UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act:

NSTAR Electric Company, Public Service Company of New Hampshire and Western Massachusetts Electric Company each meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and areeach is therefore filing this Form 10-K with the reduced disclosure format specified in General Instruction I(2) to Form 10-K.  

Indicate by check mark if the registrants are well-known seasoned issuers, as defined in Rule 405 of the Securities Act.

Indicate by check mark if the registrants are not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.

Indicate by check mark whether the registrants have submitted electronically and posted on its corporate Web sites, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrants' knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  [ü]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer.  See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act.  (Check one):

Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act).  :

The aggregate market value ofNortheast Utilities’ Common Shares, $5.00 par value, held by non-affiliates, computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of Northeast Utilities’ most recently completed second fiscal quarter (June 30, 2010)2013) was$4,486,982,187based $13,224,337,788based on a closing sales price of$25.48per $42.02per share for the 176,098,202314,715,321 common shares outstanding on June 30, 2010.  2013.  

Northeast Utilities, directly or indirectly, holds all of the 6,035,205 shares, 100 shares, 301 shares, and 434,653 shares of the outstanding common stock ofThe Connecticut Light and Power Company, NSTAR Electric Company, Public Service Company of New Hampshireand Western Massachusetts Electric Company, respectively.

Indicate the number of shares outstanding of each of the registrants'issuers' classes of common stock, as of the latest practicable date:

Documents Incorporated by Reference:

GLOSSARY OF TERMS

ii

Variable interest entity 

WWL Project

The construction of a 16-mile gas pipeline between Waterbury and Wallingford, Connecticut and the increase of vaporization output of Yankee Gas' LNG plant

YAEC

Yankee Atomic Electric Company

Yankee Companies

Connecticut Yankee Atomic Power Company, Yankee Atomic Electric Company and Maine Yankee Atomic Power Company

iii

NORTHEAST UTILITIES

AND SUBSIDIARIES
THE CONNECTICUT LIGHT AND POWER COMPANY

NSTAR ELECTRIC COMPANY AND SUBSIDIARY
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE

AND SUBSIDIARY
WESTERN MASSACHUSETTS ELECTRIC COMPANY

2013 FORM 10-K ANNUAL REPORT

2010 Form 10-K Annual ReportTABLE OF CONTENTS
Table of Contents

iii

iv

NORTHEAST UTILITIES AND SUBSIDIARIES

THE CONNECTICUT LIGHT AND POWER COMPANY

NSTAR ELECTRIC COMPANY AND SUBSIDIARY

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY

WESTERN MASSACHUSETTS ELECTRIC COMPANY

SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES

LITIGATION REFORM ACT OF 1995

References in this Annual Report on Form 10-K to "NU," "we," "our," and "us" refer to Northeast Utilities and its consolidated subsidiaries.subsidiaries, including NSTAR and its subsidiaries for periods after April 10, 2012.

From time to time we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, assumptions of future events, future financial performance or growth and other statements that are not historical facts.  These statements are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995.  You can generally identify our forward-looking statements through the use of words or phrases such as "estimate," "expect," "anticipate," "intend," "plan," "project," "believe," "forecast," "should," "could," and other similar expressions.  Forward-looking statements are based on the current expectations, estimates, assumptions or projections of management and are not guarantees of future performance.  These expectations, estimates, assumptions or projections ma ymay vary materially from actual results.  Accordingly, any such statements are qualified in their entirety by reference to, and are accompanied by, the following important factors that could cause our actual results to differ materially from those contained in our forward-looking statements, including, but not limited to:

·

cyber breaches, acts of war or terrorism, or grid disturbances,

·

the possibility that expected merger synergies will not be realized or will not be realized within the expected time period,

·

actions or inaction byof local, state and federal regulatory and taxing bodies,

·

changes in business and economic conditions, including their impact on interest rates, bad debt expense, and demand for our products and services,

·

changesfluctuations in weather patterns,

·

changes in laws, regulations or regulatory policy,

·

changes in levels andor timing of capital expenditures,

·

disruptions in the capital markets or other events that make our access to necessary capital more difficult or costly,

·

developments in legal or public policy doctrines,

·

technological developments,

·

changes in accounting standards and financial reporting regulations,

·

fluctuations in the value of our remaining competitive contracts

·

actions of rating agencies,

·

The expected timing and likelihood of completion of the proposed merger with NSTAR, including the timing, receipt and terms and conditions of any required governmental and regulatory approvals of the proposed merger that could reduce anticipated benefits or cause the parties to abandon the merger, the diversion of management's time and attention from our ongoing business during this time period, as well as the ability to successfully integrate the businesses, and the risk that the credit ratings of the combined company or its subsidiaries may be different from what the companies expect and

·

other presently unknown or unforeseen factors.  

Other risk factors are detailed in our reports filed with the SEC and updated as necessary, and we encourage you to consult such disclosures.

All such factors are difficult to predict, contain uncertainties that may materially affect our actual results and are beyond our control.  You should not place undue reliance on the forward-looking statements, each speaks only as of the date on which such statement is made, and we undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events.  New factors emerge from time to time and it is not possible for managementus to predict all of such factors, nor can itwe assess the impact of each such factor on the business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements.  For more information, see Item 1A, Risk Factors, included in this combined Annual Report on Form 10-K. Th isThis Annual Report on Form 10-K also describes material contingencies and critical accounting policies and estimates in the accompanyingManagement’s Discussion and Analysis andCombined Notes to Consolidated Financial Statements.  We encourage you to review these items.

1

NORTHEAST UTILITIES AND SUBSIDIARIES

THE CONNECTICUT LIGHT AND POWER COMPANY

NSTAR ELECTRIC COMPANY AND SUBSIDIARY

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY

WESTERN MASSACHUSETTS ELECTRIC COMPANY

PART I

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.

PROPOSED MERGER WITH NSTAR

On October 18, 2010, we and NSTAR announced that each company’s Board of Trustees unanimously approved a Merger Agreement (the merger agreement) to combine the two companies.  The transaction was structured as a merger of equals in a tax-free exchange.  Upon the terms and subject to the conditions set forth in the merger agreement, at closing, NSTAR will become a wholly-owned subsidiary of NU.  The post-transaction company will provide electric and natural gas energy delivery service to nearly 3.5 million electric and natural gas customers through six regulated electric and natural gas utilities in Connecticut, Massachusetts and New Hampshire, representing over half of all the customers in New England.  

Under the terms of the merger agreement, NSTAR shareholders would receive 1.312 NU common shares for each common share of NSTAR that they own (the "exchange ratio").  The exchange ratio was structured to result in a no premium merger and is based on the average closing share price of each company's common shares for the 20 trading days preceding the announcement.  Following completion of the merger, common shares of the post-transaction company will be owned approximately 56 percent by NU shareholders and approximately 44 percent by former NSTAR shareholders.  We anticipate that we will issue approximately 137 million common shares to the NSTAR shareholders as a result of the merger.  Following the closing of the merger, our next quarterly dividend per common share will be increased to an amount that is equivalent to NSTAR’s last quarterly dividend per common share paid prior to the closing, divided by the exchange ratio.  Based on the last quarterly dividend paid by NSTAR of $0.425 per share, and assuming there are no changes to such dividend prior to the closing of the merger, that would result in NU’s quarterly dividend being increased by approximately 18 percent to approximately $0.325 per share, or approximately $1.30 per share on an annualized basis as compared to NU's current annualized dividend of $1.10 per share.  NU filed its joint proxy statement/prospectus with the SEC on January 5, 2011 and scheduled a special meeting of shareholders for March 4, 2011, at which shareholders will vote on whether to approve the merger.  

Completion of the merger is subject to various customary conditions, including approval by holders of two-thirds of the outstanding common shares of each company and receipt of all required regulatory approvals, including those of the Massachusetts DPU, the FERC and the NRC.  We received approval from the FCC on January 4, 2011, and on February 10, 2011, the applicable Hart-Scott-Rodino waiting period expired.  Several intervening parties have applied to participate in the regulatory review of the merger and have raised various issues that they believe the regulatory agencies should examine in the course of the proceedings.  

In November 2010, the DPUC issued a draft decision stating it lacked jurisdiction over the merger.  In December 2010, the Connecticut Office of Consumer Counsel, supported by the Connecticut Attorney General, petitioned the DPUC to reconsider its draft decision.  In January 2011, the DPUC issued an Administrative Order stating that it plans to hold a hearing to determine if it has jurisdiction over the merger.  Oral arguments surrounding the draft decision were held in February 2011.  The DPUC plans to hold an informational hearing at a date to be determined.  In addition, legislation proposing to give the DPUC jurisdiction over the merger may be introduced in the Connecticut legislature.  

THE COMPANY

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-ownedwholly owned utility subsidiaries:

●

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

●

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

●

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

●

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

●

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

●

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

NU also owns certain unregulated businesses through its wholly-ownedwholly owned subsidiary, NU Enterprises.  AsEnterprises, which is included in its Parent and other companies’ results of December 31, 2010, NU Enterprises’ business consisted of (i) Select Energy’s few remaining energy wholesale marketing contracts, which are being wound down, and (ii) NU Enterprises’ electrical contracting business.operations.

2

Although NU, CL&P, NSTAR Electric, PSNH and WMECO each report their financial results separately, weseparately.  We also include information in this report on a segment or line-of-business, basis - thefor NU.  NU recognizes three reportable segments, which are electric distribution, electric transmission and natural gas distribution.  NU’s electric distribution segment (which also 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 and our natural gas distribution business) and the transmission segment.  Our Regulated companies accounted for approximately 99 percent of our total earnings of $387.9 million for 2010, with electric distribution representing approximately 45 percent, natural gas distribution representing approximately 8 percent and electric transmission representing approximately 46 percent of consolidated earnings.  The remaining 1 percent of our 2010 earnings comes from our competitive businesses.do not report separate business segments.   

MERGER WITH NSTAR

REGULATED 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 primarily engaged in the distribution of electricity to retail customers in Connecticut, eastern Massachusetts, New Hampshire and western Massachusetts, respectively, plus PSNH’sthe regulated electric generation businessbusinesses of PSNH and WMECO’s solar generation.  WMECO.  

2

The following table shows the sources of 20102013 electric franchise retail revenues for NU’s electric distribution companies, collectively, based on categories of customers:

A summary of changes in the Regulatedour distribution companies’ retail electric GWh sales (GWh)and percentage changes for 20102013, as compared to 2009 on an actual and weather normalized basis (using a 30-year average)2012, is as follows:

Total⁽¹⁾

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

⁽²⁾

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 all three electric companies were higher in 2010CL&P, NSTAR Electric and PSNH increased while they remained unchanged for WMECO, as compared to 20092012, due primarily to warmer than normalcolder weather in the summerfirst and fourth quarters of 20102013.  In 2013, heating degree days were 17 percent higher in Connecticut and colder than normal weatherwestern Massachusetts, 16 percenthigher in December 2010.  Residential sales benefitted the most fromBoston metropolitan area, and 15 percent higher in New Hampshire, and cooling degree days were 7 percent lower in Connecticut and western Massachusetts, 2 percenthigher in the weatherBoston metropolitan area, and 9 percent lower in 2010 and were higher for all three electric companies in 2010New Hampshire, as compared to 2009.  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.

OnFor 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 weather normalized basis, retailbaseline low income discount recovery of $7 million.  These two mechanisms effectively break the relationship between sales for all three electric companies were lower in 2010 compared to 2009. We believe the decrease was due in part to increased conservation efforts by our customersvolume and the continuing effects of the weak economy.  revenues recognized.

ELECTRIC DISTRIBUTION – CONNECTICUT

THE CONNECTICUT LIGHT AND POWER COMPANY - DISTRIBUTION

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, 2010,2013, CL&P furnished retail franchise electric service to approximately 1.2 million customers in 149 cities and towns in Connecticut.Connecticut, covering an area of 4,400 square miles.  CL&P does not own any electric generation facilities.  In 2010, CL&P had contracts to purchase the electric output from eighteen IPP generators.  The term of two of these contracts ended in 2010.  In 2011 the sixteen remaining generators are anticipated to provide approximately two million MWh per year through March 2015, with purchase quantities dropping significantly from 2015 through 2024, when the term of the last IPP contract ends.  CL&P sells the output of these contracts into the ISO New England market, crediting customer energy charges with the proceeds.  CL& ;P has entered into eleven contracts with renewable energy generators under a state program known as Project 150, and UI has entered into 2 other similar contracts under Project 150.  CL&P and UI will share the costs and benefits of these contracts on an 80 percent and 20 percent basis, respectively.  This cost sharing split is independent of the specific utility that is the counterparty to the contract.  It is currently projected that the first of these renewable energy projects will commence commercial operation in 2011.

3

The following table shows the sources of 2010CL&P’s 2013 electric franchise retail revenues for CL&P based on categories of customers:

Rates

CL&P is subject to regulation by the Connecticut DPUC,PURA, which, among other things, has jurisdiction over its rates, accounting procedures, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, standards of service management efficiency 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.

The CTA is a  Connecticut utilities are entitled under state law to charge assessedrates that are sufficient to allow them an opportunity to recover strandedtheir reasonable operation and capital costs, associated with electric industry restructuring as well as various IPP contracts.  The SBC recovers costs associated with various hardshipto attract needed capital and low income programs as well as payments to municipalities to compensate them for losses in property tax revenue due to decreases in the value of electric generating facilities resulting directly from electric industry restructuring.  The CTA and SBC are annually reconciled to actual costs incurred, with any difference refunded to, or recovered from, customers.maintain their financial integrity, while also protecting relevant public interests.

Under stateConnecticut law, all of CL&P's customers are entitled to choose their energy suppliers, while CL&P remains their electric distribution company.  Under "Standard Service" rates for customers with less than 500 KW of demand and "Supplier of Last Resort Service" rates for customers with 500 KW of demand or greater, CL&P purchases power forFor 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 such customers through a combined GSC and FMCC charge on customers'customers’ bills.  The combined GSC and FMCC charges for both types of service recover all of the costs of procuring energy from CL&P's wholesale suppliers and are adjusted periodically and reconciled semi-annually in accordance with the directives of the DPUC.

Although more CL&P customers chose competitive energy suppliers in 2010 than in 2009, CL&P continues to supply approximately 4056 percent of its customer load at Standard ServiceSS or Supplier of Last Resort ServiceLRS rates while the other 6044 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.

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

·

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.

·

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.  

·

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.

·

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

·

A competitive transition 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.

·

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.  

·

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.

·

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.

4

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, the DPUCPURA issued a final order in CL&P’s most recent retail distribution rate case approving annualized distribution rate increases of $63.4 million effective July 1, 2010rates and an incremental $38.5 million effective July 1, 2011.  The 2010 increase was deferred from customer bills until January 1, 2011 to coincide with the decline in revenue requirements associated with the final payment of CL&P’s RRBs. In its decision, the DPUC also maintainedestablishing CL&P’s authorized distribution segment regulatory ROE ofat 9.4 percent.  In 2010, CL&P earned a distribution segment regulatory ROE of 7.9 percent, compared to 7.3 percent in 2009, and expects to earn a distribution segment regulatory ROE of approximately 9 percent in 2011.

In May 2010, the Connecticut Legislature approved a state budget for the 2010-2011 fiscal year, which calls for the issuance by the state of Connecticut of up to $760 million of economic recovery revenue bonds (ERRBs) that would be amortized over eight years.  These bonds will be repaid through a charge on the bills of customers of CL&P and other Connecticut electric distribution companies.  For CL&P, the revenue to pay interest and principal on the bonds would come from a continuation of a portion of its CTA, which would have otherwise ended by December 31, 2010 with the final payment of the principal and interest on its RRBs, and the diversion of about one-third of the annual funding for C&LM programs beginning in April 2012.  A lawsuit pending against the DPUC to prevent the issuance of the ERRBs is pending and several bills seeking to modify or prevent the issuance have been proposed before the state l egislature.

On March 31, 2010,13, 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 filed with the DPUC an AMI and dynamic pricing plan concluding that a full deployment of AMI meters accompanied by dynamic pricing options for all CL&P customers would be cost beneficial under a set of reasonable assumptions, identified as the "base case scenario."  Under the base case scenario, capital expenditures associated with the installation of the meters are estimated at $296 million.  CL&P has proposed beginning installation of meters in late 2012 and finishing in 2016.distribution rate freeze until December 1, 2014.

On September 19, 2013, CL&P, hasalong with another Connecticut utility, signed long-term commitments, as required by regulation, to purchase approximately 250 MW of wind power from a transmission adjustment clause as partMaine wind farm and 20 MW of its retail distribution rates, which reconciles onsolar power from sites in Connecticut, at a semi-annual basiscombined average price of less than $0.08 per kWh. On October 23, 2013, PURA issued a final decision accepting the transmission revenues billedcontracts. The two projects are expected to customers againstbe operational by the transmission costsend of acquiring such services, thereby recovering all of its transmission expenses on a timely basis.  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 Standard ServiceSS and Supplier of Last Resort ServiceLRS loads from a variety of competitive sources through periodic RFPs.requests for proposals.  CL&P enters into supply contracts for Standard ServiceSS periodically for periods of up to three years to mitigate price volatilityone year for its residential and small and medium load commercial and industrial customers.  CL&P enters into supply contracts for Supplier of Last Resort serviceLRS for larger commercial and industrial

4

customers every three months.  Currently, CL&P has contracts in place with various wholesale suppliers for allfirm requirements service for 70 percent of its Standard ServiceSS loads through 2011, 40for 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 expectedits 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 2012,the second half of 2014 from wholesale suppliers for firm requirements service and 10 percentwill self-supply the remainder needed.  None of expectedthe SS load for 2013.2015 has been procured.  CL&P’s&P has contracts in place for its Supplier of Last Resort ServiceLRS loads extend through the second quarter of 2011.2014, 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,

5

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:

·

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.

6

·

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.

·

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.

·

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

·

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

·

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.

·

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

·

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 - DISTRIBUTION

PSNH’s distribution business (which includes its generation business) consists primarily of the generation, purchase, delivery and sale of electricity to its residential, commercial and industrial customers.  As of December 31, 2010,2013, PSNH furnished retail franchise electric service to approximately 497,000500,000 retail customers in 211 cities and towns in New Hampshire.Hampshire, covering an area of 5,628 square miles.  PSNH also owns and operates approximately 1,200 MW of primarily fossil-fueled electricity generation assets.plants.  Included in those generation assetselectric generating plants is itsPSNH’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 also has contracts with 18 IPPs,PSNH’s distribution business includes the outputactivities of which it either uses to serve its customer load or sells into the market.generation business.

PSNH is constructing itsThe Clean Air Project, a sulfur dioxidewet flue gas desulphurization system (Scrubber), was constructed and mercury scrubberplaced in service by PSNH at its Merrimack coal-fired generation station,Station in September 2011.  PSNH completed remaining project construction activities in 2012 and the final cost of the project was approximately $421 million.

7

Tests to date indicate that the Scrubber reduces emissions of SO2 and mercury from Merrimack Station by over 90 percent, which is currently expectedwell in excess of state and federal requirements.

Prudent Scrubber costs are allowed to cost $430 million.  The project is scheduled for completion in mid-2012.  PSNH will recover all related costsbe recovered through itsPSNH's ES rates described below.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 accompanyingManagement’s Discussion and Analysis.

The following table shows the sources of 2010PSNH’s 2013 electric franchise retail revenues based on categories of customers:

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 management efficiency and construction and operation of facilities.

PSNH’s ES rate recovers its generation 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 purchased powercapital costs, from customers on a current basisto attract needed capital and allows for an ROE of 9.81 percent on its generation investment.  maintain their financial integrity, while also protecting relevant public interests.

Under New Hampshire law, the SCRC allows PSNH to recover its stranded costs, including expenses incurred under mandated power contracts and other long-term investments and obligations.  PSNH has financed a significant portionall of its stranded costs through securitization by issuing RRBs secured by the right to recover these stranded costs from customers over time and recovers the costs of these bonds through the SCRC rate.  

On an annual basis, PSNH files with the NHPUC an ES/SCRC reconciliation filing for the preceding year.  The difference between ES/SCRC revenues and ES/SCRC costs are included in the ES/SCRC rate calculations and refunded to/recovered from customers in the subsequent period approved by the NHPUC.  

The TCAM allows PSNH to recover on a fully reconciling basis its transmission related costs.  The TCAM is adjusted July 1 of each year.

Distribution Rates:  On June 28, 2010, the NHPUC approved a joint settlement of PSNH’s rate case that had commenced in 2009, allowing a net distribution rate increase of $45.5 million on an annualized basis to be effective July 1, 2010, and annualized distribution rate adjustments projected to be a decrease of $2.9 million and increases of $9.5 million and $11.1 million on July 1 of each of the three subsequent years, respectively.  PSNH agreed not to file a new distribution rate request that would be effective prior to July 1, 2015.  During the term of the settlement, PSNH can only propose changes to its permanent distribution rate level when its 12-month distribution ROE falls below 7 percent for two consecutive quarters or certain specified external events, such as major storms, occur.  If PSNH’s 12-month ROE rolling average is greater than 10 percent, anything over the 10 percent level will be all ocated 75 percent to customers and 25 percent to PSNH.  The settlement also provided that the authorized regulatory ROE on distribution only plant will continue at the previously allowed level of 9.67 percent.  PSNH’s distribution segment regulatory ROE was 10.2 percent (including generation) in 2010, compared to 7.2 percent in 2009.  We expect PSNH’s distribution segment regulatory ROE will be approximately 9 percent in 2011.

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 2010,2013, approximately 225 percent of all of PSNH’s customers (approximately 3254 percent of load), mostly large commercial and industrial 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 sal es

5

sales volume.  The customers that didhave not switch tochosen a third party supplier, predominatelypredominantly residential and small commercial and industrial customers, are now paying a larger proportion of these fixed costs.

The  On July 26, 2011, the NHPUC openedordered PSNH to file a proceeding in 2010 to considerrate proposal that would mitigate the effectimpact of customer migration onexpected to occur when the ES rates for customers, principally residential and small commercial and industrial customers, remaining on PSNH default energy service.  As part of this docket,rate is higher than market prices.  On April 8, 2013, the NHPUC stated its intentionissued 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 exploreaddress customer migration.  The NHPUC condition was accepted by the interplaySettling Parties and incorporated into the initial implementation of customer choice, migration issuesRate ADE in mid-2013.  The pilot program results in no impact to earnings and power procurement optionsallows for PSNH.

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 customer migration levels which are dependent on market prices and supplier alternatives, are uncertain.alternatives.  If future market prices once more exceed the average ES rate level, some or all of thesethe 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

8

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:

·

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 2010, about 882013, 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 1232 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 20112014 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.  

9

WESTERN MASSACHUSETTS ELECTRIC COMPANY - DISTRIBUTION

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.

WMECO’s distribution business consists primarilyIn 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 purchase, deliverydeferred 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 saledid not have a material impact on CL&P’s financial position, results of electricityoperations 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 residential, commercialrecover storm restoration costs, plus carrying costs, related to Tropical Storm Irene and industrial customers.  Atthe 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, 2010,2013, 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 furnished retail franchise electricwere 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 Revenues

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

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

10

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 percenton 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 approximately 206,000 retail customers in 59 cities and townschanges in the western thirdcapital 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 Massachusetts.  Following11.14 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 industry restructuringutilities (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 1990s,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 sold allfrom Ludlow, Massachusetts to Bloomfield, Connecticut.  This transmission upgrade ensures the reliable flow of its generating facilitiespower in and now purchases its energy requirementsaround 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 competitive suppliers.  In 2009, pursuantLebanon, 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 Green Communities Act,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.

11

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 was authorized to install 6 MWcapitalized $252.8 million and $567 million, respectively, in costs associated with NEEWS, of solar energy generationwhich $40.8 million and $48.9 million, respectively, were capitalized in its service territory.  In October 2010, WMECO completed2013.    

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 1.8 MW solar generation facilitynew 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 siteplanned 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 Pittsfield, Massachusetts,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 began producing electricitywas 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 late 2010.  In January 2011, WMECO announced its plans to develop a second solar generation faci lity at a site in Springfield, Massachusetts.  This facility will accommodate 17,000 solar panels, producing up to 4.2 MWthe future.  

On December 31, 2013, NPT received ISO-NE approval under Section I.3.9 of solar energy.  WMECO will sell all energy and other products from its solar generation facilities into 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 market. WMECO hadgrid 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 contract with one IPP generatorresult of continued analysis of the transmission needs to enhance system reliability and improve capacity in 2010,eastern Massachusetts, NSTAR Electric expects to implement a series of new transmission initiatives over the outputnext 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 which WMECO sold into the ISO New England market.  The term of this contract ended on December 31, 2010.2013, 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.

NATURAL GAS DISTRIBUTION SEGMENT

The following table shows the sources of 2010 electricthe 2013 natural gas franchise retail revenues of NSTAR Gas and Yankee Gas based on categories of customers:

Rates

WMECO is subject to regulation by the Massachusetts 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, management efficiency and construction and operation of distribution, production and storage facilities.  WMECO's present general rate structure 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 state law, WMECO's customers are entitled to choose their energy suppliers, while WMECO remains their distribution company.  WMECO purchases electric power from competitive suppliers for, and passes through the cost to, those customers who do not choose a competitive energy supplier (basic service).  Basic service charges are adjusted and reconciled on an annual basis.  Most of WMECO's residential and small commercial and industrial customers have continued to buy their power from WMECO at basic service rates.  A greater proportion of large commercial and industrial customers have opted for a competitive energy supplier.

WMECO continues to supply approximately 50 percent of its customer load at basic service rates while the other 50 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 WMECO’s delivery business or its operating income.

WMECO recovers certain costs through various tracking mechanisms in its retail rates, including transmission costs, pension costs and prudently incurred stranded costs (a portion of which have been financed through securitization by issuing RRBs) with periodic true-up adjustments.  

6

Distribution Rates:    On January 31, 2011, the DPU issued a final decision in WMECO’s July 2010 rate application, granting a $16.8 million annualized rate increase in distribution revenues and an allowed ROE of 9.6 percent effective February 1, 2011.  The DPU also authorized a full decoupling mechanism, whereby actual revenue billed by WMECO would be reconciled with WMECO’s target revenue on an annual basis, WMECO’s request to recover balances of certain active hardship account balances and the recovery of certain storm costs over five years.  The DPU did not authorize rate recovery of a proposed $20 million average increase in WMECO’s capital spending plan. WMECO’s distribution segment regulatory ROE was 4.6 percent in 2010 compared to 8.4 percent in 2009.  We expect WMECO’s distribution segment regulatory ROE will be approximately 9 percent in 2011.  

WMECO is subject to SQ metrics that measure safety, reliability and customer service, and WMECO pays any charges incurred for failure to meet such metrics to customers.  WMECO will not be required to pay an assessment charge for its 2010 performance results as WMECO performed at target for all of its SQ metrics in 2010.  

On October 16, 2009, WMECO filed its proposal for a dynamic pricing smart meter pilot program with the DPU.  However, the Company does not expect it will conduct a pilot prior to 2012.

Sources and Availability of Electric Power Supply

As noted above, WMECO does not own any generation assets (other than its recently constructed solar generation) and purchases its energy requirements from a variety of competitive sources through periodic RFPs.  For basic service power supply, WMECO issues RFPs periodically, consistent with DPU regulations.12

REGULATED GAS DISTRIBUTION – YANKEE GAS SERVICES COMPANYA 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 operates the largestservice territory.

NSTAR GAS

NSTAR Gas distributes natural gas distribution system in Connecticut as measured by number of customers (approximately 206,000to approximately 274,000 customers in 71 cities51 communities in central and towns), and size of service territory (2,187eastern Massachusetts covering 1,067 square miles).miles.  Total throughput (sales and transportation) in both 2010 and 20092013 was approximately 52.560.5 Bcf.  YankeeNSTAR 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 their heating, hot water and cooking needs, and commercial and industrial customers who choose to purchase natural gas from YankeeNSTAR Gas.  Retail natural gas service in Connecticut is partially unbundled:

Predominantly all residential customers in Yankee Gas’the NSTAR Gas service territory buy gas supply and delivery only from YankeeNSTAR Gas while commercial and industrialall customers have choice inmay choose their gas suppliers.  YankeeNSTAR Gas offers firm transportat iontransportation service to its commercial and industrialall customers who purchase gas from sources other than YankeeNSTAR 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.  Yankeenotice, for whom NSTAR Gas can interrupt service to these customers during peak demand periods or at any other time to maintain distribution system integrity.  Yankee Gas also owns a 1.2 Bcf LNG facility in Waterbury, Connecticut, which enables the company to buy natural gas in periods of low demand, store it and use it during peak demand periods when prices are typically higher.

The following table shows the sources of 2010 gas operating revenues based on categories of customers:

A summary of firm natural gas sales in million cubic feet for Yankee Gas for 2010 and 2009 and the percentage changes in 2010 as compared to 2009 on an actual and weather normalized basis (using a 30-year average) is as follows:

7

Yankee Gas’ firm natural gas sales are subject to many of the same influences as our retail electric sales, but they have recently benefitted from a favorable price for natural gas relative to competing fuels resulting in commercial and industrial customers switching from interruptible service to firm service, and the addition of gas-fired distributed generation in Yankee Gas’ service territory.  Actual firm natural gas sales in 2010 were higher than 2009 despite the milder weather during the first quarter 2010 heating season.  Firm natural gas sales benefitted from these trends and from a large commercial customer who began to take service from Yankee Gas mid-way through the third quarter of 2009 and continued to take service throughout all of 2010.

In April 2010, Yankee Gas commenced construction of its WWL project, a 16-mile gas pipeline between Waterbury and Wallingford, Connecticut coupled with the increase of vaporization output of its LNG plant.  The project is expected to cost approximately $57.6 million.  In 2010, approximately $26.6 million was spent on construction of the WWL project, which included construction of a segment of pipeline connecting the Cheshire and Wallingford distribution systems.  The remainder of the pipeline construction and the expansion of the vaporization capacity of the LNG facility are expected to be completed in the fourth quarter of 2011

Rates

YankeeNSTAR 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.

13

NSTAR Gas is subject to regulation by the DPUC, which has jurisdiction over, among other things, rates, accounting procedures, certain dispositionsSQ metrics that measure safety, reliability and customer service and could be required to pay to customers a SQ charge of property and plant, mergers and consolidations, issuancesup to 2.5 percent of long-term securities, standardsannual 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 service, management efficiency and construction and operation of distribution, production and storage facilities.its SQ metrics in 2013.

Distribution Rates:  On January 7, 2011, Yankee Gas filed an application with the DPUC to raise natural gas distribution rates by $32.8 million, or 7.3 percent, to be effective July 1, 2011, and by an additional $13 million, or 2.8 percent, to be effective July 1, 2012.  Among other items, Yankee Gas requested to maintain its current authorized ROE of 10.1 percent, that $57.6 million of costs associated with the WWL project be placed into rates, and that a substantial increase in capital funding to replace bare steel and cast iron pipe on Yankee Gas' system.  A final decision is expected in June 2011. Yankee Gas’ regulatory ROE was 8.6 percent in 2010 compared to 6.6 percent in 2009.  We expect Yankee Gas’ distribution segment regulatory ROE to be approximately 9 percent in 2011.

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 DPUCLNG 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

14