercial retail electric GWh sales include Streetlighting and Railroad retail sales.

Rates

NSTAR Electric and WMECO are each subject to regulation by the DPU, which has jurisdiction over, among other things, rates, accounting procedures, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, acquisition of securities, standards of service 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 operation and capital costs, to attract needed capital and maintain their financial integrity, while also protecting relevant public interests.

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

The Cape Light Compact, an inter-governmental organization consisting of the 21 towns and two counties on Cape Cod and Martha’s Vineyard, serves 200,000 customers through the delivery of energy efficiency programs, effective consumer advocacy, competitive electricity supply and green power options.  NSTAR Electric continues to provide electric service to these customers including the delivery of power, meter reading, billing, and customer service.

NSTAR Electric continues to supply approximately 46 percent of its customer load at basic service rates while the other 54 percent of its customer load has migrated to competitive energy suppliers.  WMECO continues to supply approximately 49 percent of its customer load at basic service rates while the other 51 percent of its customer load has migrated to competitive energy suppliers.  Because customer migration is limited to energy supply service, it has no impact on the delivery business or operating income of NSTAR and WMECO.

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

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A basic service charge that represents the collection of energy costs, including costs related to charge-offs of uncollected energy costs.  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.

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·

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

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For WMECO, a revenue decoupling adjustment, that reconciles distribution revenue, on an annual basis, to the amount of distribution revenue approved by the DPU in its last rate case.

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

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

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Reconciling adjustment charges that recover certain DPU-approved costs, including a pension and PBOP rate to recover incremental pension and PBOP benefit costs, a  residential assistance adjustment factor to recover the cost of low income discounts, a net-metering surcharge to collect the lost revenue and credits associated with net-metering facilities installed by customers, a storm recovery charge to collect certain storm related costs, and an energy efficiency reconciliation factor to recover energy efficiency program costs and lost base revenues in addition to those charges recovered in the energy efficiency charge.  In addition to these adjustments, NSTAR Electric has a reconciling adjustment charge that collects certain safety and reliability program costs and costs related to its Smart Grid pilot program, while WMECO has a reconciling adjustment charge that recovers costs associated with certain solar projects owned and operated by WMECO.

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

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

Rate Settlement Agreement

On February 15, 2012, NU and NSTAR reached comprehensive settlement agreements with the Massachusetts Attorney General (Attorney General’s settlement agreement) and the DOER related to the merger.  The Attorney General’s settlement agreement covered a variety of rate-making and rate design issues, including a base distribution rate freeze through 2015 for NSTAR Electric and WMECO.  The settlement agreement reached with the DOER covered the same rate-making and rate design issues as the Attorney General's settlement agreement, as well as a variety of matters impacting the advancement of energy policies.

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.  The exact timing of NSTAR Electric’s next rate case has not yet been determined, but it will not be before 2015.

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 2013 performance as each company achieved results at or above target for all of its respective SQ metrics in 2013.

Sources and Availability of Electric Power Supply

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

ELECTRIC DISTRIBUTION – NEW HAMPSHIRE

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE

PSNH’s distribution business consists primarily of the generation, delivery and sale of electricity to its residential, commercial and industrial customers.  As of December 31, 2013, PSNH furnished retail franchise electric service to approximately 500,000 retail customers in 211 cities and towns in New Hampshire, covering an area of 5,628 square miles.  PSNH also owns and operates approximately 1,200 MW of primarily fossil-fueled electricity generation plants.  Included in those electric generating plants is PSNH’s 50 MW wood-burning Northern Wood Power Project at its Schiller Station in Portsmouth, New Hampshire, and approximately 70 MW of hydroelectric generation.  PSNH’s distribution business includes the activities of its generation business.

The Clean Air Project, a wet flue gas desulphurization system (Scrubber), was constructed and placed in service by PSNH at its Merrimack Station in September 2011.  PSNH completed remaining project construction activities in 2012 and the final cost of the project was approximately $421 million .

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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.

Prudent Scrubber costs are allowed to be recovered through PSNH's ES rates under New Hampshire law.  In November 2011, the NHPUC opened a docket to review the Clean Air Project.  For information about this docket, see "Regulatory Developments and Rate Matters – New Hampshire – Clean Air Project Prudence Proceeding" in the accompanying Management’s Discussion and Analysis .

The following table shows the sources of PSNH’s 2013 electric franchise retail revenues based on categories of customers:

⁽¹⁾     Commercial retail electric revenue includes Streetlighting and Railroad retail revenue.

A summary of PSNH’s retail electric GWh sales and percentage changes for 2013, as compared to 2012, is as follows:

⁽¹⁾     Commercial retail electric GWh sales include Streetlighting and Railroad retail sales.

Rates

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

Under New Hampshire law, all of PSNH's customers are entitled to choose competitive energy suppliers, with PSNH providing default energy service under its ES rate for those customers who do not elect to use a third party supplier.  Prior to 2009, PSNH experienced only a minimal amount of customer migration.  However, customer migration levels began to increase significantly in 2009 as energy costs decreased from their historic high levels and competitive energy suppliers with more pricing flexibility were able to offer electricity supply at lower prices than PSNH.  By the end of 2013, approximately 25 percent of all of PSNH’s customers (approximately 54 percent of load) had switched to competitive energy suppliers.  This was an increase from 2012, when 9 percent of customers (approximately 44 percent of load) had switched to competitive energy suppliers.  The increased level of migration has caused an increase in the ES rate, as fixed costs of PSNH’s generation assets must be spread over a smaller group of customers and lower sales volume.  The customers that have not chosen a third party supplier, predominantly residential and small commercial customers, are now paying a larger proportion of these fixed costs.  On July 26, 2011, the NHPUC ordered PSNH to file a rate proposal that would mitigate the impact of customer migration expected to occur when the ES rate is higher than market prices.  On April 8, 2013, the NHPUC issued an order conditionally approving a PSNH settlement with OCA and PUC staff for an Alternative Default Energy (ADE) pilot program rate which was designed to address customer migration.  The NHPUC condition was accepted by the Settling Parties and incorporated into the initial implementation of Rate ADE in mid-2013.  The pilot program results in no impact to earnings and allows for an increased contribution to fixed costs for all ES customers.  PSNH cannot predict if the upward pressure on ES rates due to customer migration will continue into the future, as future migration levels are dependent on market prices and supplier alternatives.  If future market prices once more exceed the average ES rate level, some or all of the customers on third party supply may migrate back to PSNH.

On January 18, 2013, the NHPUC opened a docket to investigate market conditions affecting PSNH’s ES rate, how PSNH will maintain just and reasonable rates in light of those conditions, and any impact of PSNH’s generation ownership on the New Hampshire competitive electric market.  On July 15, 2013, the NHPUC accepted from the NHPUC Staff a "Report on Investigation into Market Conditions, Default Service Rate, Generation Ownership and Impact on the Competitive Electricity Market."  The report recommended that the NHPUC examine whether default service rates remain sustainable on a going forward basis, define "just and reasonable" with respect to default service in the context of competitive retail markets, analyze the current and expected value of PSNH’s generating units, and identify means to mitigate and address stranded cost recovery.  

On September 18, 2013, the NHPUC issued a Request for Proposal to hire a valuation expert to determine the value of PSNH's generation assets and entitlements.  On October 16, 2013, the State of New Hampshire Legislative Oversight Committee on Electric

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Utility Restructuring (Oversight Committee) requested that the NHPUC conduct an analysis to determine whether it is now in the economic interest of PSNH’s retail customers for PSNH to divest its interest in generation plants.  On November 1, 2013, the Oversight Committee asked for a preliminary report on the findings by April 1, 2014 that would include at a minimum the NHPUC Staff’s position, the analysis of the valuation expert, and any recommendations for legislation that may be needed concerning divestiture or otherwise related to this issue.  A valuation expert has been hired and the investigation is currently ongoing.  At this time, we cannot predict the outcome of this review.  Our current PSNH generation rate base totals approximately $760 million.  We continue to believe all costs and generation investments are probable of recovery.

On June 28, 2010, the NHPUC approved a joint settlement of PSNH's distribution rate case.  Under the approved settlement, if PSNH's 12-month rolling average ROE for distribution exceeds 10 percent, amounts over the 10 percent level are to be allocated 75 percent to customers and 25 percent to PSNH.  Additionally, the settlement provided that the authorized regulatory ROE on distribution plant would continue at the previously allowed level of 9.67 percent, and also permitted PSNH to file a request to collect certain exogenous costs and a defined series of step increases.  In 2013, PSNH filed for a distribution rate step increase.  On June 27, 2013, the NHPUC approved an increase to rates of $12.6 million, effective July 1, 2013.  The increase consists primarily of $7.7 million related to net plant additions and a $5 million increase to the current level of funding for the Major Storm Cost reserve.  

The rates established by the NHPUC for PSNH include the following:

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An energy charge for customers who are not taking power from competitive energy suppliers.  The default energy service charge, or ES rate, is charged to customers who have never chosen competitive energy supply.  This charge recovers the costs of PSNH’s generation as well as purchased power and includes the NHPUC allowed ROE of 9.81 percent on PSNH’s generation investment.  Rate ADE is charged to certain customers who have returned to PSNH from competitive energy supply.  This rate allows PSNH to recover the forecast marginal cost of energy plus an adder for fixed costs.

·

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 plans to substations, including costs allocated by ISO-NE to maintain the wholesale electric market.

·

A stranded cost recovery charge (SCRC), which allows PSNH to recover its stranded costs, including above-market expenses incurred under mandated power purchase obligations and other long-term investments and obligations.  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 system benefits charge 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.  Expense/revenue reconciliation amounts for the energy charge and SCRC are recovered in subsequent rates.  The Rate ADE reconciliation amount is incorporated into the ES reconciliation.

Sources and Availability of Electric Power Supply

During 2013, approximately 68 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 third parties.  The remaining 32 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 2014 in a similar manner.  Included in the 68 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.

2013, 2012 and 2011 Major Storms

Over the past three years, CL&P, NSTAR Electric, PSNH and WMECO each experienced significant storms, including Tropical Storm Irene, the October 2011 snowstorm, Storm Sandy, and the February 2013 blizzard.  As a result of these storms, each electric utility company suffered damage to its distribution and transmission systems, which caused customer outages and required the incurrence of costs to repair significant damage and restore customer 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 our response to each of these storms was prudent and therefore we believe it is probable that CL&P, NSTAR Electric, PSNH and WMECO will be allowed to recover the deferred storm restoration costs.  Each electric utility company is seeking recovery of its deferred storm restoration costs through its applicable regulatory recovery process.  

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CL&P 2013 Storm Filing :  In March 2013, CL&P filed a request with PURA for approval to recover storm restoration costs associated with five major storms, all of which occurred in 2011 and 2012.  CL&P's deferred storm restoration costs associated with these major storms totaled $462 million.  Of that amount, approximately $414 million is subject to recovery in rates after giving effect to CL&P’s agreement to forego the recovery of $40 million of previously deferred storm restoration costs as well as an existing storm reserve fund balance of approximately $8 million.  During the second half of 2013, the PURA proceeded with the storm recovery review issuing discovery, holding hearings and ultimately on February 3, 2014, issuing a draft decision on the level of storm costs recovery.

In its draft decision, the PURA approved recovery of $365 million of deferred storm restoration costs and ordered CL&P to capitalize approximately $18 million of the deferred storm restoration costs as utility plant, which will be included in depreciation expense in future rate proceedings.  PURA will allow recovery of the $365 million with carrying charges in CL&P’s distribution rates over a six year period beginning December 1, 2014.  The remaining costs were either disallowed or are probable of recovery in future rates and did not have a material impact on CL&P’s financial position, results of operations or cash flows.   The final decision is expected from PURA in the first quarter of 2014.

NSTAR Electric 2013 Storm Filing :  On December 30, 2013, the DPU approved NSTAR Electric’s request to recover storm restoration costs, plus carrying costs, related to Tropical Storm Irene and the October 2011 snowstorm.  The DPU approved recovery of $34.2 million of the $38 million requested costs.  NSTAR Electric will recover these costs, plus carrying costs, in its distribution rates over a five-year period that commenced on January 1, 2014.

PSNH Major Storm Cost Reserve :  On June 27, 2013, the NHPUC approved an increase to PSNH’s distribution rates effective July 1, 2013 that included a $5 million increase to the current level of funding for the major storm cost reserve.

WMECO SRRCA Mechanism :   WMECO has an established Storm Reserve Recovery Cost Adjustment (SRRCA) mechanism to recover the restoration costs associated with its major storms.  Effective January 1, 2012, WMECO began recovering the restoration costs of Tropical Storm Irene and other storms that took place prior to August 2011.  On August 30, 2013, WMECO submitted its 2013 Annual SRRCA filing to begin recovering the restoration costs associated with the October 2011 snowstorm and Storm Sandy.  On December 20, 2013, the DPU approved the 2013 Annual SRRCA filing for effect on January 1, 2014, subject to further review and reconciliation.

2013, 2012 and 2011 Major Storm Deferrals :   As of December 31, 2013, the storm restoration costs deferred for recovery from customers for major storms that occurred during 2013, 2012 and 2011 at CL&P, NSTAR Electric, PSNH, and WMECO were as follows:

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 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

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transmission rates provide for the annual reconciliation and recovery or refund 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 Complaint

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

On September 30, 2011, several New England state attorneys general, state regulatory commissions, consumer advocates and other parties filed a joint complaint with the FERC under Sections 206 and 306 of the Federal Power Act alleging that the base ROE used in calculating formula rates for transmission service under the ISO-NE Open Access Transmission Tariff by NETOs, including CL&P, NSTAR Electric, PSNH and WMECO, is unjust and unreasonable.  The complainants asserted that the current 11.14 percent rate, which became effective in 2006, is excessive due to changes in the capital markets and are seeking an order to reduce the rate, which would be effective October 1, 2011.  In response, the NETOs filed testimony and analysis based on standard FERC methodology and precedent demonstrating that the base ROE of 11.14 percent remained just and reasonable.  The FERC set the case for trial before a FERC ALJ after settlement negotiations were unsuccessful in August 2012.

Hearings before the FERC ALJ were held in May 2013, followed by the filing of briefs by the complainants, the Massachusetts municipal electric utilities (late interveners to the case), the FERC trial staff and the NETOs.  The NETOs recommended that the current base ROE of 11.14 percent should remain in effect for the refund period (October 1, 2011 through December 31, 2012) and the prospective period (beginning when FERC issues its final decision).  The complainants, the Massachusetts municipal electric utilities, and the FERC trial staff each recommended a base ROE of 9 percent or below.

On August 6, 2013, the FERC ALJ issued an initial decision, finding that the base ROE in effect from October 2011 through December 2012 was not reasonable under the standard application of FERC methodology, but leaving policy considerations and additional adjustments to the FERC.  Using the established FERC methodology, the FERC ALJ determined that separate base ROEs should be set for the refund period and the prospective period.  The FERC ALJ found those base ROEs to be 10.6 percent and 9.7 percent, respectively.  The FERC may adjust the prospective period base ROE in its final decision to reflect movement in 10-year Treasury bond rates from the date that the case was filed (April 2013) to the date of the final decision.  The parties filed briefs on this decision with the FERC, and a decision from the FERC is expected in 2014.  Though NU cannot predict the ultimate outcome of this proceeding, in 2013 the Company recorded a series of reserves at its electric subsidiaries to recognize the potential financial impact from the FERC ALJ's initial decision for the refund period.  The aggregate after-tax charge to earnings totaled $14.3 million at NU, which represents reserves of $7.7 million at CL&P, $3.4 million at NSTAR Electric, $1.4 million at PSNH and $1.8 million at WMECO.

On December 27, 2012, several additional parties filed a separate complaint concerning the NETOs' base ROE with the FERC.  This complaint seeks to reduce the NETOs’ base ROE effective January 1, 2013, effectively extending the refund period for an additional 15 months, and to consolidate this complaint with the joint complaint filed on September 30, 2011.  The NETOs have asked the FERC to reject this complaint.  The FERC has not yet acted on this complaint, and management is unable to predict the ultimate outcome or estimate the impacts of this complaint on the financial position, results of operations or cash flows.

As of December 31, 2013, the CL&P, NSTAR Electric, PSNH, and WMECO aggregate shareholder equity invested in their transmission facilities was approximately $2.3 billion.  As a result, each 10 basis point change in the prospective period authorized base ROE would change annual consolidated earnings by an approximate $2.3 million.

Transmission Projects

NEEWS:  GSRP, the first, largest and most complicated project within the NEEWS family of projects was fully energized on November 20, 2013.  The project involved the construction of 115 kV and 345 kV overhead lines by CL&P and WMECO from Ludlow, Massachusetts to Bloomfield, Connecticut.  This transmission upgrade ensures the reliable flow of power in and around the southern New England area and enables access to less expensive generation, further reducing the risk of congestion costs impacting New England customers.  The project was fully energized ahead of schedule with a final cost of $676 million, $42 million under the $718 million estimated cost.  As of December 31, 2013, CL&P and WMECO have placed $628.2 million in service.  

The Interstate Reliability Project, which includes CL&P’s construction of an approximately 40-mile, 345 kV overhead line from Lebanon, Connecticut to the Connecticut-Rhode Island border in Thompson, Connecticut where it will connect to transmission enhancements being constructed by National Grid, is the second major NEEWS project.  All siting applications have been filed by CL&P and National Grid.  The Connecticut and Rhode Island portions of the project have been approved and a siting approval decision in Massachusetts is expected in early 2014.  On February 12, 2014, the Army Corps of Engineers issued its permit enabling construction on the Connecticut portion of the project.  This is the final permit for the Connecticut portion of the project.  NU’s portion of the cost is estimated to be $218 million and the project is expected to be placed in service in late 2015.

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The Greater Hartford Central Connecticut Study (GHCC), which includes the reassessment of the Central Connecticut Reliability Project, continues to make progress.  The final need results, which were presented to the ISO-NE Planning Advisory Committee in November 2013, showed existing and worsening severe regional and local thermal overloads and voltage violations within and across each of the four study areas.  ISO-NE is expected to confirm the preferred transmission solutions in the first half of 2014, which are likely to include many 115 kV upgrades.  We continue to expect that the specific future projects being identified to address these reliability concerns will cost approximately $300 million and that the project will be placed in service in 2017.  

Included as part of NEEWS are associated reliability related projects, $90.8 million of which have been placed in service.  As of December 31, 2013, the remaining construction on the associated reliability related projects totaled $2.8 million, which is scheduled to be completed by mid-2014.   

Through December 31, 2013, CL&P and WMECO capitalized $252.8 million and $567 million, respectively, in costs associated with NEEWS, of which $40.8 million and $48.9 million, respectively, were capitalized in 2013.    

Cape Cod Reliability Projects:  Transmission projects serving Cape Cod in the Southeastern Massachusetts (SEMA) reliability region consist of an expansion and upgrade of NSTAR Electric's existing transmission infrastructure including construction of a new 345 kV transmission line that crosses the Cape Cod Canal and associated 115 kV upgrades in the center of Cape Cod (Lower SEMA Project) and related 115 kV projects (Mid-Cape Project).  The Lower SEMA Project line work was completed and placed into service in 2013.  The Mid-Cape Project is scheduled to be completed in 2017.  The aggregate estimated construction cost for the Cape Cod projects is expected to be approximately $150 million.  Through December 31, 2013, NSTAR Electric has invested $96 million in costs associated with the Cape Cod Reliability Projects, of which $61 million was capitalized in 2013.  

Northern Pass:   Northern Pass is NPT'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.  Northern Pass will interconnect at the Québec-New Hampshire border with a planned HQ HVDC transmission line.  The $1.4 billion project is subject to comprehensive federal and state public permitting processes and is expected to be operational by mid-2017.  On July 1, 2013, NPT filed an amendment to the DOE Presidential Permit Application for a proposed improved route in the northernmost section of the project area.  As of December 31, 2013, the DOE had completed its public scoping meeting process and the majority of its seasonal field work and environmental data collection.  NPT expects to file its state permit application in the fourth quarter of 2014 after the DOE’s draft Environmental Impact Statement (EIS) is received.  

NPT filed an amendment to the Transmission Services Agreement (TSA) with FERC on December 11, 2013, which was accepted by the FERC on January 13, 2014.  The TSA amendment that went into effect on February 14, 2014 extended certain deadlines to provide project flexibility and eliminated a penalty payment for termination of the project in the future.  

On December 31, 2013, NPT received ISO-NE approval under Section I.3.9 of the ISO tariff.  By approving the project’s Section I.3.9 application, ISO-NE determined that Northern Pass can reliably interconnect with the New England grid with no significant, adverse effect on the reliability or operating characteristics of the regional energy grid and its participants.  

Greater Boston Reliability and Boston Network Improvements:   As a result of continued analysis of the transmission needs to enhance system reliability and improve capacity in eastern Massachusetts, NSTAR Electric expects to implement a series of new transmission initiatives over the next five years.  We expect projected costs to be approximately $440 million on these new initiatives.

Transmission Rate Base

Under our FERC-approved tariff, transmission projects generally enter rate base after they are placed in commercial operation.  At the end of 2013, our estimated transmission rate base was approximately $4.4 billion, including approximately $2.2 billion at CL&P, $1.1 billion at NSTAR Electric, $468 million at PSNH, and $597 million at WMECO.

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A summary of NSTAR Gas’ and Yankee Gas’ retail firm natural gas sales and percentage changes in million cubic feet for 2013, as compared to 2012, is as follows:

⁽¹⁾

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

⁽²⁾

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

Our 2013 consolidated firm natural gas sales are subject to many of the same influences as our retail electric sales, but have benefitted from favorable natural gas prices and customer growth across all three customer classes.  Our 2013 consolidated firm natural gas sales were higher, as compared to 2012, due primarily to colder weather in the first and fourth quarters of 2013.  The 2013 weather-normalized NU consolidated total firm natural gas sales increased 0.9 percent, as compared to 2012, due primarily to residential customer growth, an increase in natural gas conversions, the migration of interruptible customers switching to firm service rates, and the addition of gas-fired distributed generation, all of which was primarily in the Yankee Gas service territory.

NSTAR GAS

NSTAR Gas distributes natural gas to approximately 274,000 customers in 51 communities in central and eastern Massachusetts covering 1,067 square miles.  Total throughput (sales and transportation) in 2013 was approximately 60.5 Bcf.  NSTAR Gas provides firm natural gas sales service to retail customers who require a continuous natural gas supply throughout the year, such as residential customers who rely on gas for heating, hot water and cooking needs, and commercial and industrial customers who choose to purchase natural gas from NSTAR Gas.  

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.  NSTAR Gas offers firm transportation service to all customers who purchase gas from sources other than NSTAR Gas as well as interruptible transportation and interruptible gas sales service to those commercial and industrial customers that have the capability to switch from natural gas to an alternative fuel on short notice, for whom NSTAR Gas can interrupt service during peak demand periods or at any other time to maintain distribution system integrity.

Rates

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

The Attorney General merger settlement agreement provided for a rate freeze through 2015.

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

·

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

·

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

·

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

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

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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 2013 performance as it achieved results at or above target for all of its SQ metrics in 2013.

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 from a firm portfolio management contract with a term of one year, which has a maximum quantity of approximately 139,500 MMBtu/day.

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

A portion of the storage of natural gas supply for NSTAR Gas during the winter heating season is provided by Hopkinton, a wholly-owned subsidiary of Yankee Energy Systems, Inc.  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.

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

YANKEE GAS

Yankee Gas operates the largest natural gas distribution system in Connecticut as measured by number of customers (approximately 218,000 customers in 71 cities and towns), and size of service territory (2,187 square miles).  Total throughput (sales and transportation) in 2013 was approximately 55 Bcf.  Yankee Gas provides firm natural gas sales service to retail customers who require a continuous natural gas supply throughout the year, such as residential customers who rely on natural gas for heating, hot water and cooking needs, and commercial and industrial customers who choose to purchase natural gas from Yankee Gas.  Yankee Gas also owns a 1.2 Bcf LNG facility in Waterbury, Connecticut, which is used primarily to assist it in meeting its supplier-of-last-resort obligations and also enables it to make economic purchases of natural gas, which typically occur during periods of low demand.

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

Rates

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

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

·

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

·

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

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·

Conservation Adjustment Mechanism (CAM), 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 revenue to expenses is performed annually with any difference being recovered or refunded with carrying charges in future customer rates the following year.

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

Sources and Availability of Natural Gas Supply

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

PROJECTED CAPITAL EXPENDITURES

We project to make capital expenditures of approximately $7.6 billion from 2014 through 2017.  Of the $7.6 billion, we expect to invest approximately $3.5 billion in our electric and natural gas distribution segments and $3.7 billion in our electric transmission segment.  In addition, we project to invest approximately $400 million for our corporate service companies.

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, 2013, a total of $501.7 million of NU's long-term debt will be paid in the next 12 months, consisting of $150 million for CL&P, $301.7 million for NSTAR Electric and $50 million or PSNH.  

NUCLEAR DECOMMISSIONING

General

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 collects decommissioning and closure costs through wholesale FERC-approved rates charged under power purchase agreements with CL&P, NSTAR Electric, PSNH and WMECO and several other New England utilities.  These companies in turn recover these costs from their customers through state regulatory commission-approved retail rates.  

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

Our share of the obligations to support the Yankee Companies under FERC-approved contracts is the same as the ownership percentages above.  As a result of the Merger, we consolidate the assets and obligations of CYAPC and YAEC on our consolidated balance sheet.

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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 our facilities.  In each of the last three years, the costs incurred by PSNH related to compliance with NPDES and state discharge permits have not been material.

On September 29, 2011, the EPA issued for public review and comment a draft renewal NPDES permit under the Clean Water Act for PSNH’s Merrimack Station.  The draft permit would require PSNH to install a closed-cycle cooling system at the station.  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 fossil 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 SO ₂ and NO _X for the purpose of controlling acid rain and ground level ozone.  In addition, the CAAA address the control of toxic air pollutants.  Requirements for the installation of continuous emissions monitors and expanded permitting provisions also are included.

In December 2011, the EPA finalized the Mercury and Air Toxic Standards (MATS) that require the reduction of emissions of hazardous air pollutants from new and existing coal- and oil-fired electric generating units.  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 units.  MATS is the first implementation of a nationwide emissions standard for hazardous air pollutants across all electric generating units and provides utility companies with up to five years to meet the requirements.  PSNH owns and operates approximately 1,000 MW of fossil fueled electric generating units subject to MATS, including the two units at Merrimack Station, Newington Station and the two coal units at Schiller Station.  We believe the Clean Air Project at our Merrimack Station, together with existing equipment, will enable the facility to meet the MATS requirements.  A review of the potential impact of MATS on our other PSNH units is not yet complete.  Additional incremental controls may be required for the two coal fired units at Schiller Station.  To date, the financial impact of this potential control has not been determined.

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 2013, the total RPS obligation was 11.65 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 and purchased 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 2013, the total RPS obligation was 17 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 rates.

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Massachusetts’ RPS program also requires electricity suppliers to meet renewable energy standards.  For 2013, the requirement was 15.1 percent, and will ultimately reach 27.1 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 estimated environmental investigation and/or remediation costs for waste disposal sites for which we expect to bear legal 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, 2013, the liability recorded by us for our reasonably estimable and probable environmental remediation costs for known sites needing investigation and/or remediation, exclusive of recoveries from insurance or from third parties, was approximately $35.4 million, representing 68 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, through our subsidiaries, currently have partial or full ownership responsibilities at former MGP sites that have a reserve balance of $31.4 million of the total $35.4 million as of December 31, 2013.  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 SF ₆ gas and methane.

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

Connecticut, New Hampshire and Massachusetts are each members of the Regional Greenhouse Gas Initiative (RGGI), a cooperative effort by nine northeastern and mid-Atlantic states, to develop a regional program for stabilizing and reducing CO ₂ emissions from fossil fueled electric generating plants.  Because CO ₂ allowances issued by any participating state are usable across all nine RGGI state programs, the individual state CO ₂ trading programs, in the aggregate, form one regional compliance market for CO ₂ emissions.  A regulated power plant must hold CO ₂ allowances equal to its emissions to demonstrate compliance at the end of a three year compliance period that began in 2012.

PSNH anticipates that its generating units will emit between two million and four million tons of CO ₂ per year, depending on the capacity factor and the utilization of the respective generation plant, excluding emissions from the operation of PSNH’s Northern Wood Power Project.  New Hampshire legislation provides up to 1.5 million banked CO ₂ allowances per year for PSNH’s fossil fueled electric generating plants during the 2012 through 2014 compliance period.  PSNH expects to satisfy its remaining RGGI requirements by purchasing CO ₂ allowances at auction or in the secondary market. The cost of complying with RGGI requirements is recoverable from

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PSNH customers.  Current legislation provides a 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 two solar photovoltaic facilities owned by WMECO that do not emit CO ₂ ), none of them is required to acquire CO ₂ allowances.  However, the CO ₂ allowance costs borne by the generating facilities that are utilized by wholesale 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 involved with the early stages of relicensing at its Eastman Falls Hydro Station, which is comprised of two units, totaling 6.5 MW.

EMPLOYEES

As of December 31, 2013, NU employed a total of 8,697 employees, excluding temporary employees, of which 1,566 were employed by CL&P, 1,025 were employed by PSNH, 308 were employed by WMECO, and 2,194 were employed by NSTAR Electric.  Approximately 48 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.nu.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.  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.

Item 1A.

Risk Factors

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

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

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

Acts of war or terrorism could target our generation, transmission and distribution facilities or our data management systems.  Such actions could impair our ability to manage these facilities or operate our system effectively, resulting in loss of service to customers.  

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

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

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

We have a significant amount of goodwill on our consolidated balance sheet.  The carrying value of goodwill represents the fair value of an acquired business in excess of identifiable assets and liabilities as of the acquisition date.  As of December 31, 2013, goodwill totaled $3.5 billion, of which $3.2 billion was attributable to the acquisition of NSTAR in April 2012.  Total goodwill represented approximately 36 percent of our $9.6 billion of shareholders’ equity and approximately 13 percent of our total assets of $27.8 billion.  We test our goodwill balances for impairment on an annual basis or whenever events occur or circumstances change that would indicate a potential for impairment.  A determination that goodwill is deemed to be impaired would result in a non-cash charge that could materially adversely affect our results of operations and total capitalization.  The annual goodwill impairment test in 2013 resulted in a conclusion that goodwill is not impaired.

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

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

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

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

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

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

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

·

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

·

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

·

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

·

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

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

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

The rates that our Regulated companies charge their respective retail and wholesale customers are determined by their state utility commissions and by FERC.  These commissions also regulate the companies’ accounting, operations, the issuance of certain securities and certain other matters.  FERC also regulates their transmission of electric energy, the sale of electric energy at wholesale, accounting, issuance of certain securities and certain other matters.  The commissions’ policies and regulatory actions could have a material impact on the Regulated companies’ financial position, results of operations and cash flows.

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

Our ability to properly operate our transmission, distribution and generation systems is critical to the financial performance of our business.  Our transmission, distribution and generation businesses face several operational risks, including the breakdown or failure of or damage to equipment or processes (especially due to age); labor disputes; disruptions in the delivery of electricity and natural gas, including impacts on us or our customers; increased capital expenditure requirements, including those due to environmental regulation; information security risk, such as a breach of our systems on which sensitive utility customer data and account information are stored; catastrophic events such as fires, explosions, or other similar occurrences; extreme weather conditions beyond equipment and plant design capacity; other unanticipated operations and maintenance expenses and liabilities; and potential claims for property damage or personal injuries beyond the scope of our insurance coverage.  The failure of our transmission, distribution and generation systems to operate as planned may result in increased capital costs, reduced earnings or unplanned increases in operation and maintenance costs.  At PSNH, outages at generating stations may be deemed imprudent by the NHPUC resulting in disallowance of replacement power costs.  Such costs that are not recoverable from our customers would have an adverse effect on our financial position, results of operations and cash flows.

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

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

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

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

Difficulties in obtaining necessary rights of way, or siting, design or other approvals for major transmission projects, environmental concerns or actions of regulatory authorities, communities or strategic partners may cause delays or cancellation of such projects, which would adversely affect our earnings.

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

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

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

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

Many of our transmission projects are expected to help alleviate identified reliability issues and reduce customers' costs.  However, if, due to economic events or factors or further regulatory or other delays, the in-service date for one or more of these projects is delayed, there may be increased risk of failures in the electricity transmission system and supply interruptions or blackouts, which could have an adverse effect on our earnings.

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

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

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

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

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

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

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

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

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

Under state law, our Regulated companies are entitled to charge rates that are sufficient to allow them an opportunity to recover their reasonable operating and capital costs, to attract needed capital and maintain their financial integrity, while also protecting relevant public interests.  Each of these companies prepares and submits periodic rate filings with their respective state regulatory commissions for review and approval.  There is no assurance that these state commissions will approve the recovery of all such costs incurred by our Regulated companies, such as for construction, operation and maintenance, as well as a return on investment on their respective regulated assets.  The amount of costs incurred by the Regulated companies, coupled with increases in fuel and energy prices, could lead to consumer or regulatory resistance to the timely recovery of such costs, thereby adversely affecting our financial position, results of operations or cash flows.  

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

In addition, CL&P, NSTAR Electric and WMECO procure energy for a substantial portion of their customers’ needs via requests for proposal on an annual, semi-annual or quarterly basis.  CL&P, NSTAR Electric and WMECO receive approval to recover the costs of these contracts from the PURA and DPU, respectively.  While both regulatory agencies have consistently approved the solicitation processes, results and recovery of costs, management cannot predict the outcome of future solicitation efforts or the regulatory proceedings related thereto.

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

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Migration of customers from PSNH energy service to competitive energy suppliers may increase the cost to the remaining customers of energy produced by PSNH generation assets.

The competitiveness of PSNH’s ES rates are sensitive to the cost of fuels, most notably natural gas, and customer load.  Recently, PSNH’s ES rate has been higher than competitive energy prices offered to some customers.  Further increases may occur as the costs associated with the Clean Air Project are included in rates.  Customers remaining on PSNH’s ES rate may experience an increase in cost due to the lower base over which to recover PSNH's fixed generation costs.  Any such increase may in turn cause further migration and further impact PSNH’s ES rate.  This trend could lead to PSNH continuing to lose energy supply customers and increasing the burden of supporting the cost of its generation facilities on remaining customers and being unable to support the cost of its generation facilities through an ES rate, which could have an adverse impact on its financial position, results of operations and cash flows.

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

Pursuant to New Hampshire law, PSNH placed the Clean Air Project in service at its Merrimack Station.  PSNH’s recovery of costs in constructing the project is subject to prudence review by the NHPUC.  A material prudence disallowance could adversely affect PSNH’s financial position, results of operations or cash flows.  While we believe we have prudently incurred all expenditures to date, we cannot predict the outcome of any prudence reviews.  Our projected earnings and growth could be adversely affected were the NHPUC to deny recovery of some or all of PSNH’s investment in the project.

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

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

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

We provide a defined benefit pension plan and other post-retirement benefits for a substantial number of employees, former employees and retirees.  Our future pension obligations, costs and liabilities are highly dependent on a variety of factors beyond our control.  These factors include estimated investment returns, interest rates, discount rates, health care cost trends, benefit changes, salary increases and the demographics of plan participants.  If our assumptions prove to be inaccurate, our future costs could increase significantly.  In 2008 and 2009, due to the financial crisis, the value of our pension assets declined.  As a result, in 2013, NU made contributions to the NUSCO Pension Plan totaling $202.7 million and NSTAR Electric contributed $82 million to the NSTAR Pension Plan.  We expect to make contributions in 2014 totaling $71.6 million.  In addition, various factors, including underperformance of plan investments and changes in law or regulation, could increase the amount of contributions required to fund our pension plan in the future.  Additional large funding requirements, when combined with the financing requirements of our construction program, could impact the timing and amount of future equity and debt financings and negatively affect our financial position, results of operations or cash flows.  

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

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

In addition, global climate change issues have received an increased focus from federal and state governments, which could potentially lead to additional rules and regulations that impact how we operate our business, both in terms of the power plants we own and operate as well as general utility operations.  Although we would expect that any costs of these rules and regulations would be recovered from customers, their impact on energy use by customers and the ultimate impact on our business would be dependent upon the specific rules and regulations adopted and cannot be determined at this time.  The impact of these additional costs to customers could lead to a further reduction in energy consumption resulting in a decline in electricity and gas sales in our service territories, which would have an adverse impact on our business and financial position, results of operations or cash flows.

Any failure by us to comply with environmental laws and regulations, even if due to factors beyond our control, or reinterpretations of existing requirements, could also increase costs.  Existing environmental laws and regulations may be revised or new laws and regulations seeking to protect the environment may be adopted or become applicable to us.  Revised or additional laws could result in

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significant additional expense and operating restrictions on our facilities or increased compliance costs, which may not be fully recoverable in distribution company rates.  The cost impact of any such laws, rules or regulations would be dependent upon the specific requirements adopted and cannot be determined at this time.  For further information, see Item 1, Business - Other Regulatory and Environmental Matters , included in this Annual Report on Form 10-K.

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

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

Item 1B.