UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

SCHEDULE 14A

Proxy Statement Pursuant to Section 14(a) of the

Securities Exchange Act of 1934

(Amendment No.     )

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¨ Preliminary Proxy Statement

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x Definitive Proxy Statement

¨ Definitive Additional Materials

¨ Soliciting Material Pursuant to §240.14a-12

Northeast Utilities

(Name of Registrant as Specified In Its Charter)

(Name of Person(s) Filing Proxy Statement, if other than the Registrant)

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x No fee required.

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2012 ANNUAL MEETING OF SHAREHOLDERS

Dear Shareholder:

On behalf of the Board of Trustees and the management of Northeast Utilities, it is our pleasure to invite you to attend the Special Meeting of Shareholders in lieu of the 2012 Annual Meeting of Shareholders of Northeast Utilities to be held on Wednesday, October 31, 2012, at 2:00 p.m., at the Sheraton Springfield Monarch Place Hotel, One Monarch Place, Springfield, Massachusetts 01144.

Information concerning the matters to be acted upon at the meeting is provided in the accompanying Notice of Annual Meeting of Shareholders and proxy statement. Our 2012 proxy statement includes Appendix B, our 2011 Annual Report, which includes the audited 2011 financial statements of Northeast Utilities and the management’s discussion and analysis of financial condition and results of operations. Our meeting agenda will also include a discussion of the operations of the Northeast Utilities system companies and an opportunity for questions.

As we have for the last several years, we are again taking advantage of the Securities and Exchange Commission rule that authorizes us to furnish proxy materials to many of our shareholders over the Internet. This process expedites the delivery of proxy materials and allows materials to remain easily accessible to our shareholders.

On September 20, 2012, we mailed to certain shareholders our Notice of Internet Availability of Proxy Materials, which contains instructions for our shareholders’ use of the Internet process, including how to access our 2012 proxy statement, which includes our 2011 Annual Report as an appendix, and how to vote online. In addition, the Notice of Internet Availability of Proxy Materials contains instructions for shareholders to request paper copies of our 2012 proxy statement and 2011 Annual Report.

Whether or not you plan to attend the meeting, it is important that your shares be represented at the meeting. You may vote your shares over the Internet or by calling a toll-free telephone number. If you received a paper copy of the proxy card by mail, you may also sign, date and mail the proxy card in the envelope provided. Instructions regarding all three methods of voting are contained in the Notice of Internet Availability of Proxy Materials and the proxy materials.

On behalf of your Board of Trustees, we thank you for your continued support of Northeast Utilities.

Very truly yours,

Charles W. Shivery

Chairman of the Board

Thomas J. May

President and Chief Executive Officer

September 20, 2012

NOTICE OF ANNUAL MEETING OF SHAREHOLDERS

To Be Held on October 31, 2012

To the Shareholders of Northeast Utilities:

Notice is hereby given that the Special Meeting of Shareholders in lieu of the Annual Meeting of Shareholders of Northeast Utilities (“NU” or the “Company”) will be held on Wednesday, October 31, 2012, at 2:00 p.m., at the Sheraton Springfield Monarch Place Hotel, One Monarch Place, Springfield, Massachusetts 01144, for the following purposes:

1. To elect fourteen nominees as Trustees, the names of whom are set forth in the accompanying proxy statement, for the ensuing year;

2. To consider and approve the following advisory (non-binding) proposal:

“RESOLVED, that the compensation paid to the Company’s named executive officers, as disclosed pursuant to the compensation disclosure rules of the Securities and Exchange Commission, including the compensation discussion and analysis, the compensation tables and any related material disclosed in this proxy statement, is hereby APPROVED.”

3. To re-approve the material terms of performance goals under the 2009 Northeast Utilities Incentive Plan as required by Section 162(m) of the Internal Revenue Code; and

4. To ratify the selection of Deloitte & Touche LLP as independent registered public accountants for 2012.

We will also transact any other business that may properly come before the meeting or any adjournment thereof.

Only shareholders of record at the close of business on September 4, 2012 are entitled to receive notice of and to vote at the meeting or any adjournment thereof. You are cordially invited to be present at the meeting and to vote.

Under New York Stock Exchange rules, if your shares are held in a brokerage account, and if you have not provided directions to your broker, your broker will NOT be able to vote your shares with respect to the election of Trustees, the advisory proposal on executive compensation and the proposal to re-approve the material terms of performance goals under the Incentive Plan. We strongly encourage you to submit your proxy card and exercise your right to vote as a shareholder.

By Order of the Board of Trustees,

Gregory B. Butler

Senior Vice President, General Counsel and Secretary

Boston, Massachusetts

Hartford, Connecticut

September 20, 2012

IMPORTANT

Whether or not you plan to attend the meeting, we urge you to vote your shares over the Internet or via the toll-free telephone number, as we describe in the accompanying materials and the Notice of Internet Availability of Proxy Materials. If you received a paper proxy card, you may vote by mail by completing, signing and dating the proxy card and returning it in the pre-addressed, postage-prepaid envelope accompanying the proxy card. No postage is necessary if mailed in the United States. Voting over the Internet, via the toll-free telephone number or mailing a proxy card will not limit your right to vote in person or to attend the Annual Meeting.

TABLE OF CONTENTS

	Page
Introduction		1
Questions and Answers about the Annual Meeting and Voting		3
Proposal 1: Election of Trustees		8
Governance of Northeast Utilities		16
Board’s Leadership Structure		16
Board’s Oversight of Risk		17
Board Committees and Responsibilities		17
Audit Committee		18
Compensation Committee		19
Corporate Governance Committee		19
Executive Committee		20
Finance Committee		20
Meetings of the Board and its Committees		20
Selection of Trustees		21
Trustee Independence		22
Certain Relationships and Related Transactions		23
The Code of Ethics and the Standards of Business Conduct		23
Communications From Shareholders and Other Interested Parties		24
Common Share Ownership of Certain Beneficial Owners		24
Common Share Ownership of Trustees and Management		25
Compensation Discussion and Analysis		27
Executive Summary		27
Overall Objectives of Executive Compensation Program		30
Named Executive Officers		31
Risk Analysis of Executive Compensation Program		31
Elements of 2011 Compensation		32
Mix of Compensation Elements		34
Market Analysis		35
Base Salary		37
Incentive Compensation		37
Supplemental Benefits		49
Contractual Agreements		52
Tax and Accounting Considerations		53
Compensation Committee Report		54
Summary Compensation Table		55
Grants of Plan-Based Awards During 2011		57
Equity Grants Outstanding at December 31, 2011		59
Options Exercised and Stock Vested In 2011		60
Pension Benefits in 2011		61
Nonqualified Deferred Compensation in 2011		63
Potential Payments Upon Termination or Change of Control		64
Trustee Compensation		75
Section 16(a) Beneficial Ownership Reporting Compliance		78
Proposal 2: Advisory Vote on Executive Compensation		79
Proposal 3: Re-approval of the Material Terms of Performance Goals Under the 2009 Northeast Utilities Incentive Plan		81
Proposal 4: Ratification of the Selection of Independent Registered Public Accountants		84
Relationship with Independent Registered Public Accountants		84
Report of the Audit Committee		86
Other Matters		87
Annual Report to Shareholders and Annual Report on Form 10-K		87
Appendix A - 2009 Northeast Utilities Incentive Plan
Appendix B - 2011 Annual Report

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PROXY STATEMENT

ANNUAL MEETING OF SHAREHOLDERS

October 31, 2012

INTRODUCTION

This proxy statement is furnished in connection with the solicitation of proxies by the Board of Trustees of Northeast Utilities for use at the Special Meeting in lieu of the Annual Meeting of Shareholders (the Annual Meeting) to be held on Wednesday, October 31, 2012, at 2:00 p.m., at the Sheraton Springfield Monarch Place Hotel, One Monarch Place, Springfield, Massachusetts 01144.

Under rules and regulations of the Securities and Exchange Commission, or SEC, instead of mailing a printed copy of our proxy materials to each shareholder of record or beneficial owner of Northeast Utilities common shares (common shares), we have mailed a Notice of Internet Availability of Proxy Materials to each shareholder who holds fewer than 1,000 common shares and have made available to these shareholders our proxy materials, which include our 2012 proxy statement and our 2011 Annual Report as Appendix B, over the Internet. Shareholders who received a Notice of Internet Availability of Proxy Materials by mail did not receive a printed copy of the proxy materials. However, these shareholders are entitled to request copies of these materials by following the instructions included in the Notice of Internet Availability of Proxy Materials. The Notice of Internet Availability of Proxy Materials also includes instructions for accessing the proxy materials online and for voting common shares via telephone or the Internet.

We mailed the Notice of Internet Availability of Proxy Materials to shareholders on or about September 20, 2012.

If you vote using the Internet, by telephone or by mailing a proxy card, the proxies will vote your common shares as you direct. For the election of Trustees (Proposal 1), you can specify whether your shares should be voted for all, some or none of the listed nominees for Trustee. With respect to the advisory proposal on executive compensation (Proposal 2), the proposal to re-approve the material terms of performance goals under the 2009 Northeast Utilities Incentive Plan (Proposal 3) and the proposal to ratify the selection of Deloitte & Touche LLP as our independent registered public accountants (Proposal 4), you may vote “for” or “against” the proposals, or you may abstain from voting on the proposals.

If you vote using the Internet, by telephone or by mailing a proxy card without any instructions, the proxies will vote your common shares consistent with the recommendations of our Board of Trustees as stated in this proxy statement and in the Notice of Internet Availability of Proxy Materials, specifically: FOR the election of each Trustee nominee; FOR the advisory proposal approving the compensation paid to the Company’s named executive officers, as disclosed pursuant to the compensation disclosure rules of the SEC; FOR the proposal to re-approve the material terms of performance goals under the 2009 Northeast Utilities Incentive Plan; and FOR the proposal to ratify the selection of Deloitte & Touche LLP as our independent registered public accountants. If any other matters are properly presented at the Annual Meeting for consideration, then the proxies will have discretion to vote your common shares on those matters. As of the date of the proxy statement, we did not know of any other matters to be presented at the Annual Meeting.

Only holders of common shares of record at the close of business on September 4, 2012 (the record date) are entitled to receive notice of and to vote at the meeting or any adjournment thereof. On the record date, there were

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51,958 holders of record and 313,842,387 common shares outstanding and entitled to vote. You are entitled to one vote on each matter to be voted on at the Annual Meeting for each common share that you held on the record date.

The principal office of Northeast Utilities is located at One Federal Street, Building 111-4, Springfield, Massachusetts 01105. The general offices of Northeast Utilities are located at 800 Boylston Street, Boston, Massachusetts 02199 and 56 Prospect Street, Hartford, Connecticut 06103-2818. This proxy statement, which includes our annual report as an appendix, and the accompanying proxy card, are being mailed to shareholders commencing on or about September 20, 2012.

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QUESTIONS AND ANSWERS ABOUT THE ANNUAL MEETING AND VOTING

Q: WHAT AM I VOTING ON?

A: You are being asked by the Board of Trustees of Northeast Utilities to vote on four proposals. The first proposal is the election of 14 nominees to our Board of Trustees. At the recommendation of the Corporate Governance Committee, the Board of Trustees has nominated 14 persons for election as Trustees, each of whom is currently serving as a Trustee. Seven of the nominees were elected as Trustees at our 2011 Annual Meeting of Shareholders. The remaining seven nominees were designated to serve on our Board by NSTAR and were elected by the Northeast Utilities Board in accordance with the Agreement and Plan of Merger by and among Northeast Utilities, NU Holding Energy 1 LLC, NU Holding Energy 2 LLC and NSTAR. The merger of Northeast Utilities and NSTAR closed on April 10, 2012. For more information on each nominee, please turn to “Election of Trustees” beginning on page 8.

You are being asked to vote on one non-binding advisory proposal. This advisory proposal, commonly known as “Say on Pay,” is a vote to approve the compensation paid to the Company’s named executive officers, as disclosed pursuant to the compensation disclosure rules of the SEC, including the compensation discussion and analysis, compensation tables and any related material disclosed in this proxy statement. For more information on this advisory proposal, please turn to “Advisory Vote on Executive Compensation” beginning on page 79.

You are also being asked to re-approve the material terms of performance goals under the 2009 Northeast Utilities Incentive Plan as required by Section 162(m) of the Internal Revenue Code. For more information on the material provisions of the Northeast Utilities Incentive Plan, please turn to page 81. The Plan, as amended in 2009, is attached to this proxy statement as Appendix A.

Finally, you are being asked to ratify the selection of Deloitte & Touche LLP as Northeast Utilities’ independent registered public accountants for 2012. For more information on this selection, please turn to “Ratification of the Selection of Independent Registered Public Accountants” beginning on page 84.

Q: WILL ANY OTHER MATTERS BE VOTED ON?

A: We do not expect any other matters to be considered at the Annual Meeting. However, if a matter not described in this proxy statement is legally and properly brought before the Annual Meeting by a shareholder, the individuals designated as proxies will vote on the matter in accordance with their judgment of what is in the best interest of Northeast Utilities. We are not aware of any other matters to be presented at the Annual Meeting.

Q: WHO IS ENTITLED TO VOTE?

A: You are entitled to vote at the annual meeting if you held common shares on the record date, September 4, 2012. If you received a Notice of Internet Availability of Proxy Materials, it indicates the number of common shares that you held on the record date. If you received printed proxy materials, the enclosed proxy card indicates the number of common shares that you held on the record date. As of the record date, 313,842,387 common shares were outstanding and entitled to vote. You are entitled to one vote on each matter to be voted on at the Annual Meeting for each common share that you held on the record date.

Q: HOW DO I VOTE?

A: You can vote in any one of the following ways:

• You can vote using the Internet. Follow the instructions in the Notice of Internet Availability of Proxy Materials or on the proxy card. The Internet procedures are designed to authenticate a shareholder’s identity to allow shareholders to vote their shares and confirm that their instructions have been properly recorded.

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Internet voting facilities for shareholders of record are available 24 hours a day and will close at 11:59 p.m. (EDT) on October 30, 2012. You may access this proxy statement and related materials by going to www.envisionreports.com/NU.

• You can vote by telephone. The proxy card includes a toll-free number you can call to vote your common shares. Voting by telephone is available 24 hours a day and will close at 11:59 p.m. (EDT) October 30, 2012.

• You can vote by mail. If you received a paper proxy card, you may vote by mail by completing, signing and dating the proxy card and returning it in the pre-addressed, postage-prepaid envelope accompanying the proxy card. Proxy cards submitted by mail must be received by the time of the Annual Meeting in order for your shares to be voted.

• You can vote in person at the Annual Meeting by delivering your completed proxy card in person at the Annual Meeting or by completing a ballot available upon request at the meeting.

• If your common shares are held by a broker, bank or other nominee (i.e., in street name), you should receive instructions from that person or entity that you must follow in order to vote your common shares. You may vote by mail by requesting a voting instruction card in accordance with the instructions received from your broker or other agent. Complete, sign and date the voting instruction card provided by the brokers or other agents and return it in the pre-addressed, postage-prepaid envelope provided to you. You also will be able to vote these shares by Internet or telephone.

Regardless of how you choose to vote, your vote is important, and we encourage you to vote promptly.

Q. I HAVE NOT YET EXCHANGED MY NSTAR COMMON SHARE CERTIFICATES FOR NU COMMON SHARES. AM I ENTITLED TO VOTE?

A. Yes. However, you will not receive dividends on your NU common shares until your NSTAR common shares are exchanged, so we urge you to complete the exchange promptly.

Q: AS A PARTICIPANT IN THE NORTHEAST UTILITIES SERVICE COMPANY 401K PLAN OR THE NSTAR SAVINGS PLAN, HOW DO I VOTE MY SHARES HELD IN MY PLAN ACCOUNT?

A: If you are a participant in the Northeast Utilities Service Company 401K Plan or the NSTAR Savings Plan, you can vote the common shares held in your plan account by completing, signing and dating a proxy card and returning it in the enclosed postage-paid envelope or through the Internet or by telephone as instructed on the proxy card. The plan trustee will vote the common shares held in your plan account in accordance with your instructions. If you do not provide the plan trustee with instructions by 11:59 p.m. on October 28, 2012, the common shares in your Northeast Utilities Service Company 401K Plan account or NSTAR Savings Plan account, as the case may be, will be voted by each plan trustee in the same proportion as the votes cast by participants in each plan.

Q: HOW MANY VOTES ARE NEEDED TO HOLD THE MEETING?

A: The presence in person or by proxy at the Annual Meeting of the holders of a majority of all common shares issued and outstanding and entitled to vote at the Annual Meeting is required for a quorum in order to hold the meeting.

Q: HOW MANY VOTES ARE NEEDED TO ELECT THE NOMINEES FOR TRUSTEE?

A: The affirmative vote of a majority of all common shares issued and outstanding and entitled to vote at the Annual Meeting is required to elect a Trustee.

Q: HOW MANY VOTES ARE NEEDED TO APPROVE THE ADVISORY PROPOSAL ON SAY-ON-PAY?

A: The affirmative vote of a majority of the votes cast at the Annual Meeting is required to approve the advisory proposal on executive compensation.

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Q: HOW MANY VOTES ARE NEEDED TO RE-APPROVE THE MATERIAL TERMS OF PERFORMANCE GOALS UNDER THE 2009 NORTHEAST UTILITIES INCENTIVE PLAN?

A: The affirmative vote of a majority of the votes cast at the Annual Meeting is required to re-approve the material terms of performance goals under the 2009 Northeast Utilities Incentive Plan.

Q. HOW MANY VOTES ARE NEEDED TO APPROVE THE RATIFICATION OF DELOITTE & TOUCHE LLP AS NORTHEAST UTILITIES’ INDEPENDENT REGISTERED PUBLIC ACCOUNTANTS FOR THE YEAR ENDING DECEMBER 31, 2012?

A: The affirmative vote of a majority of the votes cast at the Annual Meeting is required to ratify the selection of Deloitte & Touche LLP as Northeast Utilities’ independent registered public accountants for the year ending December 31, 2012.

Q: HOW DOES THE BOARD RECOMMEND THAT I VOTE?

A: The Board recommends that you vote as follows:

• FOR the election of each Trustee nominee (Proposal 1);

• FOR the advisory proposal approving the compensation paid to the Company’s named executive officers, as disclosed pursuant to the compensation disclosure rules of the SEC (Proposal 2);

• FOR the proposal to re-approve the material terms of performance goals under the 2009 Northeast Utilities Incentive Plan (Proposal 3); and

• FOR the proposal to ratify the selection of Deloitte & Touche LLP as our independent registered public accountants (Proposal 4).

Q: HOW ARE VOTES COUNTED?

A: In determining whether we have a quorum, we count all properly submitted proxies and ballots, including abstentions, broker non-votes and withheld votes, as present and entitled to vote. Abstentions and broker non-votes, as well as votes withheld, are not considered votes cast and will not be counted for or against the advisory proposal on Say-on-Pay, the proposal to re-approve the material terms of performance goals under the 2009 Northeast Utilities Incentive Plan, or the proposal to ratify the selection of Deloitte & Touche LLP. However, because the election of each Trustee requires the affirmative vote of at least a majority of the common shares outstanding and entitled to vote at the Annual Meeting, abstentions, broker non-votes and votes withheld with respect to a particular Trustee nominee will have the same effect as a vote against such Trustee nominee.

Q: WHO WILL COUNT THE VOTES?

A: Representatives of Computershare Investor Services, our Registrar and Transfer Agent, will count the votes.

Q: WHAT ARE BROKER NON-VOTES?

A: Broker non-votes occur when brokers holding shares on behalf of beneficial owners, do not receive voting instructions from the beneficial holders. If a broker does not have instructions and is barred by law or applicable rules from exercising its discretionary voting authority in the particular matter, then the shares will not be voted on the matter, resulting in a “broker non-vote.” Absent voting instructions, a broker is not permitted to vote on the election of Trustees, the non-binding advisory proposal on “Say on Pay;” and the proposal to re-approve the material terms of performance goals under the 2009 Northeast Utilities Incentive Plan. Accordingly, there may be broker non-votes on Proposals 1, 2 and 3. A broker may vote on the ratification of the selection of our independent registered public accountants without instructions; therefore, broker non-votes are not expected for Proposal 4.

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Q: WHAT SHARES ARE COVERED BY THE NOTICE OF INTERNET AVAILABILITY OF PROXY MATERIALS AND PROXY CARD?

A: For each account in which you own common shares:

• Directly in your name as the shareholder of record; or

• Indirectly through a broker, bank or other holder of record;

you should have received either: (i) a Notice of Internet Availability of Proxy Materials; or (ii) a paper or electronic proxy card.

Q: WHAT DOES IT MEAN IF I RECEIVE MORE THAN ONE NOTICE OF INTERNET AVAILABILITY OF PROXY MATERIALS OR PROXY CARD?

A: If you receive more than one Notice of Internet Availability of Proxy Materials and/or more than one proxy card, then you have multiple accounts in which you own common shares. Please follow all instructions to ensure that all of your shares are voted. In addition, for your convenience, we recommend that you contact your broker, bank or our transfer agent to consolidate as many accounts as possible under a single name and address. Our transfer agent is Computershare Investor Services. If you have any questions concerning common shares you hold in your name, including address changes, name changes, requests to transfer shares and similar issues, you may contact Computershare Trust Company, N.A. by mail at P. O. Box 43078, Providence, Rhode Island 02940-3078, by telephone at (800) 999-7269 or on the Internet at www.computershare.com.

Q: HOW CAN I CHANGE MY VOTE?

A: Your presence at the Annual Meeting will not automatically revoke your proxy. You may, however, revoke a proxy and change your vote at any time before the polls close at the Annual Meeting by:

• Delivering either a written notice of revocation of the proxy or a duly executed proxy bearing a later date to Richard J. Morrison, Assistant Secretary, Northeast Utilities, Post Office Box 270, Hartford, Connecticut 06141-0270;

• Re-voting on the Internet or by telephone until 11:59 p.m. (EDT) on October 30, 2012; or

• Attending the Annual Meeting and voting in person.

If you are a participant in either the Northeast Utilities Service Company 401K Plan or the NSTAR Savings Plan, you can revoke your proxy card and change your vote by re-voting on the Internet or by telephone until 11:59 p.m. (EDT) on October 28, 2012.

Q: WHEN IS THE DEADLINE FOR SUBMITTING SHAREHOLDER PROPOSALS FOR THE 2013 ANNUAL MEETING OF SHAREHOLDERS?

A: Northeast Utilities has traditionally held its Annual Meeting of Shareholders in early May of each year. However, because the merger with NSTAR closed on April 10, 2012, the 2012 Annual Meeting was rescheduled to October 31, 2012 in order to provide the former shareholders of NSTAR with sufficient time to exchange certificates representing NSTAR common shares for common shares of Northeast Utilities. For 2013, Northeast Utilities decided to return to its traditional annual meeting date, and has tentatively scheduled the 2013 Annual Meeting of Shareholders for May 1, 2013. This date is more than thirty days prior to the anniversary date of the 2012 Annual Meeting of Shareholders. We currently expect to mail definitive proxy materials to shareholders on or about March 22, 2013.

Accordingly, you may submit proposals for consideration at the 2013 Annual Meeting of Shareholders, including Trustee nominations, in accordance with the following provisions:

To include a proposal in our proxy statement for the 2013 Annual Meeting of Shareholders, your proposal must be received by the Corporate Secretary’s office no later than November 21, 2012, and must satisfy the

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conditions established by the SEC. Written notice of proposals of shareholders to be considered at the 2013 Annual Meeting without inclusion in next year’s proxy statement must be received on or before February 5, 2013. If a notice is received after February 5, 2013, then the notice will be considered untimely and the proxies held by management may provide the discretion to vote against such proposal, even though the proposal is not discussed in the proxy statement. Northeast Utilities considers these dates to be reasonable deadlines for submission of proposals before we begin to print and mail our proxy materials for the 2013 Annual Meeting of Shareholders. Proposals should be addressed to: Richard J. Morrison, Assistant Secretary, Northeast Utilities, Post Office Box 270, Hartford, Connecticut 06141-0270.

Q: WHO PAYS THE COST OF SOLICITING THE PROXIES REQUESTED?

A: We will bear the cost of soliciting proxies on behalf of the Board of Trustees. In addition to the use of the mails, proxies may be solicited by telephone or electronic mail, by officers or employees of Northeast Utilities or its affiliates, Northeast Utilities Service Company and NSTAR Electric & Gas Corporation, neither of whom will be specially compensated for such activities, and by employees of Computershare Investor Services, our Transfer Agent and Registrar. We have also retained AST Phoenix Advisors, a professional proxy soliciting firm, to assist in the solicitation of proxies for a fee of $6,500, plus reimbursement of certain out-of-pocket expenses. We also will request persons, firms and other companies holding common shares in their names or in the name of their nominees, which are beneficially owned by others as of September 4, 2012, to send proxy materials to and obtain proxies from the beneficial owners, and we will reimburse those holders for any reasonable expenses that they incur.

Q: HOW CAN I OBTAIN ELECTRONIC ACCESS TO PROXY MATERIALS INSTEAD OF RECEIVING PAPER COPIES BY MAIL?

A: This proxy statement, which includes our 2011 Annual Report as an appendix, is available on our website at www.nu.com in the Investors section under the link entitled “Financial & SEC Reports.” You may elect to enroll in “electronic access” to receive future proxy statements and annual reports electronically instead of receiving paper copies in the mail. If you are a shareholder of record, you can choose this option and save the Company the cost of producing and mailing these documents by visiting www.computershare.com/investor and following the instructions. You will need to login to your account or create a login to verify your identity. If your common shares are held by a broker, bank or other nominee (i.e., in street name), and you wish to enroll in electronic access, you should contact your broker, bank or nominee.

If you choose to receive future proxy statements and annual reports electronically, each year we will timely notify you when these documents become available. Your choice to receive these documents electronically will remain in effect until you instruct us otherwise. You need not elect electronic access each year.

Q: WHERE CAN I GET A COPY OF THE NORTHEAST UTILITIES ANNUAL REPORT?

A: If you were a shareholder of record on September 4, 2012 and received paper copies of the proxy materials, you should have received a paper copy of our Annual Report to Shareholders for the year ended December 31, 2011 as Appendix B to this proxy statement. If you would like a copy of our Annual Report on Form 10-K filed with the SEC, you can access it on our website at www.nu.com/investors/reports/sec.asp or you may request it from the Corporate Secretary’s office at the following address and we will send it to you free of charge:

Richard J. Morrison

Assistant Secretary

Northeast Utilities

Post Office Box 270

Hartford, Connecticut 06141-0270

Important Notice Regarding the Availability of Proxy Materials for the

Northeast Utilities Annual Meeting of Shareholders to be held on October 31, 2012:

This proxy statement, which includes the 2011 Annual Report as an appendix, is also available free of charge at the following website: www.edocumentview.com/NU.

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PROPOSAL 1

ELECTION OF TRUSTEES

Our Board of Trustees oversees the business affairs and management of Northeast Utilities. The Board currently consists of 14 Trustees, only one of whom, Thomas J. May, our President and Chief Executive Officer, is a member of management.

On April 10, 2012, Northeast Utilities completed its merger transaction with NSTAR (the “Merger”). Pursuant to the Agreement and Plan of Merger (the “Merger Agreement”) entered into by Northeast Utilities and NSTAR in October 2010, upon completion of the Merger, the Northeast Utilities Board was comprised of 14 Trustees, seven of whom were designated by Northeast Utilities (including Charles W. Shivery, who was serving as the Chairman, President and Chief Executive Officer of Northeast Utilities) and seven of whom were designated by NSTAR (including Thomas J. May, who was serving as the Chairman, President and Chief Executive Officer of NSTAR). Accordingly, the Northeast Utilities Board elected the following individuals designated by NSTAR (the “NSTAR Designees”) to the Northeast Utilities Board effective upon the completion of the Merger: James S. DiStasio, Francis A. Doyle, Charles K. Gifford, Paul A. La Camera, Thomas J. May, William C. Van Faasen and Frederica M. Williams.

In addition, Richard H. Booth, John S. Clarkeson, Cotton M. Cleveland, Sanford Cloud, Jr., Kenneth R. Leibler, Charles W. Shivery and Dennis R. Wraase, each a Trustee of Northeast Utilities, were designated by the Northeast Utilities Board to continue to serve on the Board (the “Northeast Utilities Designees”). The Northeast Utilities Designees were elected as Trustees of Northeast Utilities at our 2011 Annual Meeting of Shareholders. Effective upon completion of the Merger, John G. Graham, Elizabeth T. Kennan, Robert E. Patricelli and John F. Swope, each of whom had also been elected as a Trustee in 2011, retired as a Trustee of Northeast Utilities and from all committees of the Board on which each of them served.

As a result, upon the closing of the Merger the Board of Trustees consists of: Richard H. Booth, John S. Clarkeson, Cotton M. Cleveland, Sanford Cloud, Jr., James S. DiStasio, Francis A. Doyle, Charles K. Gifford, Paul A. La Camera, Kenneth R. Leibler, Thomas J. May, Charles W. Shivery, William C. Van Faasen, Frederica M. Williams and Dennis R. Wraase. The Lead Trustee of the Company is Mr. Cloud; the Chairman of the Board is Mr. Shivery; and the President and Chief Executive Officer is Mr. May.

All 14 Trustees have been nominated for reelection as Trustees at the Annual Meeting to hold office until the next annual meeting and until the succeeding Board of Trustees has been elected, and until at least a majority of the succeeding board is qualified to act. Unless you specify otherwise, the enclosed proxy will be voted to elect the 14 nominees named on pages 9-15 as Trustees.

If one or more of the nominees should become unavailable for election, which the Board of Trustees does not currently anticipate, the proxy may be voted for a substitute person or persons, but not more than a total of 14 nominees.

Set forth on the following pages is each nominee’s name, age, date first elected as a Trustee, and a brief summary of the nominee’s business experience, including the nominee’s particular experience, qualifications, attributes or skills that led the Board to conclude that the nominee should continue to serve as a Trustee. See the Trustees’ biographies below and the section captioned “Selection of Trustees” on page 21. Each nominee has indicated he or she will stand for election and will serve as a Trustee if elected. An affirmative vote of a majority of the common shares outstanding as of the record date will be required to elect each nominee. Abstentions, broker non-votes and withheld votes will be counted in the determination of a quorum and will have the same effect as a vote against a nominee.

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The Board of Trustees recommends that shareholders vote FOR the election of

the nominees listed below

	RICHARD H. BOOTH, 65 Trustee since 2001. Since July 2009, Mr. Booth has served as Vice Chairman of Guy Carpenter & Company, LLC, a global reinsurance intermediary and wholly owned subsidiary of Marsh & McLennan Companies, Inc. From June 2008 to March 2009, Mr. Booth served as a corporate officer, and from October 2008 to March 2009, as Vice Chairman, Transition Planning and Chief Administrative Officer, of American International Group, Inc.,
an insurance and financial services company. From January 2000 to March 2009, he served as Chairman and a director, and from January 2000 to July 2007, as President and Chief Executive Officer, of HSB Group, Inc., a specialty insurer and reinsurer. From January 2000 to March 2009, he served as Chairman and a director, and from January 2000 to July 2007, as Chief Executive Officer, of Hartford Steam Boiler Inspection and Insurance Company, a provider of insurance and engineering services and investments. Mr. Booth is currently a member of the boards of Sun Life Financial Inc., WorldBusiness Capital LLC, the Florence Griswold Museum (Emeritus) and the National Association of Corporate Directors, Connecticut Chapter. He is a senior adviser to Century Capital Management. Mr. Booth received B.S. and M.S. degrees from the University of Hartford. He is a former member of the Financial Accounting Standards Advisory Council and its Steering Committee.
Mr. Booth has considerable senior executive level experience in business and management, including in particular strategic planning, capital and financial markets, accounting and financial reporting, credit markets and risk assessment, both in his current position as an executive officer of Guy Carpenter as well as in prior positions, including Chairman of HSB Group and Chairman of Hartford Steam Boiler. He has served on the board of directors of numerous companies. In addition, Mr. Booth is a certified public accountant. Based on these skills and qualifications, coupled with his ties to the City of Hartford and the State of Connecticut, the Board of Trustees determined that Mr. Booth should continue to serve as a Trustee.

JOHN S. CLARKESON, 69 Trustee since 2008. Mr. Clarkeson has served as the Chairman Emeritus of The Boston Consulting Group, Inc. since 2007. Previously, Mr. Clarkeson served as Co-Chairman of the Board of The Boston Consulting Group, Inc. from 2004 to 2007. He is a director of the Cabot Corporation, a director of the National Bureau of Economic Research, a former trustee of the Educational Testing Service, a trustee emeritus of the Massachusetts General

Physicians Organization, Inc., and a member of the INSEAD Advisory Council. Mr. Clarkeson received an A.B. degree magna cum laude from Harvard College, where he was a Harvard National Scholar, and an M.B.A. from Harvard Business School. Mr. Clarkeson has significant senior executive level experience in business and management through his service as Chairman and Chief Executive Officer of The Boston Consulting Group, as well as his service as a director of Cabot Corporation, where he chairs the Corporate Governance and Nominating Committee and serves on the Compensation and Executive Committees. He has served on the board of directors of numerous companies. He also has experience in budgeting, capital and financial markets, credit markets, and risk assessment. Based on these skills and qualifications, the Board of Trustees determined that Mr. Clarkeson should continue to serve as a Trustee.

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COTTON M. CLEVELAND, 60 Trustee since 1992. Ms. Cleveland has been President of Mather Associates, a firm specializing in leadership and organizational development for business, public and nonprofit organizations, since 1981. She is a director of The National Grange Mutual Insurance Company and Ledyard National Bank, and was the founding Executive Director of the state-wide Leadership New Hampshire program. She was elected and served as the

Moderator of the Town of New London, New Hampshire and the New London/Springfield Water Precinct from 2000 to 2010. Ms. Cleveland has also served as Chair, Vice Chair and member of the Board of Trustees of the University System of New Hampshire, as Co-Chair of the Governor’s Commission on New Hampshire in the 21st Century, and as an incorporator for the New Hampshire Charitable Foundation. Ms. Cleveland received a B.S. magna cum laude from the University of New Hampshire, Whittemore School of Business and Economics. She is a certified and practicing Court Appointed Special Advocate for abused and neglected children. Ms. Cleveland founded and serves as president of her own consulting firm. She has experience serving on the board of directors of numerous companies. She also benefits from her policy-making level experience in education at the university level as the Chair, Vice Chair and member of the Board of Trustees of the University System of New Hampshire. In addition, she has policy-making level experience in financial and capital markets as a result of her service as a director of Ledyard National Bank and Bank of Ireland. Based on her skills and experience, combined with her ties to the State of New Hampshire, the Board of Trustees determined that Ms. Cleveland should continue to serve as a Trustee.

SANFORD CLOUD, JR., 67 Trustee since 2000. Mr. Cloud has been Chairman and Chief Executive Officer of The Cloud Company, LLC, a real estate development and business investment firm, since 2005. Mr. Cloud served as past President and Chief Executive Officer of the National Conference for Community and Justice from 1994 to 2004, was a former partner at the law firm of Robinson and Cole from 1993 to 1994, and served for two terms as a state senator of

Connecticut. Mr. Cloud has served as a director of The Phoenix Companies, Inc. since 2001 and is currently a director of Ironwood Mezzanine Fund, L.P. He is also a director of the MetroHartford Alliance, Inc., and Chairman of The Connecticut Health Foundation and the University of Connecticut Health Center. Mr. Cloud received a B.A. from Howard University, a J.D. cum laude from the Howard University Law School, and an M.A. in Religious Studies from the Hartford Seminary. Mr. Cloud has significant policy-making level experience in business and financial affairs as a director of several publicly traded companies. He has served on the board of directors of numerous companies. Combined with his practice as a law firm partner, his experience as a Connecticut state senator, and his significant ties to the City of Hartford and the State of Connecticut, the Board of Trustees determined that Mr. Cloud should continue to serve as a Trustee.

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JAMES S. DISTASIO, 65 Trustee since 2012. Mr. DiStasio served as Senior Vice Chairman and Americas Chief Operating Officer at Ernst & Young, a registered public accounting firm, from 2003 until his retirement in 2007. Mr. DiStasio joined Ernst & Young in 1969 and became a partner in 1977. He has served as a director of EMC Corporation since 2010. He served as a trustee of NSTAR from 2009 until the closing of the NSTAR merger. He previously served as a

director of the United Way of Massachusetts Bay and Merrimack Valley and as a trustee of each of Catholic Charities of Boston, the Boston Public Library Foundation and the Wang Center for the Performing Arts. Mr. DiStasio received a bachelor’s degree in Accounting from the University of Illinois at Chicago. Mr. DiStasio has significant experience overseeing the accounting and financial reporting processes of major public companies, derived from his service as a senior executive at one of the largest public accounting firms in the world. In his position of Senior Vice Chairman and Americas Chief Operating Officer, Mr. DiStasio also acquired important management and leadership skills that provide additional value and support to the Board. Based on his skills and experience, the Board of Trustees determined that Mr. DiStasio should continue to serve as a Trustee.

FRANCIS A. DOYLE, 64 Trustee since 2012. Since 2001, Mr. Doyle has served as President and Chief Executive Officer of Connell Limited Partnership, whose businesses produce metal components and related supplies for the automotive, power, mining, appliance, office and farm equipment industries. From 1972 to 2001, he was Vice Chairman of PricewaterhouseCoopers LLP, where he was Global Technology and E-Business Leader and a member of the firm’s Global

Leadership Team. Mr. Doyle became a Trustee at the closing of the NSTAR merger. He has served as a director and Chairman of the audit committee and a member of the executive committee of each of Tempur-Pedic International, Inc. and Liberty Mutual Holding Company, Inc. since 2003. In the past five years, Mr. Doyle has served as a director of Citizens Financial Group, where he was a member of the executive committee and chaired the compensation committee, as a trustee of the Joslin Diabetes Center, where he chaired the finance committee, and as a trustee of Boston College. Mr. Doyle is a certified public accountant and holds a B.S. degree and an M.B.A. degree from Boston College. Mr. Doyle has significant financial accounting and financial reporting experience and an in-depth understanding of finance and capital markets through his years at PricewaterhouseCoopers LLP. He also has extensive senior management experience as the President and Chief Executive Officer of a global manufacturer. Mr. Doyle has served on the board of directors of numerous companies. Based on his qualifications and experience, the Board of Trustees determined that Mr. Doyle should continue to serve as a Trustee.

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CHARLES K. GIFFORD, 69 Trustee since 2012. Mr. Gifford has served as the Chairman Emeritus of Bank of America Corporation, a bank holding company, since his retirement as Chairman in 2005. He has served as a director of CBS Corporation since 2006. Since 2007, Mr. Gifford has served as a director of NYSE Group Trust I, established as part of the creation of NYSE Euronext and charged with remedying certain significant and unforeseen effects in the application

of U.S. or European regulation and legislation on markets operated by NYSE Euronext subsidiaries. He served as a trustee of NSTAR from 1999 until the closing of the NSTAR Merger. He is the chairman of the Boston Plan for Excellence in the Public Schools and was the founding chairman of the United Way of Massachusetts Bay’s “Success By 6” initiative. He is a trustee of Northeastern University and serves on the boards of several nonprofit organizations, including the Massachusetts General Hospital and Partners HealthCare System, Inc. He is an honorary director of the Greater Boston Chamber of Commerce. Mr. Gifford received a B.A. from Princeton University. Mr. Gifford, through a career overseeing large complex financial institutions in the banking industry, brings important business and financial expertise to the Board in its deliberations on complex transactions and other financial matters. In addition, his breadth of director experience, which includes his service on executive, executive personnel, credit, governance and nominating, and audit committees, as well as his service as Lead Trustee of NSTAR, provides valuable contributions to the Board in implementing good corporate governance. Based on his qualifications and experience, the Board of Trustees determined that Mr. Gifford should continue to serve as a Trustee.

PAUL A. LA CAMERA, 69 Trustee since 2012. Mr. La Camera has served as the Administrator of Public Radio for WBUR, the National Public Radio news station in Boston, since 2011. Previously Mr. La Camera served as General Manager of WBUR from 2005 until 2010 and as the President and General Manager of WCVB-TV Channel 5 Boston from 1993 to 2005. He served as a trustee of NSTAR from 1999 until the closing of the NSTAR merger. He serves on

the board of the Boston Foundation and as a trustee of the Boston Public Library. Mr. La Camera is a graduate of the College of Holy Cross, where he served as a trustee for eight years. He received Masters Degrees in Journalism and Urban Studies from Boston University and an M.B.A. from Boston College. Mr. La Camera served for more than 30 years as an executive in the local television and radio broadcast industry. In addition to his experience in operating regulated broadcast businesses and the important perspective that his career in broadcast journalism provides, Mr. La Camera brings extensive organizational and leadership skills to the Board, along with his link to the NSTAR customer community through his substantial non-profit board service. Based on his qualifications and experience, the Board of Trustees determined that Mr. La Camera should continue to serve as a Trustee.

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KENNETH R. LEIBLER, 63 Trustee since 2006. Mr. Leibler has served as a trustee of The Putnam Mutual Funds since 2006, a Trustee of Beth Israel Deaconess Medical Center since 2006, and Vice Chairman of the Board of Trustees of Beth Israel Deaconess Medical Center since 2009. He is a founding partner of the Boston Options Exchange and served as its Chairman from 2004 to February 2007. He is a past Vice Chairman of the Board of Directors of ISO New

England, Inc., the independent operator of New England’s bulk electric transmission system, where he served until 2006. He also served as a director of The Ruder Finn Group from 2005 to 2010. Mr. Leibler received a B.A. magna cum laude from Syracuse University. Mr. Leibler has considerable senior executive level experience in business and management, including experience in financial markets and risk assessment, as the former Chairman of the Boston Options Exchange, former Chairman and Chief Executive Officer of the Boston Stock Exchange, and former President, Chief Operating Officer and Chief Financial Officer of the American Stock Exchange, as well as through his current service as a trustee of The Putnam Mutual Funds, where he recently became chair of the Audit and Compliance Committee and serves on the pricing, distributions, investment oversight, and investment oversight coordinating committees. He also has policy-making level experience in the electric utility industry through his service as the Vice Chairman of ISO New England. Based on these qualifications, the Board of Trustees determined that Mr. Leibler should continue to serve as a Trustee.

THOMAS J. MAY, 65 Trustee since 2012. Mr. May has served as President and Chief Executive Officer and a Trustee of Northeast Utilities since the closing of the NSTAR merger in April, 2012. He has also served as the Chairman and a director of each of The Connecticut Light and Power Company, Public Service Company of New Hampshire, Western Massachusetts Electric Company and Yankee Gas Services Company since the closing of the merger.

Previously, Mr. May served as Chairman, President and Chief Executive Officer and a trustee of NSTAR until the closing of the merger. He served as Chairman, Chief Executive Officer and a trustee from the creation of NSTAR in 1999, was elected President in 2002 and has served as a director of NSTAR Electric Company and NSTAR Gas Company since 1999. Mr. May has served as a director of Bank of America Corporation since 2004 and a director of Liberty Mutual Holding Company, Inc. since 2002. He is Chair of the Board of Trustees of Stonehill College, is a member of the Executive Committee of the Board of Directors of the Boston Chamber of Commerce, is a member of the Board of Trustees of Dana Farber Cancer Institute and a board member of the John F. Kennedy Library Foundation. Mr. May received a bachelor’s degree in business administration from Stonehill College and a M.S. in Finance from Bentley College. He is also a graduate of the Harvard Business School’s Advanced Management Program. Mr. May is the President and Chief Executive Officer of the Company. His extensive experience in the energy industry and diverse financial, operations and management skills provide the necessary background to lead the Company. Mr. May represents management on the Board as the sole management Trustee. Based on these skills and experiences, the Board of Trustees determined that Mr. May should continue to serve as a Trustee.

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CHARLES W. SHIVERY, 67 Trustee since 2004. Mr. Shivery has been Chairman of the Board of Trustees since the closing of the NSTAR merger. Previously, Mr. Shivery served as the Chairman, President and Chief Executive Officer of Northeast Utilities from March 29, 2004 until the closing of the NSTAR merger. He served as interim President of Northeast Utilities beginning in January 2004. Mr. Shivery served as Chairman and a director of The Connecticut Light

and Power Company, Public Service Company of New Hampshire, Western Massachusetts Electric Company and Yankee Gas Services Company from January 19, 2007 until the closing of the NSTAR merger. In 2002, Mr. Shivery retired from Constellation Energy Group, Inc., parent company of Baltimore Gas and Electric Company (BG&E) and other energy related businesses, having held numerous senior management positions at Constellation. Mr. Shivery is a director of Webster Financial Corporation Energy Insurance Mutual, the Connecticut Business & Industry Association, Association of Edison Illuminating Companies, Connecticut Children’s Medical Center, The Bushnell, and the Edison Electric Institute. He is the Chairman of the Metro Hartford Alliance, Inc. and the Connecticut Science Center. Mr. Shivery received B.A. and B.S. degrees from The Johns Hopkins University and an M.B.A. from the University of Baltimore. Mr. Shivery has nearly 40 years of experience in the heavily regulated utility industry, including policy-making level director and executive officer positions while employed at Constellation Energy and Northeast Utilities. He gained important senior management level experience in capital and financial markets and credit markets throughout his career at Constellation Energy and Northeast Utilities. Based on his extensive experience and qualifications, the Board of Trustees determined that Mr. Shivery should continue to serve as a Trustee.

WILLIAM C. VAN FAASEN, 64 Trustee since 2012. Mr. Van Faasen served as Chief Executive Officer of Blue Cross Blue Shield of Massachusetts, Inc. (“BCBSMA”), a health care services provider, from 1992 until his retirement in 2007. He is currently Chairman of BCBSMA and also served as interim Chief Executive Officer in 2010. He has served as a director of Liberty Mutual Holding Company, Inc. since 2002 and served as a director of IMS Health, Inc. from 1996 to 2010.

He also served as a director of PolyMedica Corporation from 2005 to 2008. Mr. Van Faasen served as a trustee of NSTAR from 2002 until the completion of the NSTAR merger. He is an honorary director of the Greater Boston Chamber of Commerce and previously served as a director of the United Way of Massachusetts Bay and Merrimack Valley. Mr. Van Faasen received a B.A. from Hope College and an M.B.A. from Michigan State University. Mr. Van Faasen brings to the Board extensive management, leadership, and financial experience as a result of leading a large company in a regulated industry. He also brings in-depth experience and insight as a director of several public companies, including service as a lead director. Based on his qualifications and experience, the Board of Trustees determined that Mr. Van Faasen should continue to serve as a Trustee.

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FREDERICA M. WILLIAMS, 54 Trustee since 2012. Ms. Williams has served as the President and Chief Executive Officer of Whittier Street Health Center in Boston, an urban community health care facility serving residents of Boston and surrounding communities, since 2002. Prior to joining Whittier, she served as the Senior Vice President of Administration and Finance and Chief Financial Officer of the Dimock Center, a large health care and human services facility in Boston. She was elected as a trustee of NSTAR in March 2012 and served

as a trustee until the completion of the NSTAR merger. Ms. Williams is a member of the Board of Trustees of Dana Farber Cancer Institute, the Massachusetts League of Community Health Centers and Boston Health Net. She also serves on several advisory boards, including the Global Health/International Health Initiative and the African Health Foundation. Ms. Williams attended the London School of Accountancy, passed the examinations of the Institute of Chartered Secretaries and Financial Administrators, (United Kingdom) (“ICSA”) and of the Institute of Administrative Management (United Kingdom), with distinction, and was elected a Fellow of the ICSA in 2000. She obtained a graduate certificate in Administration and Management from the Harvard University Extension School and an M.B.A. with a concentration in Finance from Anna Maria College in Paxton, Massachusetts. Ms. Williams has more than 20 years of experience in a heavily regulated industry and has served as the President and Chief Executive Officer of Whittier Street Health Center, a national model for providing equitable access to high quality and cost effective health care, for more than ten years. She also has significant experience serving on numerous boards and advisory boards. Based on her qualifications and experience, the Board of Trustees determined that Ms. Williams should continue to serve as a Trustee.

DENNIS R. WRAASE, 68 Trustee since 2010. Mr. Wraase served as Chairman of the Board, Chief Executive Officer and a director of Pepco Holdings, Inc. (PHI) until his retirement in June 2009. PHI is an energy delivery company in the mid Atlantic region. He was elected Chairman of PHI in 2004, became Chief Executive Officer in 2003 and served as a director since 1998. He previously served as the President of PHI from 2001 to 2008 and Chief Operating

Officer from 2002 to 2003. Mr. Wraase received a B.S. in Accounting from the University of Maryland and an M.S in Business Financial Management from The George Washington University. He is member of the Financial Executives Institute and the American Institute of Certified Public Accountants. Mr. Wraase currently serves as the Executive-In-Residence at the Center for Social Value Creation at the Robert H. Smith School of Business, University of Maryland. He is also currently a director and Vice Chairman of the University of Maryland System Foundation and a director and Chairman of the Washington Hospital Center. Mr. Wraase previously served as a director of the Edison Electric Institute, The Association of Edison Illuminating Companies and the Institute for Electric Efficiency, and as President of the Southeastern Electric Exchange. Mr. Wraase brings to Northeast Utilities considerable utility industry knowledge and experience gained through his career of service at PHI. He has significant policy-making level experience in the heavily regulated industry as well as in the capital and financial markets, credit markets, financial reporting and accounting, and risk assessment. He is also a certified public accountant. Based on his extensive experience and qualifications, the Board of Trustees determined that Mr. Wraase should continue to serve as a Trustee.

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GOVERNANCE OF NORTHEAST UTILITIES

Board’s Leadership Structure

The Merger Agreement contained specific provisions addressing the Board’s structure and the corporate governance of Northeast Utilities after the completion of the Merger. Our current leadership structure consists of a non-executive Chairman of the Board, a President and Chief Executive Officer, and a Lead Trustee. Pursuant to the Merger Agreement, upon the completion of the Merger on April 10, 2012, Charles W. Shivery became the Company’s non-executive Chairman of the Board and Thomas J. May became the Company’s President and Chief Executive Officer. In accordance with the Merger Agreement, Mr. Shivery will continue to serve as non-executive Chairman of the Board until October 10, 2013. Also in accordance with the Merger Agreement, at the time that Mr. Shivery ceases to serve as our non-executive Chairman of the Board, the Board will appoint Mr. May as Chairman of the Board.

Effective upon completion of the merger, there were five committees of the Board of Trustees: Audit, Compensation, Corporate Governance, Executive and Finance. Each of these committees consists of an equal number of Northeast Utilities Designees and NSTAR Designees, respectively. The chairs of the Audit and Corporate Governance Committees have been designated by Northeast Utilities, and the chairs of the Compensation and Finance Committees have been designated by NSTAR. In addition, Northeast Utilities has designated the Lead Trustee.

As described in the Merger Agreement, the roles and responsibilities of the non-executive Chairman and the Lead Trustee are as follows:

Chairman: The Chairman of the Board shall:

• Be recommended by the Corporate Governance Committee and appointed by the Board.

• Preside at the Annual Meeting of Shareholders and at all meetings of the Executive Committee and the Board, other than executive sessions of the independent trustees.

• Working with the Chief Executive Officer, develop the annual Board calendar and Board meeting agendas.

• Work with the Lead Trustee to facilitate communication between the Chief Executive Officer and the Board members.

• Act as a resource to the Chief Executive Officer in the development of key corporate strategies and goals.

• Provide a visible presence in our communities and region.

• Working with the Chief Executive Officer, provide leadership on regional and national policy and industry association matters.

Lead Trustee: The Lead Trustee shall:

• Be recommended by the Corporate Governance Committee and appointed by the Board.

• Preside at executive sessions of the independent Trustees.

• Work with the Chairman to facilitate communication between the Chief Executive Officer and the Board members.

• Participate with the Compensation Committee in its evaluation of the Chief Executive Officer and provide ongoing information to the Chief Executive Officer about his or her performance.

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Board’s Oversight of Risk

The Board of Trustees administers its risk oversight function primarily through its Audit and Finance Committees. Each year, the Board evaluates its risk assessment function as part of its Board evaluation process. The Board believes that its leadership structure is appropriate to carry out its risk oversight responsibilities. The Audit Committee is responsible for the oversight of the integrity of the financial statements, including oversight of the guidelines and policies that govern management’s processes for assessing, monitoring and mitigating major financial risk exposures. The Finance Committee is primarily responsible for the oversight of:

• Financial risks, including liquidity, dividend policy, financial goals and operational plans;

• Strategic risks in connection with significant new business ventures; and

• Risk assessment through the Company’s Enterprise Risk Management (ERM) process.

Our ERM process involves the application of a well-defined, enterprise-wide methodology designed to allow our executives to identify, categorize, prioritize, and mitigate the principal risks to the Company, such as strategic, financial, operational and reputational risks. In addition to known risks, ERM identifies emerging risks as well as risks that are rare and difficult to predict, but which, if they were to occur, would have a significant impact on the Company. The findings of the ERM process are reported periodically to the Finance Committee.

The Board of Trustees and the Finance Committee annually review the Company’s comprehensive operating and strategic plans. The operating plan consists of the goals and objectives for the year, key performance indicators and financial forecasts. The strategic plan consists of long-term corporate goals and objectives, specific strategies to achieve those goals, and action plans designed to implement each strategy. The ERM process is integrated with the annual operating and strategic planning processes. The top enterprise-wide financial risks are identified during the development of the annual operating plan, and are updated and presented periodically to the Finance Committee. Enterprise strategic risks are identified and presented to the Board of Trustees during development of the three-year strategic plans. Detailed risk mitigation plans are updated periodically and presented to the Finance Committee.

ERM also informs the Finance Committee about the activities of the Company’s Risk and Capital Committee (RaCC). The RaCC consists of the senior executives of the Company, and it is responsible for ensuring that the Company is managing its principal enterprise wide risks, including large capital and non-capital projects, with a focus on project risk assessments and mitigations, as well as other key risk areas such as credit, environmental, information technology, compliance and business continuity risks.

In addition, each Board committee oversees risks within its area of responsibility. For example, the Board of Trustees administers its compensation risk oversight function primarily through its Compensation Committee. The process by which the Board and the Compensation Committee oversee executive compensation risk is described in greater detail on page 31.

Board Committees and Responsibilities

During 2011, the Board of Trustees of Northeast Utilities had six standing committees: Audit, Compensation, Corporate Responsibility, Corporate Governance, Executive and Finance, each of which consisted of members appointed by the Trustees upon the recommendation of the Corporate Governance Committee. None of the committee members in 2011 was employed by Northeast Utilities or its subsidiaries except for Mr. Shivery, who served as Chairman of the Board, President and Chief Executive Officer and who was a member of the Executive Committee. The Corporate Governance Committee performed the functions of a nominating committee.

In accordance with the Merger Agreement, following the completion of the Merger, the Board of Trustees has five standing committees: Audit, Compensation, Corporate Governance, Executive and Finance, each of which consists of an equal number of Northeast Utilities Designees and NSTAR Designees, respectively. The

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Board has adopted a written charter for each standing committee as well as written Corporate Governance Guidelines. The Corporate Governance Guidelines and committee charters are available on our website at the Internet addresses appearing in the committee descriptions below. Copies of these documents are available to any shareholder upon written request to our Assistant Secretary at the address set forth on page 7 of this proxy statement. The functions of these committees are described in the paragraphs following the table.

The table below shows the committee membership:

Board Committees

Trustee	Audit		Compensation		Corporate Governance		Executive		Finance
Richard H. Booth		C						M		M
John S. Clarkeson		M		M
Cotton M. Cleveland						M				M
Sanford Cloud, Jr. *				M		C		M
James S. DiStasio				M				M		C
Francis A. Doyle						M				M
Charles K. Gifford				C		M		M
Paul A. La Camera		M				M
Kenneth R. Leibler		M								M
Thomas J. May								M
Charles W. Shivery								C
William C. Van Faasen		M		M
Frederica M. Williams		M								M
Dennis R. Wraase				M		M

C: Committee Chair

M: Committee Member

* Lead Trustee

Set forth below is a brief summary of the functions performed by the existing Board committees.

Audit Committee

The Audit Committee consists of Mr. Booth (Chair), Mr. Clarkeson, Mr. La Camera, Mr. Leibler, Mr. Van Faasen and Ms. Williams. The Audit Committee meets independently with the internal and independent registered public accountants of Northeast Utilities and its subsidiaries and with management at least quarterly. Following each committee meeting, the Audit Committee reports to the full Board. The Audit Committee reviews and evaluates the independent registered public accountants’ activities, procedures and recommendations to assist the Board in monitoring the integrity of our financial statements, the independent registered public accountants’ qualifications and independence, the performance of our internal audit function and independent registered public accountants, and our compliance with legal and regulatory requirements. The Committee also discusses the guidelines and policies that govern management’s processes for assessing, monitoring and mitigating major financial risk exposures. The Audit Committee has the sole authority to select and replace the independent registered public accountants and is directly responsible for their compensation and oversight of their work. Each member of the Audit Committee meets the financial literacy requirements of the New York Stock Exchange (“NYSE”) and the SEC. The Board has affirmatively determined that Messrs. Booth and Leibler are “audit committee financial experts,” as defined by the SEC. Each member of the Audit Committee meets the independence requirements of the NYSE, SEC and our Corporate Governance Guidelines. No member of the Audit Committee is employed by Northeast Utilities or its subsidiaries. A copy of the Committee’s charter, which has been adopted by our Board of Trustees, is available on our website at www.nu.com/investors/corporate_gov/charter_audit.asp. The Audit Committee met nine times during 2011.

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Compensation Committee

The Compensation Committee consists of Mr. Clarkeson, Mr. Cloud, Mr. DiStasio, Mr. Gifford (Chair), Mr. Van Faasen and Mr. Wraase. The Compensation Committee is responsible for the compensation and benefits programs for all executive officers of Northeast Utilities and has overall authority to establish and interpret our executive compensation programs. The Compensation Committee establishes and reviews our executive compensation strategy, evaluates components of total compensation and assesses performance against goals, market competitive data and other appropriate factors. The Compensation Committee is authorized to grant share awards to our executive officers. The Compensation Committee makes recommendations to the Board with respect to the adoption, amendment or termination of executive compensation and benefits plans, policies and practices. The Compensation Committee has sole authority to select and retain experts and consultants in the field of executive compensation to provide advice to the Committee with respect to market data, competitive information, and executive compensation trends. The Compensation Committee also reviews and approves the compensation of the non-employee members of the Board.

The Compensation Committee reviews and approves corporate goals and objectives relevant to the Chief Executive Officer’s compensation and, with the participation of the Lead Trustee and subject to the further review and approval of the independent Trustees, evaluates the performance of the Chief Executive Officer in light of those goals and objectives. The Compensation Committee establishes performance criteria for the Chief Executive Officer and approves the Chief Executive Officer’s total compensation based on the annual evaluation, subject to further approval by the independent Trustees. In addition, in collaboration with the Chief Executive Officer, the Compensation Committee oversees the evaluation of those executive officers reporting directly to the Chief Executive Officer. The Compensation Committee engages in the succession planning process for the Chief Executive Officer and other officers.

The Compensation Committee retained Semler Brossy Consulting Group (Semler Brossy) to provide compensation consulting services from 2006 to 2012. Following the completion of the Merger, the Compensation Committee retained Pay Governance LLC to provide compensation consulting services. Pay Governance LLC has been engaged to perform work only for the Compensation Committee.

The Compensation Committee has delegated the negotiation of certain compensation arrangements and administration of the Compensation Committee’s responsibilities to certain executive officers. The Compensation Committee has not delegated any of its responsibilities to any other persons. The Board has affirmatively determined that each member of the Compensation Committee meets the independence requirements of the NYSE and the SEC, and our Corporate Governance Guidelines. No member of the Compensation Committee is employed by Northeast Utilities or its subsidiaries. A copy of the Compensation Committee’s charter is available on our website at www.nu.com/investors/corporate_gov/charter _compensation.asp. The Compensation Committee met 11 times during 2011. The Chair of the Compensation Committee reports to the full Board following each committee meeting.

Corporate Governance Committee

The Corporate Governance Committee consists of Ms. Cleveland, Mr. Cloud (Chair), Mr. Doyle, Mr. Gifford, Mr. La Camera and Mr. Wraase. The Corporate Governance Committee is responsible for developing, overseeing and regularly reviewing our Corporate Governance Guidelines and related policies. The Corporate Governance Committee also serves as a nominating committee, establishing criteria for new Trustees, identifying and recommending prospective Board candidates, and reviewing qualifications of Trustees and nominees. In addition, the Corporate Governance Committee evaluates the performance of the Board and its committees. Following each meeting, the Corporate Governance Committee reports to the full Board. No member of the Corporate Governance Committee is employed by Northeast Utilities or its subsidiaries. The Board of Trustees has determined that each member of the Corporate Governance Committee meets the independence requirements of the NYSE and the SEC, and under our Corporate Governance Guidelines. A copy of the Committee’s charter is available on our website at www.nu.com/investors/corporate_gov/charter_corporate_gov.asp. The Corporate Governance Committee met 10 times during 2011.

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Executive Committee

The Executive Committee consists of Mr. Booth, Mr. Cloud, Mr. DiStasio, Mr. Gifford, Mr. May and Mr. Shivery (Chair). The Executive Committee is empowered to exercise all the authority of the Board, subject to certain limitations set forth in our Declaration of Trust, during the intervals between meetings of the Board. A copy of the Committee’s charter is available on our website at www.nu.com/investors/corporate_gov/ charter_corporate_exec.asp. The Executive Committee did not meet in 2011.

Finance Committee

The Finance Committee consists of Mr. Booth, Ms. Cleveland, Mr. DiStasio (Chair), Mr. Doyle, Mr. Leibler and Ms. Williams. The Finance Committee assists the Board in fulfilling its fiduciary responsibilities relating to financial plans, policies and programs for Northeast Utilities and its subsidiaries. The Finance Committee reviews the Company’s plans and actions to assure liquidity; proposed financing programs; plans and recommendations regarding common share repurchase programs, early extinguishment and refunding of debt and preferred stock obligations; and other proposals to modify the Company’s capital structure. The Finance Committee is responsible for reviewing the Company’s risk assessment and risk management policies, its major financial risk exposures, and the steps management has taken to monitor and mitigate such exposures, as further described above under the caption “Board’s Oversight of Risk.” The Finance Committee is also responsible for reviewing the Company’s dividend policy and recommending to the Board the dividend on the Company’s common shares as well as for reviewing new business ventures and initiatives which may result in substantial expenditures, commitments and exposures. Following each meeting, the Finance Committee reports to the full Board. No member of the Finance Committee is employed by Northeast Utilities or its subsidiaries. A copy of the Committee’s charter is available on our website at www.nu.com/investors/corporate_gov/charter_finance.asp. The Finance Committee met nine times during 2011.

Meetings of the Board and its Committees

In 2011, the Board of Trustees held 16 meetings, the independent Trustees held six meetings, and the Board, the independent Trustees and the committees of the Board held a total of 59 meetings, taking into account that certain meetings were jointly held by various committees. The totals above reflect special meetings of the Board and various committees of the Board conducted during 2011 in connection with the Merger with NSTAR. In 2011, each Trustee attended at least 95% of the aggregate number of meetings of the Board of Trustees and meetings of all Committees of the Board held during the periods for which he or she served as a Trustee. All of the Trustees attended the Annual Meeting of Shareholders held on May 10, 2011. Our Trustees are expected to attend our Annual Meetings of Shareholders, but we do not have a formal policy addressing this subject.

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SELECTION OF TRUSTEES

As set forth in its charter, it is the responsibility of the Corporate Governance Committee to identify individuals qualified to become a Trustee and to recommend to the Board a slate of trustee candidates to be submitted to a vote of our shareholders at the Annual Meeting of Shareholders. The Committee has from time to time retained the services of a third party executive search firm to assist it in identifying and evaluating such individuals.

As provided in our Corporate Governance Guidelines, the Corporate Governance Committee seeks nominees with the following qualifications:

Trustees should possess the highest personal and professional ethics, integrity and values, and be committed to representing the long-term interests of our shareholders. They must also have an inquisitive and objective perspective, practical wisdom and mature judgment. The Board should represent diverse experience at policy-making levels in business, government, education, community and charitable organizations as well as areas that are relevant to our business activities. The Corporate Governance Committee also seeks diversity in gender, ethnicity and personal background when considering trustee candidates.

Applying these criteria, the Corporate Governance Committee considers trustee candidates suggested by its members as well as by management and shareholders. As part of the annual nomination process, the Corporate Governance Committee reviews the qualifications, experience, attributes and skills of each nominee for Trustee, including currently serving Trustees, under the Corporate Governance Guidelines and reports its findings to the Board. The Committee commenced its review of the Trustees in February 2012, which included its review of the seven Northeast Utilities Designees. Prior to the completion of the Merger with NSTAR, the Committee also reviewed each of the seven NSTAR Designees. The Committee determined that each Trustee possesses the highest personal and professional ethics, integrity and values, and each Trustee remains committed to representing the long-term interests of our shareholders. The Committee’s reviews also focused on each Trustee’s experience at policy-making levels in business, government, education, community and charitable organizations, and other areas relevant to our business activities, as described below. Based on these reviews, the Committee advised the Board on February 14, 2012 with respect to the Northeast Utilities Designees, on April 9, 2012 with respect to the NSTAR Designees, and on July 17, 2012 with respect to all nominees for election as Trustees, that each of the Trustees was qualified to serve on the Board under the Corporate Governance Guidelines.

Business, Management and Finance. The Board values significant business and management experience at the highest levels, including experience in heavily regulated industries. Many of our Trustees have served as chief executive officers and/or chief financial officers and have served on the board of directors of numerous companies. In addition, the vast majority of our ongoing capital program is expected to be funded through cash flows provided by operating activities as well as new debt issuances and, less frequently, equity issuances. As a result, the Board highly values policy-making level experience in, and understanding of, capital and financial markets, accounting and financial reporting, credit markets, and risk assessment.

Regulatory. Each of our utility subsidiaries is regulated in virtually all aspects of its business by various federal and state agencies, including the SEC, the Federal Energy Regulatory Commission, and various state and/or local regulatory authorities with jurisdiction over the industry and the service areas in which each subsidiary operates. Accordingly, the Board considers policy-making level experience in a heavily regulated industry to be important.

Education/Community and Charitable Organizations. The Board also supports and encourages educational opportunities, community involvement and development, and philanthropic goals and activities. The Northeast Utilities Foundation, Inc. was established in 1998 and the NSTAR Foundation in 1999 to focus on our community investments and to provide grants to our nonprofit community partners. Consistent with our business strategy and core values, the Foundations invest primarily in projects that address issues of economic and community development and the environment. Each Trustee has experience in one or more community or charitable organizations.

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Other Areas Relevant to Our Business Activities. We operate New England’s largest energy delivery system in three different states. Because a majority of our Trustees also reside in our service territory, they not only have ties to local communities, but they understand our customers’ needs.

Diversity. In accordance with our Corporate Governance Guidelines, in addition to diverse business and other experience described above, the Corporate Governance Committee seeks diversity in gender, ethnicity and personal background when considering trustee candidates. Diverse thoughts and views emanating from different backgrounds, life experiences, career experiences and skills are critical to a well-functioning Board and essential to embracing opportunities and confronting challenges in the future. To ensure the success of our business strategy, the Board of Trustees strives to identify and pursue trustee candidates with diverse skills, knowledge, background and experience that complement the skills, knowledge and experience of our current Trustees.

Shareholders wishing to suggest potential candidates for membership on the Board of Trustees may address such information, in writing, to our Assistant Secretary at the mailing address set forth on page 7 of this proxy statement. The communication must identify the writer as a shareholder of Northeast Utilities and provide sufficient detail for the Corporate Governance Committee to consider the individual’s qualifications.

TRUSTEE INDEPENDENCE

We have adopted Corporate Governance Guidelines incorporating independence standards that meet the listing standards of the New York Stock Exchange. The Corporate Governance Guidelines are available on our website at www.nu.com/investors/corporate_gov/guidelines.asp. In addition, we have adopted an additional standard under which a charitable relationship will not be considered to be a material relationship that would impair a Trustee’s independence if a Trustee serves as an officer or director of a charitable organization, and our discretionary charitable contributions to the organization, in the aggregate, do not exceed the greater of: (a) $200,000; or (b) two percent of the organization’s total annual charitable receipts or latest publicly available operating budget. The Trustee Independence Guidelines are available on our website at www.nu.com/investors/corporate_gov/trustee_independence.asp.

The Corporate Governance Committee conducts an annual review of the independence of the members of the Board and reports its findings to the full Board. In addition, prior to the completion of the Merger with NSTAR, the Committee reviewed the independence of the NSTAR Designees. Applying the Corporate Governance Guidelines, the Committee, assisted by legal counsel and based on responses to questionnaires completed by the Trustees, reviewed and considered relationships and transactions between Northeast Utilities, its affiliates and subsidiaries, on the one hand, and each nominee for Trustee, entities affiliated with him or her, and/or any member of his or her immediate family, on the other hand. The Committee also reviewed Northeast Utilities’ charitable donations to organizations where the nominees for Trustee or their immediate family members serve as officers or directors. Similarly, the Committee examined relationships and transactions between each nominee for Trustee and (a) our senior management and (b) our independent registered public accountants. The Committee determined that none of these relationships was material to the nominees for Trustee or likely to impair the independence of any of the nominees for Trustee.

The Board of Trustees separately considered that the utility operating company subsidiaries of Northeast Utilities provide electric service or natural gas service to the residences of Trustees and/or companies at which some of the Trustees were directors or executive officers. These utility services are provided in the ordinary course of business, on an arms’ length basis and pursuant to rates determined by the applicable public utility commission and available to all similar customers of the utility. The Board determined that relationships that exist solely due to an individual or entity purchasing electric service or natural gas service from any of the utility operating company subsidiaries of Northeast Utilities in the ordinary course of business, on an arms’ length basis and pursuant to rates determined by the applicable public utility commission, were not material to the Trustees or likely to impair the independence of any of the Trustees.

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On February 14, 2012, based on the recommendation of the Corporate Governance Committee following its review, the Board of Trustees affirmatively determined that each of the then-serving Trustees, including the Northeast Utilities Designees but excluding Mr. Shivery, who was then serving as our Chairman of the Board, President and Chief Executive Officer, satisfied the independence criteria (including the enhanced criteria with respect to members of the Audit Committee) set forth in the current listing standards and rules of the NYSE and the SEC, and under our Corporate Governance Guidelines. Similarly, on April 9, 2012, based on the recommendation of the Corporate Governance Committee following its review, the Board of Trustees affirmatively determined that each of the NSTAR Designees, excluding Mr. May, who became our Chief Executive Officer and President upon the completion of the Merger, satisfied the independence criteria (including the enhanced criteria with respect to members of the Audit Committee) set forth in the current listing standards and rules of the NYSE and the SEC, and under our Corporate Governance Guidelines. On July 17, 2012, based on the recommendation of the Corporate Governance Committee following its review, the Board of Trustees affirmatively determined that each nominee for election as a Trustee, excluding Messrs. May and Shivery, satisfied the independence criteria (including the enhanced criteria with respect to members of the Audit Committee) set forth in the current listing standards and rules of the NYSE and the SEC, and under our Corporate Governance Guidelines.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The Board of Trustees adopted a Related Party Transactions Policy on December 11, 2007. The Policy is administered by the Corporate Governance Committee. The Policy generally defines a “Related Party Transaction” as any transaction or series of transactions in which (i) Northeast Utilities or a subsidiary is a participant, (ii) the aggregate amount involved exceeds $120,000 and (iii) any “Related Party” has a direct or indirect material interest. A “Related Party” is defined as any Trustee or nominee for Trustee, any executive officer, any shareholder owning more than 5% of our total outstanding shares, and any immediate family member of any such person. Management submits to the Corporate Governance Committee for consideration any proposed Related Party Transaction. The Corporate Governance Committee recommends to the Board of Trustees for approval only those transactions that are in our best interests. Related Party Transactions are considered in light of the requirements set forth in our Standards of Business Conduct, including the Conflicts of Interest Policy, and our Code of Ethics for Senior Financial Officers. If management causes us to enter into a Related Party Transaction prior to approval by the Committee, the transaction will be subject to ratification by the Board of Trustees. If the Board determines not to ratify the transaction, then management will make all reasonable efforts to cancel or annul such transaction.

THE CODE OF ETHICS AND THE STANDARDS OF BUSINESS CONDUCT

We have adopted a Code of Ethics for Senior Financial Officers (Chief Executive Officer, Chief Financial Officer and Controller) and a Standards of Business Conduct which is applicable to all of the Trustees, directors, officers, employees, contractors and agents of Northeast Utilities and its subsidiaries. The Code of Ethics is available on our website at www.nu.com/investors/corporate_gov/code_ethics.asp and our Standards of Business Conduct are available on our website at www.nu.com/investors/corporate_gov/NU_SBC_2007.pdf. You may obtain a printed copy of the Code of Ethics and the Standards of Business Conduct, without charge, by contacting our Assistant Secretary at the address set forth on page 7 of this proxy statement. Any amendments to or waivers under the Code of Ethics or the Standards of Business Conduct will be posted to our website at www.nu.com/investors/corporate_gov/default.asp.

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COMMUNICATIONS FROM SHAREHOLDERS AND OTHER INTERESTED PARTIES

Interested parties, including shareholders, who desire to communicate directly with the Board of Trustees, the non-management Trustees as a group, or individual Trustees, including the Lead Trustee, Mr. Cloud, should send written communications in care of our Assistant Secretary at the mailing address set forth on page 7 of this proxy statement. The Assistant Secretary will review each communication and forward all communications that properly identify the sender to the intended recipient or recipients.

COMMON SHARE OWNERSHIP OF CERTAIN BENEFICIAL OWNERS

The following table provides information as to persons who are known to us to beneficially own more than five percent of the common shares of Northeast Utilities. We do not have any other class of voting securities.

Name and Address of Beneficial Owner	Amount and Nature  of Beneficial Ownership			Percent of Class
BlackRock, Inc.		21,331,498	(1)		6.80	%(1)
40 East 52nd Street
New York, NY 10022
The Vanguard Group, Inc.		16,347,567	(2)		5.21	%(2)
100 Vanguard Blvd.
Malvern, PA 19355
State Street Corporation		15,890,795	(3)		5.06	%(3)
State Street Financial Center
One Lincoln Street
Boston, MA 02111

(1) Based on Schedules 13F-HR filed by BlackRock, Inc. and certain of its subsidiaries on August 13, 2012, reporting holdings as of June 30, 2012 by BlackRock, Inc.; BlackRock Financial Management, Inc.; BlackRock Investment Management (Australia) Limited; BlackRock Asset Management Australia Limited; BlackRock Asset Management Canada Limited; BlackRock Investments Canada, Inc.; BlackRock Advisors, LLC; BlackRock Capital Management, Inc.; BlackRock Fund Advisors; BlackRock Investment Management, LLC; BlackRock Fund Managers Limited; BlackRock Investment Management (UK) Limited; BlackRock (Netherlands) B.V.; BlackRock International Limited; BlackRock Asset Management Ireland Limited; BlackRock Advisors (UK) Limited; BlackRock Asset Management Deutschland AG; BlackRock (Luxembourg) S.A.; BlackRock Life Limited; BlackRock Institutional Trust Company, N.A.; and BlackRock Japan Co., Ltd.

(2) Based on a Schedule 13F-HR filed by The Vanguard Group, Inc. on August 13, 2012, reporting holdings as of June 30, 2012 by The Vanguard Group, Inc.; Vanguard Fiduciary Trust Company; and Vanguard Investments Australia Ltd.

(3) Based on a Schedule 13F-HR filed by State Street Corporation on August 14, 2012, reporting holdings as of June 30, 2012 by State Street Corporation; State Street Bank and Trust Company, SSgA Funds Management, Inc.; State Street Global Advisors LTD; State Street Global Advisors Ltd.; State Street Global Advisors, Australia; State Street Global Advisors (Japan) Co., Ltd.; State Street Global Advisors Asia LTD; and State Street Global Advisors France, S.A.

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COMMON SHARE OWNERSHIP OF TRUSTEES AND MANAGEMENT

The table below shows the number of our common shares beneficially owned as of September 4, 2012, by each of our Trustees and each 2011 Named Executive Officer as well as the number of common shares beneficially owned by all of our Trustees and executive officers as a group. The table also includes information about options, restricted share units and deferred shares credited to the accounts of our Trustees and executive officers under certain compensation and benefit plans. The address for the shareholders listed below is c/o Northeast Utilities, One Federal Street, Building 111-4, Springfield, Massachusetts 01105.

Name of Beneficial Owner	Amount and Nature  of Beneficial Ownership (1)(2)			Percent of Class
Richard H. Booth		39,888			*
Gregory B. Butler		152,282	(3)(4)(5)		*
John S. Clarkeson		16,934			*
Cotton M. Cleveland		43,750			*
Sanford Cloud, Jr.		42,713			*
James. S. DiStasio		9,277			*
Francis A. Doyle		5,857			*
Charles K. Gifford		48,701			*
Paul A. La Camera		36,328			*
Kenneth R. Leibler		20,177			*
Thomas J. May		2,853,235	(4)(6)		*
David R. McHale		187,962	(4)(5)(7)		*
Leon J. Olivier		183,410	(4)(5)		*
James B. Robb		147,262	(4)		*
Charles W. Shivery		786,852	(4)(8)		*
William C. Van Faasen		27,621			*
Frederica M. Williams		2,456			*
Dennis R. Wraase		13,431	(9)		*
All Trustees and Executive Officers as a group (22 persons)		5,413,304	(10)		1.7	%

 * Less than 1% of Northeast Utilities common shares outstanding.

(1) The persons named in the table have sole voting and investment power with respect to all shares beneficially owned by each of them, except as noted below.

(2) Includes restricted share units, deferred restricted share units and/or deferred shares, including dividend equivalents, as to which none of the individuals has voting or investment power, and phantom common shares, representing employer matching contributions distributable only in cash, held by executive officers who participate in our Deferred Compensation Plan for Executives, as follows: Mr. Booth: 38,438 shares; Mr. Butler: 102,241 shares; Mr. Clarkeson: 3,050 shares; Ms. Cleveland: 35,409 shares; Mr. Cloud: 16,372 shares; Mr. DiStasio: 9,277 shares; Mr. Doyle: 1,921 shares; Mr. Gifford: 42,508 shares; Mr. La Camera: 36,328 shares; Mr. Leibler: 3,050 shares; Mr. May: 980,061 shares (811,688 of which are deferred shares held in a rabbi trust that are voted by the trustee); Mr. McHale: 133,370 shares; Mr. Olivier: 121,920 shares; Mr. Robb: 144,068 shares; Mr. Shivery: 706,079 shares; Mr. Van Faasen: 27,621 shares; Ms. Williams: 2,456 shares; and Mr. Wraase: 9,431 shares.

(3) Includes 45,901 common shares owned jointly by Mr. Butler and his spouse with whom he shares voting and investment power.

(4) Includes common shares held in the Company’s 401k Plans invested in employee stock ownership plan accounts over which the holder has sole voting and investment power (Mr. Butler: 3,681 shares; Mr. May: 60,675 shares; Mr. McHale: 4,413 shares; Mr. Olivier: 2,229 shares; Mr. Robb: 937 shares; and Mr. Shivery: 2,340 shares).

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(5) Includes common shares held as units in the 401k Plan invested in the NU Common Shares Fund over which the holder has sole voting and investment power (Mr. Butler: 458 shares; Mr. McHale: 1,993 shares; and Mr. Olivier: 197 shares).

(6) Includes 1,611,136 common shares issuable upon exercise of outstanding stock options exercisable within the 60-day period after September 4, 2012.

(7) Includes 117 common shares held by Mr. McHale in the 401k Plan TRASOP/PAYSOP account over which Mr. McHale has sole voting and investment power.

(8) Includes 1,500 common shares owned jointly by Mr. Shivery and his spouse with whom he shares voting and investment power.

(9) Includes 4,000 common shares owned jointly by Mr. Wraase and his spouse with whom he shares voting and investment power.

(10) Includes 1,880,315 common shares issuable upon exercise of outstanding stock options exercisable within the 60-day period after September 4, 2012, and 2,802,341 unissued common shares. See note 2. Also includes 982,872 deferred shares held in a rabbi trust that are voted by the trustee.

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INTRODUCTORY NOTE

We completed our Merger with NSTAR on April 10, 2012, creating New England’s largest energy delivery system, serving approximately 3.5 million customers in Connecticut, Massachusetts and New Hampshire. As previously described, following the completion of the Merger with NSTAR, Mr. Shivery retired as President and Chief Executive Officer of the Company and was elected as Chairman of the Board of Trustees, and Mr. May became our President and Chief Executive Officer. We also consolidated the two management teams, and are well in the process of integrating many talented executives and employees from both Northeast Utilities and NSTAR into the combined Company.

As required by the rules and regulations of the SEC, the Compensation Discussion and Analysis that appears below describes in detail our compensation program as it existed in 2011, prior to the completion of the Merger. Additionally, the narrative was written as of February 22, 2012, approximately six weeks prior to the completion of the Merger, and filed with the SEC on February 24, 2012 in Part III of our Annual Report on Form 10-K. It provides information about compensation paid to or earned by our Chairman, President and Chief Executive Officer, Executive Vice President and Chief Financial Officer, and the three other most highly compensated executive officers other than the Chief Executive Officer and Chief Financial Officer, all of whom were serving as executive officers at the end of 2011. Information with respect to the 2012 compensation of Mr. May, James J. Judge, our Executive Vice President and Chief Financial Officer, and other current executive officers, including awards to be made for performance in 2012 under our compensation programs and plans, as well as under NSTAR’s compensation programs and plans, will be disclosed in our 2013 proxy statement, which we expect to file in March of 2013.

Upon completion of the Merger with NSTAR on April 10, 2012, outstanding awards under our 2010 — 2012 Long-Term Incentive Program and our 2011 — 2013 Long-Term Incentive Program were finally determined and paid or converted, as the case may be, as described on page 45, below. In addition, certain executive officers who previously served as executive officers of NSTAR, including Mr. May and Mr. Judge, were participants in NSTAR’s Long Term Incentive Plan, whose terms provide that stock compensation awards that were granted prior to October 16, 2010, the date of the Merger Agreement, vest upon the closing of the merger. Mr. Shivery’s change in control severance benefits expired in 2011 when he reached age 65. Accordingly, Mr. Shivery did not receive any severance benefits as a result of the completion of the Merger. He will receive 76,406 common shares, conditioned upon his completion of service as Chairman of the Board of Trustees for a period of eighteen months following the date of the merger closing, as described in the Compensation Discussion and Analysis below.

COMPENSATION DISCUSSION AND ANALYSIS

EXECUTIVE SUMMARY

Pay for Performance Philosophy

Our Compensation Committee follows a philosophy of linking our named executive officers’ compensation to performance that will ultimately benefit customers and shareholders. We use compensation programs to attract and retain the best executive talent and to motivate our executives to exceed specific financial and organizational goals set each year. We strive to provide executives with base salary, performance-based annual incentive compensation and long-term incentive compensation opportunities that are competitive with the market. With respect to incentive compensation, the Compensation Committee believes it is important to balance short-term goals, such as generating earnings, with longer term goals, such as long-term value creation, maintaining a strong balance sheet, system reliability and customer service.

The Compensation Committee makes annual compensation decisions in a thoughtful and deliberate way using data that our independent compensation consultant provides and through open discussion within the

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Committee. The Compensation Committee periodically assesses the risks of our compensation programs and mitigates risks by:

• Rigorous analysis of goal setting in our incentive programs;

• Continuous monitoring of performance and risk;

• Imposing minimum performance thresholds and ceilings on incentive awards; and

• Providing discretion with respect to actual payouts.

In addition, our executives:

• Must comply with share ownership guidelines to more closely link their interests to those of shareholders;

• Are subject to clawback of incentive compensation under certain circumstances; and

• Are provided very few perquisites, all related primarily to business needs.

Alignment of Performance and Compensation

Our compensation philosophy, programs and practices support executive officers and employees as they work to meet and exceed both customer and shareholder expectations. The specific compensation programs that were in place during 2011 were approved during the first quarter of the year and were designed to retain key, talented executives during the continuing uncertainty in the capital markets and weakened economic conditions and incentivize them to create long-term value for customers and shareholders.

Pending Merger with NSTAR

During 2011, our shareholders approved the merger agreement for our pending merger with NSTAR and simultaneously approved an increase in the number of our common shares authorized for issuance. We also received approvals from a number of state and federal regulatory agencies and authorities. We have entered into settlement agreements with the Massachusetts Attorney General and the Massachusetts Department of Energy Resources (“DOER”) agreeing to certain conditions with respect to the merger, which agreements are subject to approval by the Massachusetts Department of Public Utilities (“DPU”) on April 4, 2012. We are also awaiting approval of the merger from the Connecticut Public Utilities Regulatory Authority (“PURA”). After the closing of the transaction, the Company will provide electric and natural gas energy delivery service to approximately 3.5 million electric and natural gas customers through six regulated electric and natural gas utilities in Connecticut, Massachusetts and New Hampshire.

The Compensation Committee faced unique challenges in 2011 related to executive retention and linking compensation of the executives to the interests of our shareholders as the transaction, first announced in October 2010, was pending during the entire year. The Committee acknowledged the critical importance of keeping the management team intact while the merger remained subject to closing conditions and regulatory approvals. In 2010, the Committee had approved a retention pool to be allocated to key employees to help ensure their continued dedication to the Company, both before and after completion of the merger, and to maintain a strong link between compensation and shareholder interests. In 2011, the Committee recommended, and the Board approved, a special grant of 76,406 restricted share units to Mr. Shivery, our Chairman, President and Chief Executive Officer, to recognize the critical role he has had and will play in the successful leadership of the Company through the close of the pending merger and as nonexecutive Chairman of the Board during the post-merger integration period.

During 2011, Mr. Shivery and the management team effectively pursued the federal and state regulatory approvals required to close the merger with NSTAR. At the end of 2011, only the approval of the DPU remained outstanding. However, in January 2012, the PURA revised its earlier decision concluding that it did not have jurisdiction to review the merger and determined that the Company and NSTAR must obtain approval from the

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PURA prior to completing the merger. As a result, approvals from the DPU and PURA are currently outstanding. Mr. Shivery worked closely with NSTAR’s Chief Executive Officer, Thomas J. May, to provide guidance and oversight to the merger integration plan to ensure that the Company is positioned to function effectively immediately after the closing. Members of management from both companies continue to work together closely in merger integration teams tasked with identifying the best practices to be implemented by the Company after the closing.

Storm Responses in 2011

On August 28, 2011, Tropical Storm Irene caused extensive damage to the Company’s electric distribution system. Approximately 800,000 of our 1.9 million electric distribution customers were without power at the peak of the outages, with approximately 670,000 of those customers in Connecticut. On October 29, 2011, an unprecedented snowstorm inundated our service territory with heavy snow, causing significant damage to our distribution and transmission systems. Approximately 1.2 million electric distribution customers were without power at the peak of the outages. The snowstorm was extraordinary, and we set very high performance expectations, a number of which we did not meet. As a result, in November 2011, CL&P established a storm fund reserve of $30 million to provide bill credits to its residential customers who remained without power after noon on Saturday, November 5, 2011, as a result of the October snowstorm, and to provide contributions to certain Connecticut charitable organizations. CL&P also announced changes in senior leadership, appointing officers to lead emergency preparedness as well as infrastructure hardening to make the electric system more resistant to increasingly severe weather related events. As a result, certain members of senior management, including the Named Executive Officers, proposed to the Compensation Committee that they not receive an award under the 2011 Annual Incentive Award, and the Compensation Committee accepted that proposal.

State regulatory agencies in Connecticut, Massachusetts and New Hampshire opened inquiries into the responses of utilities in their states during the October snowstorm, including responses of CL&P, PSNH and WMECO. In addition, in Connecticut, the review included the responses of utilities during Tropical Storm Irene, and a consultant was engaged to conduct an audit into the emergency response programs of CL&P. These inquiries are expected to be completed in the second quarter of 2012.

2011 Financial Performance

In 2011, the Company achieved:

• 2011 earnings of $423.9 million, or $2.38 per share (excluding a charge of $17.9 million, or $0.10 per share, associated with the $30 million storm fund reserve and an after-tax charge of $11.3 million, or $0.06 per share, associated with the merger with NSTAR), compared with 2010 earnings of $387.9 million, or $2.19 per share;

• 2011 Adjusted Net Income (ANI) of $406.0 million (excluding an after-tax charge of $11.3 million, or $0.06 per share, associated with the merger with NSTAR), compared with 2010 ANI of $400.6 million;

• Share price appreciation of 13.1 percent from a closing price of $31.88 on December 31, 2010 to a closing price of $36.07 on December 30, 2011, the last trading day of the year; and

• Total shareholder returns of 16.4 percent for the year ended December 31, 2011 and 67.4 percent for the three years ended December 31, 2011.

In 2011, the execution of the Company’s long-term strategic plan as well as the annual operating and capital plans exceeded expectations. In addition, although approvals from the DPU and PURA remain outstanding, only the approval of the DPU remained outstanding at the end of 2011. The Company has also made significant progress toward integrating the companies after the closing.

For compensation purposes, the Named Executive Officers proposed that they not receive awards under the 2011 Annual Incentive Program and, while recognizing the many notable accomplishments in achieving or exceeding other strategic and operational goals by the Company’s leadership, the Compensation Committee

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accepted that proposal. As a result, notwithstanding strong financial performance and successful execution of the strategic operating plan and annual operating and capital plans in 2011, Mr. Shivery and the other Named Executive Officers did not receive awards under the annual incentive program.

CEO Compensation

Mr. Shivery received total direct compensation of $9,685,241 for 2011, including the special equity grant of 76,406 restricted share units described above, valued at $2,574,118. Excluding the value of the special equity grant, Mr. Shivery received compensation of $7,111,123 for 2011, as compared with $8,254,374 for 2010.

OVERALL OBJECTIVES OF EXECUTIVE COMPENSATION PROGRAM

General

The fundamental objective of our Executive Compensation Program is to motivate executives and key employees to support our strategy of investing in and operating businesses that benefit customers, employees, and shareholders. As a holding company for several regulated utilities, we are also responsible to our franchise customers to provide energy services reliably, safely, with respect for the environment and our employees, and at a reasonable cost.

The Executive Compensation Program supports its fundamental objective through the following design principles:

• Attract and retain key executives by providing total compensation competitive with that of other executives employed by companies of similar size and complexity in the utility and general industries. The program relies on compensation data obtained from consultants’ surveys of companies and from a customized peer group to ensure that compensation opportunities are competitive and capable of attracting and retaining executives with the experience and talent required to achieve our strategic objectives. As we continue to grow and improve our transmission, distribution, and generation systems, having the right talent will be critical.

• Establish performance-based compensation that balances rewards for short-term and long-term business results. The program motivates executives to run the business well in the short-term, while executing the long-term business plan to benefit both our customers and shareholders. The program aims to strike a balance between the short- and long-term programs so that they work in tandem. It also ensures that long-term objectives are not sacrificed to achieve short-term goals or vice versa.

Incentive plan performance criteria are based on a combination of financial, operational, stewardship, and strategic goals that are essential to the achievement of our business strategies. This linkage to critical goals helps to align executives with our key stakeholders: customers, employees, and shareholders. The long-term program also compares performance relative to a group of comparable utility companies.

• Reward corporate and individual performance. Overall compensation has many metrics based on corporate performance but is also highly differentiated based on individual performance. The annual incentive program rewards both corporate performance (measured by adjusted net income) and individual performance (including individualized financial, operational, stewardship and strategic metrics). Long-term incentives consist of performance units (performance shares and performance cash) and restricted share units (RSUs). Performance units are paid out based on the achievement of corporate goals (cumulative net income, average return on equity, average credit rating and relative total shareholder return). The size of RSU grants may reflect corporate performance during the preceding fiscal year as well as individual performance and contribution, but the ultimate value of the RSUs is based on total shareholder return.

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• Encourage long-term commitment to the Company. Utility companies provide a public service and have a long-term commitment to ensure that customers receive reliable service day after day. Meeting this commitment requires specialized skills and institutional knowledge that are learned over time through local industry experience. These skills include familiarity with the regions and communities that we serve, government regulations, and long-term energy policies. In addition, utility companies rely on long-term capital investments to serve their customers.

As a result, public utilities benefit from long-term service employees. We have structured our executive compensation programs to build long-term commitment as well as shareholder alignment. Providing competitive compensation opportunities and offering programs such as RSUs and supplemental retirement benefits that vest and have the ability to increase in value over time encourage long-term employment. Executive share ownership guidelines are another program component intended to build long-term shareholder alignment and commitment.

The Company provides its shareholders with the opportunity to cast an annual advisory vote on executive compensation (a “say-on-pay” proposal). At the Company’s annual meeting of shareholders held in May 2011, over 97 percent of the votes cast on the say-on-pay proposal were voted to approve the compensation of the Named Executive Officers, as described in our 2011 proxy statement. The Compensation Committee believes this affirms shareholders’ support of the executive compensation program, and the Committee did not make any changes to the executive compensation program in 2011 as a result of the say-on-pay vote. The Compensation Committee will continue to consider the outcome of the Company’s say-on-pay votes when making future compensation decisions for the Named Executive Officers.

NAMED EXECUTIVE OFFICERS

The executive officers listed in the Summary Compensation Table in this proxy statement whose compensation is discussed in this CD&A are referred to as the “Named Executive Officers” or “NEOs.” For 2011, the Named Executive Officers are:

• Charles W. Shivery, Chairman of the Board, President and Chief Executive Officer

• David R. McHale, Executive Vice President and Chief Financial Officer

• Leon J. Olivier, Executive Vice President and Chief Operating Officer

• Gregory B. Butler, Senior Vice President and General Counsel

• James B. Robb, Senior Vice President-Enterprise Planning and Development of Northeast Utilities Service Company

RISK ANALYSIS OF EXECUTIVE COMPENSATION PROGRAM

The overall compensation program features a mix of compensation elements ranging from a fixed base salary that is risk-neutral to annual and long-term incentive compensation programs intended to motivate officers and eligible employees to achieve individual and corporate performance goals that reflect the appropriate assessment of risk. The fundamental objective of the compensation program is to foster the continued growth and success of our business. The design and implementation of the overall compensation program provides the Compensation Committee with opportunities throughout the year to assess risks within the compensation program that may have a material effect on the Company and our shareholders.

Each year, as part of its annual planning process, the Board of Trustees and its Finance Committee review the Company’s comprehensive annual operating and five-year strategic plans. The annual operating plan consists of the goals and objectives for the year, key performance indicators and financial forecasts. The strategic plan consists of long-term corporate goals and objectives, specific strategies to achieve those goals, and action plans designed to implement each strategy. The Enterprise Risk Management (ERM) process is integrated into the

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annual operating planning and the strategic planning processes. The most significant enterprise-wide financial risks are identified during development of the annual operating plans, and are updated and presented monthly to the Finance Committee. Enterprise strategic risks are identified and presented to the Board during development of the five-year strategic plans. Following review and approval of the annual operating and strategic plans by the Board of Trustees and the Finance Committee, the Compensation Committee reviews the overall compensation program in the context of both plans. In particular, the Compensation Committee designs the annual and long-term incentive compensation programs for officers and eligible employees to promote the achievement of the goals and objectives of the annual operating plan and the strategic plan that were each previously subjected to ERM review.

In 2009, the Compensation Committee assessed the risks associated with the executive compensation program by specifically reviewing the various elements of the incentive compensation programs. The annual incentive program was reviewed to ensure an appropriate balance between the individual and corporate goals and that the goals were appropriate to support the annual business plan. Similarly, the long-term incentive program was reviewed to ensure that the performance metrics were properly weighted and supported the Company’s strategic plan. Both the annual and long-term incentive programs were reviewed to ensure that mechanisms exist to mitigate risk, which mechanisms include goal setting and discretion with respect to actual payments, share ownership guidelines, clawback of incentive compensation under certain circumstances, and deferral of certain long-term incentive awards. Key elements of the executive compensation program have not changed since the review in 2009.

The Compensation Committee periodically assesses the risks of our compensation programs and mitigates risks by continuous monitoring of performance and risk.

ELEMENTS OF 2011 COMPENSATION

Set forth below is a brief description and the objective of each material element of our executive compensation program:

Compensation Element	Description	Objective
Base Salary	Fixed compensation	Compensate officers for fulfilling their basic job responsibilities
	Subject to increase annually during the first quarter based on individual performance, competitive market levels, strategic importance of the role and experience in the position	Provide base pay commensurate with salaries paid to executive officers holding comparable positions in other utility companies and companies in general industry Aid in attracting and retaining qualified personnel
Annual Incentive Program	Variable compensation based on performance against pre-established annual corporate and individual goals that is paid in cash in the first quarter following the end of the program year	Promote the achievement of annual performance objectives that represent business success for the Company, the executive, and his business unit or function

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Compensation Element	Description	Objective
Long-Term Incentive Program	Variable compensation consisting of 75% Performance shares and 25% RSUs (see below)
• Restricted share units (RSUs)	Common share units, which vest over a three-year period, may be granted based on corporate performance and individual performance and contribution	Align executive and shareholder interests through share performance and share ownership Encourage a long-term commitment to the Company
• Performance shares	Long-term incentive, consisting solely of performance shares, that rewards individuals for corporate performance over a three-year period based on achieving pre-established levels of: •   Cumulative net income •   Average return on equity •   Average credit rating •   Total shareholder return relative to a group of comparable utility companies	Reward performance on key corporate priorities that are also key drivers of total shareholder return performance Align executive and shareholder interests through share performance and share ownership Strengthen the link between long-term compensation and total shareholder return performance Encourage long-term planning and commitment to the Company
Supplemental Benefits	Supplemental Executive Retirement Plan, Nonqualified Deferred Compensation, and Perquisites	Supplemental benefits intended to help us attract and retain executive officers critical to our success by reflecting competitive practices
• Supplemental Executive Retirement Plan (Supplemental Plan)	Non-qualified pension plan, providing additional retirement income to officers beyond payments provided in our standard defined benefit retirement plan, consisting of: •   A defined benefit “make-whole” plan •   A supplemental “target” benefit (certain senior vice presidents and above only) Executives hired after 2005 are ineligible for these benefits	Compensate for Internal Revenue Code limits on qualified plans Aid in retention of executives and enhance long-term commitment to the Company
• Other Nonqualified Deferred Compensation (Deferral Plan)	Opportunity to defer base salary and annual incentives, using the same investment vehicles as our qualified 401(k) plan, and receive matching contributions otherwise capped by Internal Revenue Code limits on qualified plans Each year’s matching contribution vests after three years or at retirement	Aid executives in tax planning by allowing them to defer taxes on certain compensation Compensate for Internal Revenue Code limits on qualified plans Provide a competitive benefit Aid in retention and enhance long-term commitment to the Company

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Compensation Element	Description	Objective
	For executives hired after 2005, who are ineligible to participate in our defined benefit pension plan, we make contributions of 2.5%, 4.5% and 6.5%, as applicable based on the relevant bracket for the sum of the officer’s age and years of service, of cash compensation that would otherwise be capped by Internal Revenue Code limits on qualified plans
• Med-Vantage Plan	For executives hired after 2005, who are ineligible to participate in our defined benefit pension plan, starting at age 40 we make contributions of $1,000 per year to a qualified retiree medical savings account	Designed to help build tax-free savings for post-employment health care expenses
• Perquisites	Tax preparation and financial planning reimbursement benefit (certain senior executives) Executive physical examination reimbursement plan	Encourage use of a professional tax advisor to properly prepare complex tax returns and leverage the value of our compensation programs
	Reimbursement of relocation expenses for newly hired and transferred executives Reimbursement of spousal travel expenses only for business purposes	Encourage executives to undergo regular health checks to reduce the risk of losing critical employees Discretionary benefits intended to help our executive officers be more productive and efficient
Employment Agreements	Employment or other agreements with certain of our Named Executive Officers provide benefits and payments upon involuntary termination and termination following a change of control. Mr. Olivier participates in a “Special Severance Program” (SSP) that provides other benefits and payments upon termination of employment resulting from a change-in-control	Meet competitive expectation of employment Help focus executive on shareholder interests Provide income protection in the event of involuntary loss of employment

MIX OF COMPENSATION ELEMENTS

We strive to provide executive officers with base salary, performance-based annual incentive compensation and long-term incentive compensation opportunities that are competitive with the market. The Compensation Committee determines the Total Direct Compensation for our Named Executive Officers as described under the caption entitled “Market Analysis,” below. As a result, the target mix of compensation for our CEO and the other executive officers listed in the Summary Compensation Table are approximately equal to competitive median incentives.

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With respect to incentive compensation, the Compensation Committee believes it is important to balance short-term goals, such as generating earnings, with longer term goals, such as long-term value creation and maintaining a strong balance sheet. As our executive officers are promoted to more senior positions, they assume increased responsibility for implementing our long-term business plans and strategies, and a greater proportion of their total compensation is based on performance with a long-term focus.

The Compensation Committee determines the compensation for each executive officer based on the relative authority, duties and responsibilities of each office. Our CEO’s responsibilities for the daily operations and management of the Northeast Utilities System companies are significantly greater than the duties and responsibilities of our other executive officers. As a result, our CEO’s compensation is significantly higher than the compensation of our other executive officers. We regularly review market compensation data for executive officer positions similar to those held by our executive officers, including our CEO, and this market data continues to indicate that chief executive officers are typically paid significantly more than other executive officers. For 2011, target annual incentive and long-term incentive compensation opportunities for our CEO were 100% and 300% of base salary, respectively. For the remaining NEOs, target annual incentive compensation opportunities ranged from 50% to 65% of base salary and target long-term incentive compensation opportunities ranged from 100% to 150% of base salary.

The following table sets forth the contribution to 2011 Total Direct Compensation (TDC) of each element of compensation, at target, reflected as a percentage of TDC, for each Named Executive Officer.

	Percentage of TDC at Target
				Performance Based (1)
							Long-Term Incentives (2)
Named Executive Officer	Base Salary			Annual Incentive			Performance Units			RSUs (3)			TDC
Charles W. Shivery		20	%		20	%		45	%		15	%(4)		100	%
David R. McHale		32	%		20	%		36	%		12	%		100	%
Leon J. Olivier		32	%		20	%		36	%		12	%		100	%
Gregory B. Butler		32	%		20	%		36	%		12	%		100	%
James B. Robb		40	%		20	%		30	%		10	%		100	%
NEO average, excluding CEO		34	%		20	%		34.5	%		11.5	%		100	%

(1) The annual incentive compensation element and performance units under the long-term incentive compensation element are performance-based.

(2) Long-term incentive compensation at target consists of 75% performance units and 25% RSUs.

(3) RSUs vest over three years contingent upon continued employment.

(4) Excludes 76,406 RSUs granted to Mr. Shivery in 2011 to recognize the critical role he has had and will play in the successful leadership of the Company through the close of the proposed merger with NSTAR and as nonexecutive Chairman of the Board during the post-merger integration period.

MARKET ANALYSIS

The Compensation Committee strives to provide our executive officers with target compensation opportunities over time at or above the median compensation levels for executive officers of companies comparable to us. The Committee determined executive officer TDC levels in two steps. First, the Committee determined the “market” values of executive officer compensation elements (base salaries, annual incentives and long-term incentives) as well as total compensation using compensation data obtained from other companies. The Committee reviewed compensation data obtained primarily from utility and general industry surveys and, secondarily, from a customized group of peer utility companies. The Committee then reviewed the compensation elements for each executive officer with respect to the median of these market values, and considered individual performance, experience and internal pay equity to determine the amount, if any, by which the various

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compensation elements should differ from median market values. Significantly, the Committee has not made an explicit commitment to compensate our executive officers through a firm and direct connection between the compensation paid by us and the compensation paid by any of the companies in the utility and general industry surveys or in the customized group of peer utilities.

Set forth below is a description of the sources of the compensation data used by the Compensation Committee when reviewing 2011 compensation:

• Utility and general industry survey data. The Committee analyzed compensation information obtained from surveys of diverse groups of utility and general industry companies that represent our market for executive officer talent. The Committee used size-adjusted utility and general industry survey data to determine base salaries and incentive opportunities. Then the Committee compared utility-specific executive officer positions, including our Executive Vice President and Chief Operating Officer, to utility-specific market values. For executive officer positions that have counterparts in general industry, including our CEO; Executive Vice President and Chief Financial Officer; Senior Vice President and General Counsel; and Senior Vice President-Enterprise Planning and Development, the Committee averaged general industry comparisons with utility industry comparisons weighted equally, as both groups represent the talent market for these executive officers.

• Customized peer group data. The Committee also evaluated compensation data obtained from reviews of proxy statements from our customized group of peer utility companies. Periodically, the Committee assesses the composition of our customized peer group to ensure that the number of companies is sufficient and the companies have reasonably similar revenues. The Committee reviewed the composition of our customized peer group in 2011 and compared the group against our size guidelines of revenues between approximately $3 billion and $12 billion. Notwithstanding the Compensation Committee’s desire to maintain a consistent set of peer companies from year to year to avoid volatility in competitive compensation findings used for comparison across companies, the peer group selected by the Committee in 2011 included two fewer utilities than the group used in 2010. One company was omitted because it had been acquired, while a second company was omitted because it fell outside the Committee’s revenue guidelines. As a result, in support of executive pay decisions during 2011, our customized peer group consisted of utilities with annual revenues that ranged from $2.3 billion to $10.6 billion with median annual revenues of $4.6 billion. We will continue to monitor their size to determine if they should be removed from the peer group in the future. The Committee considered data only for those executive officer positions where there is a title match, which in 2011 included the CEO, Chief Operating Officer, Chief Financial Officer, and General Counsel. For 2011, the peer group consisted of the following 18 companies:

Alliant Energy Corporation	Integrys Energy Group Inc.	Pinnacle West Capital Corporation
Ameren Corporation	NiSource Inc.	Progress Energy, Inc.
CenterPoint Energy, Inc.	NSTAR	SCANA Corporation
CMS Energy Corporation	NV Energy, Inc.	TECO Energy, Inc.
DTE Energy Company	OGE Energy Corp.	Wisconsin Energy Corporation
Great Plains Energy Incorporated	Pepco Holdings, Inc.	Xcel Energy Inc.

The Committee periodically adjusts the target percentages of annual and long-term incentives based on the survey data to ensure that they continue to represent market median levels. Any adjustments are made gradually over time to avoid radical changes. The Committee used compensation data obtained from the companies listed above for insights into incentive compensation design practices and compensation levels, although no specific actions were taken in 2011 directly as a result of this information. In 2011, the Committee also used this group for performance comparisons under the 2011 — 2013 Long-Term Incentive Program.

The Compensation Committee also (i) determines perquisites to the extent they serve business purposes and (ii) sets supplemental benefits at levels that provide market-based compensation opportunities to the executive officers. The Committee periodically reviews the general market for supplemental benefits and perquisites using

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utility and general industry survey data, sometimes including data obtained from companies in the customized peer group. Benefits are adjusted occasionally to help maintain market parity. When the market trend for supplemental benefits reflects a general reduction (e.g., the elimination of defined benefit pension plans), the Committee has reduced these benefits only for newly hired officers. The Committee reviewed our supplemental retirement practices most recently in 2005 and 2006, as described in more detail below under the caption entitled “Supplemental Benefits.”

BASE SALARY

The Compensation Committee reviews executive officers’ base salaries annually. The Committee considers the following specific factors when setting or adjusting base salaries:

• Annual individual performance appraisals

• Market pay movement across industries (determined through market analysis)

• Targeted market pay positioning for each executive officer

• Individual experience and years of service

• Changes in corporate focus with respect to strategic importance of a position

• Internal equity

Individuals who are performing well in strategic positions are likely to have their base salaries increased more significantly than other individuals. From time-to-time, economic conditions and corporate performance have caused salary increases to be postponed. The Committee prefers to reflect subpar corporate performance through the variable pay components.

INCENTIVE COMPENSATION

The annual incentive program and the long-term incentive program are provided under the Northeast Utilities Incentive Plan, which was approved by our shareholders at the 2007 Annual Meeting of Shareholders. The annual incentive program provides cash compensation intended to reward performance under our annual operating plans. The long-term incentive program is designed to reward demonstrated performance and leadership, motivate future superior performance, align the interests of the executive officers with those of our shareholders and retain the executive officers during the term of grants. The annual and long-term programs are intended to work in tandem so that achievement of our annual goals leads us towards attainment of our long-term financial goals.

Incentive grants are based on objective financial performance goals established by the Compensation Committee with the advice of the Finance Committee. The Compensation Committee sets the performance goals annually for new annual incentive and long-term incentive program performance periods, depending on our business focus for the then-current year and the long-term strategic plan.

2011 ANNUAL INCENTIVE PROGRAM

The 2011 Annual Incentive Program consisted of a corporate goal plus individual goals for each NEO. The Compensation Committee set the annual incentive compensation targets for 2011 at 100% of base salary for our CEO and at 50% to 65% of base salary for the other NEOs. The annual incentive compensation targets are used as guidelines for the determination of annual incentive payments, but actual annual incentive payments may vary significantly from these targets, depending on individual and corporate performance. Actual annual incentive payments may equal up to two times target if we achieve superior financial and operational results. The opportunity to earn up to two times the incentive target reflects the Compensation Committee’s belief that executive officers have significant ability to affect performance outcomes. However, we do not pay annual incentive awards if minimum levels of financial performance are not met. A total of 33 officers, including the NEOs, participated in the 2011 Annual Incentive Program.

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2011 Corporate Goal

The objective of the 2011 Annual Incentive Program corporate goal for the NEOs was to achieve an adjusted net income (ANI) target established by the Compensation Committee. ANI is defined as consolidated Northeast Utilities net income adjusted to exclude the effect of certain nonrecurring income and expense items or events. The Committee uses ANI because it believes that ANI serves as an indicator of ongoing operating performance. The minimum payout under the corporate goal was set at 50% of target and would have occurred if actual ANI had been 90% of the ANI target. The maximum payout under the corporate goal was set at 200% of target and would have occurred if actual ANI had been at least 110% of the ANI target.

For 2011, the Compensation Committee established the ANI target at $415.8 million. The ANI target reflects the midpoint of the range of internal ANI estimates calculated at the beginning of the year. The ANI thresholds for the individual and corporate goals appear below (dollars in millions):

Threshold For Individual Goals (20% below ANI Target)	Minimum Corporate Goal (10% below ANI Target)	2011 ANI Target	Maximum Corporate Goal (10% above ANI Target)	Actual 2011 ANI
$332.6	$374.2	$415.8	$457.4	$406.0

The Compensation Committee set the ANI threshold for achieving individual goals and the minimum and maximum corporate goals in its discretion based on the following factors:

• An assessment of the potential volatility in results through an evaluation of critical elements of the strategic business plan, both individually and in combination with each other;

• The degree of difficulty in achieving the ANI target; and

• The minimum acceptable ANI.

At the time that the Compensation Committee established the performance goals for 2011, the Committee also considered and agreed upon exclusions from ANI consisting of certain nonrecurring income and expense items or events that were either beyond the control of management generally or related to a decision by the Committee not to penalize executive officers for making correct strategic business decisions. The Compensation Committee approved all final exclusions from ANI. The income and expense items set forth below were excluded from ANI in 2011.

Excluded Categories	Specific  2011 Adjustments ($ in millions)
Incremental NSTAR merger costs		(11.3	)
Net Adjustments:	$	(11.3	)

2011 Individual Goals

The 2011 Annual Incentive Program individual goals included various financial, operational, stewardship, and strategic metrics that are drivers of overall corporate performance. The achievement of individual goals would result in an annual incentive payment only if actual ANI is at least 80% of the ANI target. Upon achieving this ANI threshold, the maximum payout is possible for individual goals for every participant.

This 80% ANI threshold satisfies the requirements of Section 162(m) of the Internal Revenue Code. The Committee acts in its discretion under Section 162(m) and related Internal Revenue Service rules and regulations to ensure that incentive compensation payments are “qualified performance based compensation” not subject to the $1 million limitation on deductibility.

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The Compensation Committee acting jointly with the Corporate Governance Committee determines the CEO’s proposed annual incentive program payment based on the extent to which individual and corporate goals have been achieved. The Compensation Committee recommends to the Board of Trustees for approval the proposed award for the CEO. For the remaining NEOs, the CEO recommends annual incentive awards to the Compensation Committee for its approval. NEOs are eligible to receive up to two times the annual incentive compensation target for the individual portion of the award.

Goal Weightings and Individual Goals for 2011

The following table sets forth the weighting of the annual incentive program corporate goal and individual goals for each NEO for 2011. These weightings reflect the Compensation Committee’s desire to balance individual accountability with teamwork across the organization. Individual goals for our NEOs range from 40% to 50% of the total annual incentive program target. Certain of our NEOs’ individual performance goals are subjective in nature and cannot be measured either by reference to existing financial metrics or by using pre-determined mathematical formulas. The Committee believes that it is important to exercise judgment and discretion when determining the extent to which each NEO satisfies subjective individual performance goals. The Committee considers these goals along with several factors, including overall individual performance, corporate performance, prior year compensation and the other factors discussed below.

Name and Principal Position	Corporate Goal Weighting			Individual Goal Weighting			Brief Description of Material Individual Goals
Charles W. Shivery Chairman of the Board, President, and Chief Executive Officer		60	%		40	%	Complete the merger with NSTAR on terms that meet the objectives approved by the Board of Trustees and outlined in the merger documents (25% of individual goals). Working with NSTAR CEO Thomas J. May, actively provide oversight to the integration planning process to ensure that the Company functions effectively after the closing. Special emphasis to be placed on the cultural changes necessary to generate the anticipated benefits of the merger (25% of individual goals). Operating as an independent company until the merger is completed, effectively execute the Company’s approved 2011 operating and capital plan (20% of individual goals). Operating as an independent company until the merger is approved, continue to execute the key elements of the Company’s 2011-2015 strategic plan (20% of individual goals). Until the merger is completed, continue to embed sustainability into the Company’s operations and relationships with its key stakeholders. Continue to improve the Company’s reputation among the various stakeholders. Take an active role in evolving energy policy nationally, regionally and in each our jurisdictional states (10% of individual goals).
David R. McHale Executive Vice President and Chief Financial Officer		60	%		40	%	As lead integration officer for the merger with NSTAR, working with the integration project management team, lead the design and implementation of the merger integration effort (40% of individual goals).

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Name and Principal Position	Corporate Goal Weighting			Individual Goal Weighting			Brief Description of Material Individual Goals
							Achieve the 2011 financial plan to meet funding and liquidity requirements necessary to achieve the 2011 operating plan. Support on-going rate cases and develop and implement a regulatory strategy which meets the objectives of the 2011 operating plan. Develop strategic alignment between the shared services organization and operating businesses while effectively managing costs and efficient delivery of services (25% of individual goals). Implement the 2011 Talent Management Program and develop a new organization to support the merger with NSTAR (15% of individual goals). Continue to execute the Company’s strategy that brings customer focus to the forefront of the organization (5% of individual goals). Support and advance the Company’s strategy and position the Company to successfully pursue new opportunities. Position the Company to finance current and future growth while ensuring the integrity of the Company’s financial position (5% of individual goals). Communicate the Company’s strategy and financial position throughout the organization and with external stakeholders, with an
							emphasis on investors, shareholders, members of the financial community and employees with respect to the merger with NSTAR (5% of individual goals). Manage the CFO and Shared Services budget and capital expenditures (5% of individual goals).
Leon J. Olivier Executive Vice President and Chief Operating Officer		50	%		50	%	Achieve the Company’s 2011 operating plans, with special emphasis on plan execution, process improvement and meeting the transmission and operating companies’ operational objectives (35% of individual goals). Advance the Company’s strategic objectives with special emphasis on the NEEWS project, the Northern Pass project, a successful outcome in the Yankee Gas Rate Case and achieving integration goals in the merger with NSTAR (35% of individual goals). Meet major customer experience 2011 initiatives, including customer satisfaction improvement, meter data management, and 2011 customer experience metrics (10% of individual goals). Implement safety improvement initiatives in support of measurable improvements in overall safety results (10% of individual goals). Work with CEO and executive team to build stakeholder confidence; apply rigorous financial performance management across all companies (10% of individual goals).

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Name and Principal Position	Corporate Goal Weighting			Individual Goal Weighting			Brief Description of Material Individual Goals
Gregory B. Butler Senior Vice President and General Counsel		50	%		50	%	Provide strategic counsel to the Board of Trustees, CEO, and management to review and assess future strategic opportunities (35% of individual goals). Support implementation of the Company’s operating and capital plans (20% of individual goals). Develop legislative, regulatory, legal and communications plans to implement the Company’s 2011-2015 strategic plan (20% of individual goals). Contribute to the development of the Company’s view on major energy and environmental policy issues as necessary to position the Company as a leading regional and national expert on energy issues (10% of individual goals). Increase and make more effective engagement of employees in Legal and Governmental Affairs departments through talent management, succession planning, and individual career and professional development. Develop, manage and execute plan to effectively and efficiently integrate with the NSTAR legal department following the merger (5% of individual goals). Provide leadership to ensure high quality customer support in the Legal and Governmental Affairs departments to help the company advance overall customer experience (5% of individual goals). Successfully manage legal and corporate affairs areas within established budgets (5% of individual goals).
James B. Robb Senior Vice President — Enterprise Planning and Development, Northeast Utilities Service Company		50	%		50	%	Finalize Smart Grid Road Map recommendations. Continue to develop electric vehicle strategies. Support Distribution Asset Management strategy development process (15% of individual goals). Refocus research and development efforts across the Company (EPRI, UCONN, Utility Technology Challenge). Conduct successful research and development pilots (15% of individual goals). Continue to evolve the Company’s understanding of the regional power market and emerging opportunities to drive profitable growth (15% of individual goals). Evolve the Company’s “policies” statements and preferred outcomes around carbon, renewables, transmission rules, energy efficiency and market structure. Work with Governmental Affairs in crafting policy strategies (15% of individual goals). Continue to build the Company’s reputation as a national and regional thought leader on energy sector issues (10% of individual goals).

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Name and Principal Position	Corporate Goal Weighting	Individual Goal Weighting	Brief Description of Material Individual Goals
			Keep Northern Pass project on track. Transition full implementation of leadership after receipt of FERC approval (10% of individual goals). Support operating subsidiaries and strategic projects as required (10% of individual goals). Engage employees in strategy issues and the Company’s direction through live presentations, intranet and other communication outlets (5% of individual goals). Effectively integrate relevant planning and analytic functions of the Company and NSTAR (5% of individual goals).

2011 Results

The 2011 actual ANI was $406.0 million. However, as discussed in the Executive Summary, above, the Named Executive Officers proposed to the Committee that they not receive awards under the 2011 Annual Incentive Program, and the Committee accepted that proposal.

CEO Evaluation

The Compensation Committee and the Corporate Governance Committee assessed Mr. Shivery’s performance during 2011. The Committee determined that Mr. Shivery’s execution of our long-term strategic plan as well as our 2011 operating and capital plans exceeded expectations. The Company delivered improved financial performance with strong control over costs and sound operations.

During 2011, Mr. Shivery and the management team aggressively pursued the federal and state regulatory approvals required to close the pending merger with NSTAR. Through his leadership and direction, only the approval of the DPU remained outstanding at the end of 2011. Currently, approvals from the DPU and PURA remain outstanding and efforts continue to obtain them. Mr. Shivery worked closely with NSTAR’s Chief Executive Officer, Thomas J. May, to provide guidance and oversight to the merger integration process to ensure that the Company is positioned to function effectively immediately after the closing.

As described above, notwithstanding strong financial performance, successful execution of the strategic operating plan and annual operating and capital plans, and significant accomplishments in connection with the pending merger with NSTAR during 2011, for compensation purposes, Mr. Shivery proposed to the Committee that he not receive an award under the annual incentive program, and the Committee accepted his proposal.

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Evaluations of Other Named Executive Officers

The Compensation Committee also reviewed the individual performance of each of the other NEOs. These factors included the scope of each NEO’s responsibilities, performance, and impact on or contribution to our corporate success and growth. None of the NEOs listed below received awards under the 2011 Annual Incentive Program.

Name and Principal Position	Annual Incentive Payment		2011 Accomplishments
David R. McHale Executive Vice President and Chief Financial Officer	$	0	The Compensation Committee determined that Mr. McHale and his organization effectively managed the regulatory approval process for the pending merger with NSTAR. In addition, Mr. McHale demonstrated leadership and initiative in managing all aspects of the merger integration process. Mr. McHale and his team successfully executed the 2011 financing plan, issuing debt on favorable terms, and maintaining and enhancing liquidity through a period of continued economic contraction
Leon J. Olivier Executive Vice President and Chief Operating Officer	$	0	The Committee determined that Mr. Olivier and his team successfully executed the 2011 operating plans and the five-year strategic plan. Mr. Olivier’s significant accomplishments in 2011 included the achievement of important objectives related to the NEEWS project and merger integration. Mr. Olivier also exceeded objectives for customer service performance measurements and effectively completed the 2011 capital program.
Gregory B. Butler Senior Vice President and General Counsel	$	0	The Compensation Committee determined that Mr. Butler provided comprehensive strategic counsel to the Board of Trustees, CEO, and management, including in connection with the pending merger with NSTAR. Mr. Butler and his organization effectively managed the regulatory approval process for the NSTAR merger. He and his team contributed significantly to supporting the Company’s 2011 operational and strategic objectives, including the NEEWS project, and continued to position the Company as a leading regional and national expert on energy issues.
James B. Robb Senior Vice President — Enterprise Planning and Development	$	0	The Compensation Committee determined that Mr. Robb and his team continued to enhance the Company’s understanding of the regional power market and emerging opportunities, including in particular opportunities in solar power and natural gas. Mr. Robb and his team continued to evolve the Company’s policies with respect to renewable energy, energy efficiency and carbon, and to enhance the Company’s reputation as a national leader on energy issues.

LONG-TERM INCENTIVE PROGRAMS

General

Under our Long-Term Incentive Programs, the Compensation Committee acting jointly with the Corporate Governance Committee recommends to the Board of Trustees a long-term incentive target grant value for our CEO as a percentage of base salary on the date of grant. This recommendation is presented to the Board of Trustees for approval. The Compensation Committee also approves long-term incentive target grant values for each of the other NEOs as a percentage of base salary on the date of grant. For the 2011 — 2013 Long-Term Incentive Program, at target, each grant generally consisted of 75% performance shares and 25% RSUs, subject to adjustment by the Compensation Committee (except the Compensation Committee acts jointly with the Corporate Governance Committee in recommending to the Board of Trustees adjustments to our CEO’s targets), reflecting the Committee’s desire to balance the roles of total shareholder return and our corporate financial performance in our compensation programs.

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For the 2011 — 2013 program, the Compensation Committee acting jointly with the Corporate Governance Committee recommended to the Board of Trustees a long-term incentive compensation target for our CEO at 300% of base salary, which the Board approved. The Compensation Committee established long-term incentive compensation targets at 100% to 150% of base salary for the remaining NEOs.

Restricted Share Units (RSUs)

Each RSU granted under the long-term incentive program entitles the holder to receive one Northeast Utilities common share at the time of vesting. All RSUs granted under the 2011 — 2013 program will vest in equal annual installments over three years. RSU holders are eligible to receive reinvested dividend units on outstanding RSUs held by them to the same extent that dividends are declared and paid on our common shares. Reinvested dividend units are accounted for as additional RSUs that accrue and are distributed with the common shares issued upon vesting and distribution of the underlying RSUs. Common shares, including any additional common shares in respect of reinvested dividend units, are not issued for any RSUs that do not vest.

General

Annually, the Compensation Committee determines RSU grants for each officer participating in the long-term incentive program. Initially, the target RSU grants are equal to 25% of the long-term incentive compensation target for each officer. RSU grants are based on a percentage of base salary and measured in dollars. The percentage used for each officer is based on the officer’s position in the Company and ranges from 5% to 75% of salary. The Committee reserves the right to increase or decrease the RSU grant from target for each officer under special circumstances. The Compensation Committee acting jointly with the Corporate Governance Committee recommends to the Board of Trustees the final RSU grant for our CEO. Based on input from our CEO, the Compensation Committee determines the final RSU grants for each of the other officers, including the other NEOs.

All RSUs are granted on the date of the Committee meeting at which they are approved. RSU grants are subsequently converted from dollars into common share equivalents by dividing the value of each grant by the average closing price for our common shares during the last ten trading days in January in the year of the grant.

RSU Grants under the 2011 — 2013 Program

Under the 2011 — 2013 program, the target RSU grant totaled approximately $2,504,978 million for all 33 officers participating in the long-term incentive program. The Committee did not adjust any officer’s RSU grant from target for the 2011 — 2013 program. Accordingly, the final total RSU grant for officers, including our CEO, was unchanged from target. Dividing the final total RSU grant by $32.72, the average closing price for our common shares during the last ten trading days in January 2011, resulted in an aggregate of 76,558 RSUs. The following RSU grants at 100% of target were approved, reflected in RSUs: Mr. Shivery: 24,526; Mr. McHale: 6,197; Mr. Olivier: 6,524; Mr. Butler: 4,814; and Mr. Robb: 3,148.

Performance Units

General

Performance units are a performance-based component of our long-term incentive program. A new three-year program commences every year. Performance unit grants are equal to 75% of total individual long-term incentive grants at target. The performance-based component of our long-term incentive programs has continued to evolve over the three prior years by shifting a portion of performance cash in earlier programs to performance shares in more recent programs to further strengthen the alignment of the performance elements with our shareholders.

Long-Term Incentive Program	Percentage  of Performance Cash			Percentage  of Performance Shares
2008 — 2010		100	%		0	%
2009 — 2011		67	%		33	%
2010 — 2012		50	%		50	%
2011 — 2013		0	%		100	%

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The Committee approved the 2011 — 2013 program in early 2011. The performance unit grant in the 2011 — 2013 program consisted solely of a performance share grant. Under all of our long-term programs, both performance cash grants and performance share grants are measured in dollars. Performance share grants are subsequently converted from dollars into common share equivalents by dividing the value of each grant by the average closing price for our common shares during the last ten trading days in January in the year of the grant. During the three-year performance program period, the dividends that would have been paid with respect to the performance shares to holders of performance share grants are accounted for as additional common shares that accrue and are distributed with the common shares, if any, at the end of the program.

Awards under a program are earned to the extent to which we achieve goals in the four metrics described below during the three years of the program, except as reduced in the discretion of the Compensation Committee. The Compensation Committee determines the actual awards, if any, only after the end of the final year in the respective program. The selection of these four metrics reflects the Compensation Committee’s belief that these areas are critical measurements of corporate success.

• Cumulative Adjusted Net Income, which is consolidated Northeast Utilities net income adjusted by the Compensation Committee to exclude the effects of certain nonrecurring income and expense items or events (which we defined as ANI under the annual incentive program) over the three years in a program (20%).

• Average adjusted ROE, which is the average of the annual return on equity for the three years in a program. The Committee adjusts average ROE on the same basis as cumulative adjusted net income (20%).

• Average credit rating of Northeast Utilities (excluding the regulated utilities), which is the time-weighted average daily credit rating by the rating agencies Standard & Poor’s, Moody’s, and Fitch. The metric is calculated by assigning numerical values, or “points,” to credit ratings (A or A2: 5; A- or A3: 4; BBB+ or Baa1: 3; BBB or Baa2: 2; and BBB- or Baa3: 1) so that a large point value represents a high credit rating. In addition to average credit rating objectives, the ratings of Northeast Utilities by S&P and Moody’s must remain above investment grade (20%).

• Relative total shareholder return of Northeast Utilities as compared to the return of the utility companies listed in the performance peer group identified for each long-term incentive program (40%).

Each metric was weighted equally in the 2009 — 2011 program. In the 2010 — 2012 program, the weighting of the total shareholder return metric was increased to 40% and the remaining three metrics were reduced to 20% each, to strengthen the alignment between executives and shareholders. The Committee measures performance against the cumulative adjusted net income, average adjusted ROE, and average credit rating, because these metrics are directly related to our multi-year business plan in effect at the beginning of the three-year program. The Committee also measures performance against relative total shareholder return to emphasize to the plan participants the importance of achieving total shareholder returns that are comparable to the returns for companies listed in the performance peer group. Before any amount is payable with respect to a metric, we must achieve a minimum level of performance under that metric. If we achieve the minimum level of performance for any goal, then the resulting payout will equal 50% of the target for that goal. If we achieve the maximum level of performance for any goal, then the resulting payout will equal 150% of target for that goal. The Committee fixed the minimum opportunity at 50% of target and the maximum opportunity at 150% of target because the Committee believes this range is consistent with the ranges used by companies listed in the performance peer group.

Upon closing of the proposed merger with NSTAR, the extent of satisfaction of the performance goals applicable to performance units for performance periods not yet completed in the 2010 — 2012 program generally will be measured based on performance up to the closing of the merger and payment generally will be made on a pro-rata basis (based on the portion of the applicable performance period that had been completed upon closing of the merger) following the end of the original performance period conditioned upon continued

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employment through such date. Performance units outstanding immediately before the closing of the merger that are attributable to the portion of the applicable performance periods extending beyond the closing of the merger will be forfeited. However, if an executive officer experiences a qualifying termination of employment (a termination of employment before age 65 by the Company without “cause” or by the executive officer for “good reason”) before completion of the original performance period, the awards will be vested at target performance levels and paid out without pro-ration upon such termination. Subject to the closing of the merger, the Committee intends to grant to each executive officer whose awards are paid on a pro-rated basis a “make-whole” award of RSUs with a value equal to the value of the executive officer’s Performance Units outstanding at target immediately before the closing of the merger that are attributable to the portion of the applicable performance periods extending beyond the closing of the merger.

Upon the closing of the pending merger with NSTAR, all performance shares outstanding under the 2011 — 2013 program will be converted to RSUs assuming a target level of performance. These RSUs will vest according to the schedule that applies to the RSU component already granted as part of the 2011 — 2013 program.

Set forth below are descriptions of each of the three long-term performance programs that were in effect during 2011. The peer groups used by the Committee for performance comparisons under each program are listed in footnote 1 to the table that accompanies each description. The performance peer groups represent companies with investment profiles, including growth potential, business models and areas of focus substantially similar to ours. The Committee compared our total shareholder return to the total shareholder returns of the companies in the performance peer group. Beginning with the 2009 — 2011 Long-Term Incentive Program, to simplify the peer group structure, the Committee evaluates the total shareholder return metric using the same customized group of peer utilities described above under “Market Analysis.”

2009 — 2011 Performance Units

The Compensation Committee approved the 2009 — 2011 performance unit grants in early 2009, consisting of two-thirds performance cash and one-third performance shares. Upon completion of our fiscal year ended 2011, the Committee determined that we achieved goals under each of the four metrics during the three-year program and, accordingly, that awards under the program were payable at an overall level of 100% of target.

For the 2009 — 2011 program, cumulative adjusted net income and average adjusted ROE excluded the effects of the following nonrecurring expense item:

Excluded Categories	Specific  2011 Adjustments ($ in millions)
Changes to net income as the result of accounting or tax law changes		(11.3	)
Net Adjustments:	$	(11.3	)

The table set forth below describes the goals under the 2009 — 2011 program and our actual results during that period:

2009 — 2011 Program Goals
Goal (1)	Minimum			Target			Maximum			Actual Results
Cumulative Adjusted Net Income ($ in millions)	$	899.3		$	999.2		$	1,099.1		$	1,137.7
Average Adjusted ROE		8.4	%		9.3	%		10.1	%		10.3	%
Average Credit Rating Points		1.2			1.7			2.2			1.7
Relative Total Shareholder Return (percentile) (2)		40th			60th			80th			32nd

(1) Goals were evenly weighted in the 2009 — 2011 program.

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(2) The performance peer group for the 2009 — 2011 program included Northeast Utilities and the following companies: Allegheny Energy, Inc., Alliant Energy Corporation, Ameren Corporation, CenterPoint Energy, Inc., CMS Energy Corporation, Consolidated Edison, Inc., DTE Energy Company, Great Plains Energy Incorporated, Integrys Energy Group Inc., NiSource, Inc., NSTAR, NV Energy, Inc., OGE Energy Corp., Pepco Holdings, Inc., Pinnacle West Capital Corporation, Progress Energy Inc., SCANA Corporation, TECO Energy, Inc., Wisconsin Energy Corporation and Xcel Energy Inc.

Based on our financial performance during the three-year performance period, the total payout under the 2009 — 2011 Long-Term Incentive Program equaled 100% of target. As a result, the Committee approved the following performance cash awards: Mr. Shivery: $1,552,500; Mr. McHale: $393,750; Mr. Olivier: $412,500; Mr. Butler: $305,241; and Mr. Robb: $200,000. In addition, the Committee approved the following performance share awards: Mr. Shivery: 32,702 shares; Mr. McHale: 8,294 shares; Mr. Olivier: 8,689 shares; Mr. Butler: 6,430 shares; and Mr. Robb: 4,213 shares. These awards were determined pursuant to formulas set forth in the 2009 — 2011 Long-Term Incentive Program and were not subject to the discretion of the Compensation Committee.

2010 — 2012 Performance Units

The Committee approved the 2010 — 2012 performance unit goals in early 2010. No awards have been paid under this program, and the Committee will not determine whether any awards are payable until the earlier of the end of our 2012 fiscal year, which is the final year in the three-year program, or upon the closing of the pending merger with NSTAR, as described above.

As described above, under the 2010 — 2012 program, one-half of each performance unit grant consists of a performance cash grant and the remaining one-half of each performance unit grant consists of a performance share grant. The 2010 — 2012 program also includes goals in four metrics: cumulative adjusted net income, average adjusted ROE, average credit rating, and relative total shareholder return, as described below. For the 2010 — 2012 program, cumulative adjusted net income and average adjusted ROE exclude the positive and negative effects of the following nonrecurring income and expense items or events: accounting or tax law changes; unusual Internal Revenue Service or regulatory issues; unexpected changes in costs related to nuclear decommissioning; unexpected changes in costs related to environmental remediation of HWP Company; divestiture or discontinuance of a segment or component of our business; the acquisition of shares or assets of another entity comprising an additional segment or component of our business; and impairments on goodwill acquired before 2003 (more than seven years prior to the beginning of this program cycle).

The table set forth below describes the goals under the 2010 — 2012 program:

2010 — 2012 Program Goals
Goal (1)	Minimum			Target			Maximum
Cumulative Adjusted Net Income ($ in millions)	$	1,051.6		$	1,168.4		$	1,285.2
Average Adjusted ROE		9.0	%		9.9	%		10.7	%
Average Credit Rating Points		1.2			1.7			2.2
Relative Total Shareholder Return (percentile) (2)		40th			60th			80th

(1) Relative total shareholder return accounted for 40% of the performance units granted in the 2010 — 2012 program while the cumulative adjusted net income, average adjusted ROE, and average credit rating metrics each accounted for 20% of the performance units granted.

(2) The performance peer group for the 2010 — 2012 program includes Northeast Utilities and the following companies: Alliant Energy Corporation, Ameren Corporation, CenterPoint Energy, Inc., CMS Energy Corporation, Consolidated Edison, Inc., DTE Energy Company, Great Plains Energy Incorporated, Integrys Energy Group Inc., NiSource, Inc., NSTAR, NV Energy, Inc., OGE Energy Corp., Pepco Holdings, Inc., Pinnacle West Capital Corporation, Progress Energy Inc., SCANA Corporation, TECO Energy, Inc., Wisconsin Energy Corporation and Xcel Energy Inc.

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2011 — 2013 Performance Shares

The Committee approved the 2011 — 2013 performance share goals in early 2013. No awards have been paid under this program, and the Committee will not determine whether any awards are payable until the end of our 2013 fiscal year, which is the final year in the three-year program.

As described above, under the 2011 — 2013 program, each performance grant consists solely of a performance share grant. The 2011 — 2013 program also includes goals in four metrics: cumulative adjusted net income, average adjusted ROE, average credit rating, and relative total shareholder return, as described below. For the 2011 — 2013 program, cumulative adjusted net income and average adjusted ROE exclude the positive and negative effects of the following nonrecurring income and expense items or events: accounting or tax law changes; unusual Internal Revenue Service or regulatory issues; unexpected changes in costs related to nuclear decommissioning; unexpected changes in costs related to environmental remediation of HWP Company; divestiture or discontinuance of a segment or component of our business; the acquisition of shares or assets of another entity comprising an additional segment or component of our business; and impairments on goodwill acquired before 2003 (more than eight years prior to the beginning of this program cycle).

The table set forth below describes the goals under the 2011 — 2013 program:

2011 — 2013 Program Goals
Goal (1)	Minimum			Target			Maximum
Cumulative Adjusted Net Income ($ in millions)	$	1,187.5		$	1,319.4		$	1,451.3
Average Adjusted ROE		9.5	%		10.4	%		11.3	%
Average Credit Rating Points		1.2			1.7			2.2
Relative Total Shareholder Return (percentile) (2)		40th			60th			80th

(1) Relative total shareholder return accounted for 40% of the performance units granted in the 2011 — 2013 program while the cumulative adjusted net income, average adjusted ROE, and average credit rating metrics each accounted for 20% of the performance shares granted.

(2) The performance peer group for the 2011 — 2013 program includes Northeast Utilities and the following companies: Alliant Energy Corporation, Ameren Corporation, CenterPoint Energy, Inc., CMS Energy Corporation, DTE Energy Company, Great Plains Energy Incorporated, Integrys Energy Group Inc., NiSource, Inc., NSTAR, NV Energy, Inc., OGE Energy Corp., Pepco Holdings, Inc., Pinnacle West Capital Corporation, Progress Energy Inc., SCANA Corporation, TECO Energy, Inc., Wisconsin Energy Corporation and Xcel Energy Inc.

SPECIAL EQUITY GRANT

On February 8, 2011, the Board of Trustees approved a special grant of 76,406 RSUs to Mr. Shivery to recognize the critical role he has had and will play in the successful leadership of the Company through the close of the proposed merger with NSTAR and as nonexecutive Chairman of the Board during the post-merger integration period. The RSUs will vest eighteen months after the closing of the merger with NSTAR, coinciding with Mr. Shivery’s commitment to remain as nonexecutive Chairman of the Board through that date. If Mr. Shivery dies or becomes disabled prior to the vesting date, then the RSUs will vest as of the date of death or disability. If Mr. Shivery does not serve on the Board through eighteen months after the merger closes, or the merger does not close, then the RSUs will be forfeited.

2012 CHANGES

2012 Incentive Programs

In early 2012, the Compensation Committee approved the 2012 Annual Incentive Program and the 2012 — 2014 Long-Term Incentive Program. At the time that the Committee established the performance goals for 2012, the Committee also considered and agreed upon exclusions from ANI consisting of certain nonrecurring income

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and expense items or events that were either beyond the control of management generally or related to a decision by the Committee not to penalize executive officers for making correct strategic business decisions. For 2012, the Committee acknowledged that increased amounts will be invested to further strengthen the system’s emergency preparedness and abilities to respond to storms. The Committee also acknowledged that enhanced emergency preparedness and system hardening programs were being evaluated as a result of the 2011 storms. Accordingly, the Committee agreed to consider excluding from ANI, in its discretion, expenses resulting from the implementation of emergency preparedness initiatives and system hardening programs. The Committee determined to encourage management to implement these initiatives and programs, if appropriate, which the Committee believes will benefit customers by enhancing the reliability and storm resistance of the electric system. Similar to the 2011 — 2013 Long-Term Incentive Program, upon the closing of the pending merger with NSTAR, all outstanding 2012 — 2014 performance shares will be converted to RSUs assuming a target level of performance. These RSUs will vest according to the schedule that applies to the RSU component already granted as part of the 2012 — 2014 Long-Term Incentive Program.

CLAWBACKS

If our earnings were to be restated as a result of noncompliance with accounting rules caused by fraud or misconduct, the Sarbanes-Oxley Act of 2002 would require our CEO and our Chief Financial Officer to reimburse us for certain incentive compensation received by each of them. To the extent that reimbursement were not required under Sarbanes-Oxley, our Incentive Plan would require any employee whose misconduct or fraud caused such restatement, as determined by the Board of Trustees, to reimburse us for any incentive compensation received by him or her. To date, there have been no restatements to which either the Sarbanes-Oxley clawback provisions or the Incentive Plan clawback provisions would apply.

SHARE OWNERSHIP GUIDELINES

Effective in 2006, the Compensation Committee approved share ownership guidelines to emphasize the importance of share ownership by certain of our executive officers. The Committee most recently reviewed the guidelines for these executive officers in 2010 and determined that they remain reasonable and require no modification. The guidelines call for the CEO to own 200,000 common shares, which is currently valued at approximately five- to six-times base salary, and the other executive officers to own a minimum number of common shares valued at approximately two- to three-times base salary.

Executive Officer	Ownership Guidelines (Number of Shares)	Approximate Salary Multiple
CEO	200,000	5-6
EVPs / SVPs	30,000 – 45,000	2-3
VPs	3,000 – 17,500	1-2

At the time the share ownership guidelines were implemented, the Committee required our executive officers to attain these ownership levels within five years. The Committee requires all newly-elected executive officers to attain the ownership levels within five to seven years. All of our executive officers, including our NEOs, have satisfied the share ownership guidelines, or are expected to satisfy them within the applicable timeframe. Common shares, whether held of record, in street name, or in individual 401(k) accounts, and RSUs satisfy the guidelines. Unexercised stock options and unvested performance shares do not count toward the ownership guidelines.

SUPPLEMENTAL BENEFITS

We provide a variety of basic and supplemental benefits designed to assist us in attracting and retaining executive officers critical to our success by reflecting competitive practices. The Compensation Committee endeavors to adhere to a high level of propriety in managing executive benefits and perquisites. We do not

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provide permanent lodging or personal entertainment for any executive officer or employee, and our executive officers are eligible to participate in substantially the same health care and benefit programs available to our employees.

RETIREMENT BENEFITS

We provide retirement income benefits for employees, including executive officers, who commenced employment before 2006 under the Northeast Utilities Service Company Retirement Plan (Retirement Plan) and, for officers, under the Supplemental Executive Retirement Plan for Officers of Northeast Utilities System Companies (Supplemental Plan). Each plan is a defined benefit pension plan, which determines retirement benefits based on years of service, age at retirement, and “plan compensation.” Plan compensation for the Retirement Plan, which is a qualified plan under the Internal Revenue Code, includes primarily base pay and nonofficer annual incentives up to the Internal Revenue Code limits for qualified plans. Beginning in 2006, newly-hired nonunion employees, including Mr. Robb and other executive officers, participate in an enhanced defined contribution retirement program in the Northeast Utilities Service Company 401k Plan (401k Plan), called the K-Vantage benefit, instead of participating in the Retirement Plan.

For NEOs who participate in the Retirement Plan, the Supplemental Plan adds to plan compensation: base pay over the Internal Revenue Code limits; deferred base salary; annual executive incentive program awards; and, for certain participants, long-term incentive program awards, as explained in the narrative accompanying the Pension Benefits Table.

The Supplemental Plan consists of two parts. The first part, called the make-whole benefit, compensates for benefits lost due to Internal Revenue Code limitations on benefits provided under the Retirement Plan. The second part, called the target benefit, is available to all NEOs except Mr. Olivier and Mr. Robb. The target benefit supplements the Retirement Plan and make-whole benefit under the Supplemental Plan so that, upon attaining at least 25 years of service, total retirement benefits from these plans will equal a target percentage of the final average compensation. To receive the target benefit, a participant must remain employed by us or our subsidiaries at least for five years and until age 60, unless the Board of Trustees establishes a lower age.

The value of the target benefit was reduced in 2005 to reflect changes in competitive practices, which indicated general reductions in the prevalence of defined benefit plans and the value of special retirement benefits to senior executives. Individuals who began serving as officers before February 2005 are eligible to receive a target benefit with the target percentage fixed at 60%. Individuals who began serving as officers from and after February 2005 are eligible to receive a target benefit with the target percentage fixed at 50%. As a result, Messrs. Shivery and Butler have target benefits at 60% while Mr. McHale has a target benefit at 50%.

Mr. Shivery’s employment agreement provides for a special total retirement benefit determined using the Supplemental Plan target benefit formula plus three additional years of service. Upon retirement, Mr. Shivery will be eligible to receive retirement health benefits. In addition, the Named Executive Officers are eligible to receive certain health and welfare benefits upon termination of employment following a change of control or, for Messrs. Shivery, Olivier, McHale and Butler, an involuntary termination of employment. To the extent such benefits may not be provided through our tax qualified plans, the executive is entitled to participate in a non-qualified health plan that will be treated as taxable compensation to the executive officer to the extent of Company contributions and will be provided with a tax gross-up so that the value to the executive is equivalent to a tax qualified plan benefit. See the Pension Benefits Table and the accompanying narrative for more details of these arrangements.

We entered into an employment agreement with Mr. Olivier that includes retirement benefits similar to the benefits provided by his previous employer. Accordingly, Mr. Olivier is entitled to receive separate retirement benefits in lieu of the Supplemental Plan benefits described above. Pursuant to his agreement, Mr. Olivier will receive a pension based on a prescribed formula if he meets certain eligibility requirements. See the Pension Benefits Table and the accompanying narrative for more details of this arrangement.

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401K PLAN

We provide an opportunity for employees to save money for retirement on a tax-favored basis through the 401k Plan. The 401k Plan is a defined contribution qualified plan under the Internal Revenue Code and contains a cash or deferred arrangement under Section 401(k) of the Internal Revenue Code. Participants with at least six months of service receive employer matching contributions, not to exceed 3% of base compensation, one-third of which are in cash available for investment in various fund alternatives and two-thirds of which are in the form of common shares (ESOP shares).

The K-Vantage benefit provides for employer contributions to the 401k Plan in amounts between 2.5% and 6.5% of plan compensation based on an eligible employee’s age and years of service. These contributions are in addition to employer matching contributions. Mr. Robb and other executive officers hired beginning in 2006 also participate in a companion nonqualified K-Vantage benefit in the Nonqualified Deferred Compensation Plan (Deferral Plan) that provides defined contribution benefits above Internal Revenue Code limits on qualified plans.

MED-VANTAGE PLAN

We automatically enroll K-Vantage employees who have attained at least age 40 in the Med-Vantage Plan to help pay for medical expenses, including healthcare premiums on a tax-favored basis upon the employee’s termination of employment. Eligible full-time employees receive employer contributions of $1,000 per year.

NONQUALIFIED DEFERRED COMPENSATION PLAN

Our executive officers participate in the Deferral Plan to provide additional retirement benefits not available in our 401k Plan because of Internal Revenue Code limits on qualified plans. Under the Deferral Plan, executive officers are entitled to defer up to 100% of base salary and annual incentive awards. We match officer deferrals in an amount equal to 3% of the amount of base salary above Internal Revenue Code limits on qualified plans. The matching contribution is deemed to be invested in common shares and vests at the end of the third year after the calendar year in which the matching contribution was earned, or at retirement, whichever occurs first. Participants are entitled to select deemed investments for all deferred amounts from the same investments available in the 401k Plan, except for investments in our common shares. We also credit the Deferral Plan in amounts equal to the K-Vantage benefit that would have been provided under the 401k Plan but for Internal Revenue Code limits on qualified plans. This nonqualified plan is unfunded. Please see the Nonqualified Deferred Compensation Table and the accompanying notes for additional plan details.

PERQUISITES

It is our philosophy that perquisites should be provided to executive officers only as needed for business reasons, and not simply in reaction to prevalent market practices.

Senior executive officers, including the NEOs, are eligible to receive reimbursement for financial planning and tax preparation services. This benefit is intended to help ensure that executive officers seek competent tax advice, properly prepare complex tax returns, and leverage the value of our compensation programs. Reimbursement is limited to $4,000 every two years for financial planning services and $1,500 per year for tax preparation services.

All executive officers receive a special annual physical examination benefit to help ensure serious health issues are detected early. The benefit is limited to the reimbursement of up to $800 for fees incurred beyond those covered by our medical plan.

When hiring a new executive officer or transferring an executive officer to a new location, we sometimes reimburse executive officers for reasonable temporary living and relocation expenses, or provide a lump sum payment in lieu of specific reimbursement. These expenses are grossed-up for income taxes attributable to such reimbursements so that relocation or transfer is cost neutral to the executive officer.

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When required for a valid business purpose, an executive officer may be accompanied by his or her spouse, in which case we will reimburse the executive officer for all spousal travel expenses.

We do not pay gross-ups for taxes on any perquisites other than for taxes on reimbursement of relocation expenses for newly-hired or transferred executives.

CONTRACTUAL AGREEMENTS

We have entered into employment and other agreements with certain executive officers, including Messrs. Shivery, McHale, Olivier, Butler and Robb. The agreements specify all or part of the following: compensation and benefits during the employment term, benefits payable upon involuntary termination of employment, and benefits payable upon termination of employment following a change of control. These termination and change of control benefits were customary at the time the agreements were signed and were necessary to attract and retain competent and capable executive talent. We continue to believe that these benefits help to ensure our executive officers’ dedication and objectivity at a time when they might otherwise be concerned about their future employment.

The agreements with Messrs. McHale, Butler and Robb provide for enhanced cash severance benefits in the event of a “change of control” and subsequent termination of employment without “cause” (as defined in the employment agreement, generally involving a felony conviction; acts of fraud, embezzlement, or theft in the course of employment; intentional, wrongful damage to our property; gross misconduct or gross negligence in the course of employment; or a material breach of obligations under the agreement) or upon termination of employment by the executive for “good reason” (as defined in the employment agreement, generally meaning an assignment to duties inconsistent with his position, a failure by the employer to satisfy material terms of the agreement or the transfer of the executive to an office location more than 50 miles from his principal place of business immediately prior to a change of control). The Compensation Committee believes that termination for good reason is conceptually the same as termination “without cause” and, in the absence of this provision, potential acquirers would have an incentive to constructively terminate executives to avoid paying severance. The change of control provisions in Mr. Shivery’s employment agreement expired when Mr. Shivery reached age 65. Mr. Olivier’s employment agreement does not provide for severance payments in the event that his employment terminates following a change of control. Mr. Olivier participates instead in the Special Severance Program.

For Messrs. McHale and Butler, a “change of control” is defined in their employment agreements as a change in ownership or control effected through (i) the acquisition of 20% or more of the combined voting power of common shares or other voting securities, (ii) a change in the majority of the Board of Trustees over a 24-month period, unless approved by a majority of the incumbent Trustees, (iii) certain reorganizations, mergers or consolidations where substantially all of the persons who were the beneficial owners of the outstanding common shares immediately prior to such business combination do not beneficially own more than 50% of the voting power of the resulting business entity, and (iv) complete liquidation or dissolution of Northeast Utilities, or a sale or disposition of all or substantially all of the assets of Northeast Utilities other than to an entity with respect to which following completion of the transaction more than 50% of common shares or other voting securities is then owned by all or substantially all of the persons who were the beneficial owners of common shares and other voting securities immediately prior to such transaction. For Mr. Robb, a “change of control” is as defined in the shareholder-approved Northeast Utilities Incentive Plan.

Pursuant to the change of control provisions in the employment agreements, each NEO except for Messrs. Olivier and Robb will be reimbursed for the full amount of any excise taxes imposed on severance payments and any other payments under Section 4999 of the Internal Revenue Code. This “gross-up” is intended to preserve the aggregate amount of the severance payments by compensating the executive officers for any adverse tax consequences to which they may become subject under the Internal Revenue Code. We have not included gross-up provisions in any employment arrangements entered into with executive officers hired beginning with Mr. Robb. The severance payments for Messrs. Olivier and Robb may be reduced to avoid excise taxes.

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We describe and explain how the appropriate payment and benefit levels are determined under the various circumstances that trigger payments or provision of benefits in the tables and accompanying notes appearing in the section of this proxy statement captioned “Potential Payments Upon Termination or Change of Control.”

To help protect us after the termination of an executive officer’s employment, the employment agreements include non-competition and non-solicitation covenants pursuant to which the executive officers have agreed not to compete with us or solicit our employees for a period of two years (one year for Mr. Olivier pursuant to the Special Severance Program and one year for Mr. Robb pursuant to his agreement) after termination of employment.

In the event of a change of control, the long-term incentive programs, other than the 2011 — 2013 program, provide for the vesting and payment of performance units and RSUs, pro rata based on the number of days of employment during the allocable performance period, if the executive remains employed through the original three-year performance period. In addition, performance units and RSUs will vest and pay out at target, without proration, if the executive’s employment terminates involuntarily in conjunction with the change of control, unless the Committee determines otherwise. Under the 2011 — 2013 program, in the event of a change of control, all outstanding performance shares will be converted to RSUs assuming a target level of performance. These RSUs will vest according to the schedule that applies to the RSU component already granted as part of the 2011 — 2013 program.

Finally, in the event of a change of control, the Deferral Plan provides for the immediate vesting of any employer matches. These matches and any associated executive officer deferrals will be paid in a lump sum without respect to the executive’s original election.

As discussed under the caption entitled “Supplemental Benefits,” above, our employment agreements with Messrs. Shivery and Olivier also include additional retirement benefits payable upon certain terminations of employment.

With respect to the Company’s pending merger with NSTAR, Mr. Shivery is not entitled to severance benefits because he ceased being entitled to such benefits upon attaining age 65. Messrs. McHale and Butler are entitled to severance benefits upon a qualifying termination of employment without regard to whether the merger is completed because the merger does not constitute a change in control within the meaning of their employment agreements. Mr. Olivier will be entitled to benefits under the Special Severance Program in the event of a qualifying termination of employment within two years following the approval by the Company’s shareholders of the proposed merger. Pursuant to a supplemental agreement between the Company and Mr. Olivier, Mr. Olivier is also entitled to a special retirement payment upon a qualifying termination of employment within two years following the approval by the Company’s shareholders of the merger. Mr. Robb will be entitled to benefits under his employment agreement in the event of a qualifying termination of employment within two years following the approval by the Company’s shareholders of the merger.

TAX AND ACCOUNTING CONSIDERATIONS

Tax Considerations. All executive compensation for 2011 was fully deductible by us for federal income tax purposes, except for approximately $109,000 paid to Mr. Shivery, consisting primarily of RSU distributions.

Section 162(m) of the Internal Revenue Code limits the tax deduction for compensation paid to a Company’s CEO and certain other executives. We are entitled to deduct compensation payments above $1 million as compensation expense only to the extent that these payments are “performance based” in accordance with Section 162(m) of the Internal Revenue Code. Our annual incentive program and performance unit grants qualify as performance-based compensation under the Internal Revenue Code. As required by Section 162(m), the Compensation Committee reports to the Board of Trustees annually the extent to which various performance goals have been achieved. RSUs do not qualify as performance-based compensation.

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Currently, Mr. Shivery is the only NEO to exceed the Section 162(m) limit. To preserve an employee compensation tax deduction for us, Mr. Shivery agreed, for as long as it is beneficial to us, to defer the distribution to him of common shares in respect of all vested RSUs until the calendar year after he leaves the Company, at which time Section 162(m) will no longer apply to him. The non-deductible RSU distributions for Mr. Shivery in 2011 described above relate to RSUs granted before Mr. Shivery was elected as our CEO.

Section 409A of the Internal Revenue Code provides that amounts deferred under nonqualified deferred compensation plans are includable in an employee’s income when vested unless certain requirements are met. If these requirements are not met, employees are also subject to additional income tax and interest penalties. All of our supplemental retirement plans, executive employment agreements, severance arrangements, and other nonqualified deferred compensation plans were amended in 2008 to satisfy the requirements of Section 409A.

Section 280G of the Internal Revenue Code disallows a tax deduction for “excess parachute payments” in connection with the termination of employment related to a change of control (as defined in the Internal Revenue Code), and Section 4999 of the Internal Revenue Code imposes a 20% excise tax on any person who receives excess parachute payments. As discussed above, our NEOs are entitled to receive certain payments upon termination of their employment, including termination following a change of control. Under the terms of the agreements, all NEOs except Mr. Olivier and Mr. Robb are entitled to receive tax gross-ups for any payments that constitute an excess parachute payment. Accordingly, our tax deduction would be disallowed under Section 280G for all excess parachute payments as well as tax gross-ups. Not all of the payments to which NEOs are entitled are excess parachute payments. The amounts of the payments that constitute excess parachute payments are set forth in the tables found under the caption entitled “Potential Payments at Termination or Change of Control,” below.

In the event of a change of control in which we are not the surviving entity, RSUs granted to executive officers provide that the acquirer will assume or replace the grants, even if the executive remains employed after the change of control.

Accounting Considerations. RSUs and performance shares disclosed in the Grants of Plan-Based Awards Table are accounted for based on their grant date fair value, as determined under FASB ASC Topic 718, which is recognized over the service period, or the three-year vesting period applicable to the grant. Assumptions used in the calculation of this amount appear under the caption entitled “Management’s Discussion and Analysis and Results of Operations” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2011. Forfeitures are estimated, and the compensation cost of awards will be reversed if the employee does not remain employed by us throughout the three-year vesting period. Performance unit grants are accounted for on a variable basis based on the most likely payment outcome.

COMPENSATION COMMITTEE REPORT

The Compensation Committee of the Northeast Utilities Board of Trustees has reviewed and discussed the Compensation Discussion and Analysis required by Item 402(b) of Regulation S-K with Northeast Utilities management. Based on this review and discussion, the Compensation Committee has recommended to the Board of Trustees that the Compensation Discussion and Analysis be included in this proxy statement and our Annual Report on Form 10-K.

The Compensation Committee

John S. Clarkeson, Chair

Sanford Cloud, Jr.

Elizabeth T. Kennan

Kenneth R. Leibler

Dennis R. Wraase

February 22, 2012

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SUMMARY COMPENSATION TABLE

The table below summarizes the total compensation paid or earned by our Chairman, President and Chief Executive Officer (CEO), Executive Vice President and Chief Financial Officer (CFO), and the three other most highly compensated executive officers other than the CEO and CFO who were serving as executive officers at the end of 2011 (collectively, the Named Executive Officers or NEOs). As explained in the footnotes below, the amounts reflect the economic benefit to each Named Executive Officer of the compensation item paid or accrued on his behalf for the fiscal year ended December 31, 2011. The compensation shown for each Named Executive Officer was for all services in all capacities to Northeast Utilities and its subsidiaries. All salaries, annual incentive amounts and long-term incentive amounts shown for each Named Executive Officer were paid for all services rendered to Northeast Utilities and its subsidiaries in all capacities.

Name and Principal Position	Year		Salary ($) (1)		Bonus ($) (2)		Stock Awards ($) (3)		Option Awards ($) (4)		Non-Equity Incentive Plan Compensation ($) (5)		Change in Pension Value and Non- Qualified Deferred Compensation Earnings ($) (6)		All Other Compen- sation ($) (7)		Total ($)
Charles W. Shivery (8)		2011		1,063,270		—		5,780,091		—	Annual:	—		1,158,298		31,898		9,586,057
Chairman of the Board, President and Chief Executive Officer											Long Term:	1,552,500
											Total:	1,552,500
		2010		1,035,000		—		1,905,964		—	Annual:	1,987,200		1,525,310		31,050		8,254,374
											Long Term:	1,769,850
											Total:	3,757,050
		2009		1,035,000		—		1,574,915		—	Annual:	1,645,650		1,812,023		31,050		7,773,638
											Long Term:	1,635,000
											Total:	3,280,650
David R. McHale		2011		537,721		—		810,080		—	Annual:	—		798,025		16,132		2,555,708
Executive Vice President and Chief Financial Officer											Long Term:	393,750
											Total:	393,750
		2010		525,000		—		2,484,707		—	Annual:	608,517		934,059		15,750		4,995,533
											Long Term:	427,500
											Total:	1,036,017
		2009		524,520		—		399,436		—	Annual:	555,728		1,038,268		7,350		2,893,177
											Long Term:	367,875
											Total:	923,603
Leon J. Olivier		2011		565,548		—		852,791		—	Annual:	—		724,796		16,966		2,572,601
Executive Vice President and Chief Operating Officer											Long Term:	412,500
											Total:	412,500
		2010		550,000		—		2,007,381		—	Annual:	601,494		699,343		16,500		4,255,906
											Long Term:	381,188
											Total:	982,682
		2009		550,000		—		418,459		—	Annual:	558,415		219,565		16,500		2,086,533
											Long Term:	323,594
											Total:	882,009
Gregory B. Butler		2011		417,508		—		629,234		—	Annual:	—		553,436		7,350		1,912,769
Senior Vice President and General Counsel											Long Term:	305,241
											Total:	305,241
		2010		406,988		—		1,875,695		—	Annual:	458,320		472,066		7,350		3,568,394
											Long Term:	347,975
											Total:	806,295
		2009		406,988		—		309,666		—	Annual:	414,009		503,614		7,350		1,958,496
											Long Term:	316,870
											Total:	730,878
James B. Robb		2011		409,692		—		411,494		—	Annual:	—		—		42,041		1,063,227
Senior Vice President Enterprise Planning & Development NUSCO											Long Term:	200,000
											Total:	200,000
		2010		400,000		—		1,246,211		—	Annual:	339,000		—		45,243		2,258,454
											Long Term:	228,000
											Total:	567,000
		2009		400,000		—		202,896		—	Annual:	316,500		—		44,237		963,663
											Long Term:	—
											Total:	316,500

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(1) Includes amounts deferred in 2011 by the Named Executive Officers under the Deferral Plan, as follows: Mr. Shivery: $31,898; Mr. McHale: $8,604; Mr. Olivier: $113,110; and Mr. Robb: $8,194. For more information, see the Executive Contributions in the Last Fiscal Year column of the Non-Qualified Deferred Compensation Plans Table.

(2) No discretionary bonus awards were made to any of the Named Executive Officers in the fiscal years ended 2009, 2010 and 2011.

(3) Reflects the aggregate grant date fair value of restricted share units (RSUs) and performance shares granted in each fiscal year, calculated in accordance with FASB ASC Topic 718.

In 2009, 2010 and 2011, certain Named Executive Officers were granted RSUs that vest in equal annual installments over three years as long-term incentive compensation. We deferred the distribution of common shares upon vesting of RSUs granted to Mr. Shivery until 2013, the calendar year after the year in which his employment terminates. RSU holders are eligible to receive dividend equivalent units on outstanding RSUs held by them to the same extent that dividends are declared and paid on our common shares. Dividend equivalent units are accounted for as additional common shares that accrue and are distributed simultaneously with the common shares issued upon vesting of the underlying RSUs.

In 2011, the Named Executive Officers were granted performance shares as long-term compensation. These performance shares will vest on December 31, 2013, based on the extent to which four performance conditions are achieved. The grant date values for the performance shares, assuming achievement of the highest level of all four performance conditions, are as follows: Mr. Shivery: $3,569,554; Mr. McHale: $901,954; Mr. Olivier: $949,497; Mr. Butler: $700,560; and Mr. Robb: $458,157.

On February 8, 2011, the Board of Trustees approved a special grant of 76,406 RSUs to Mr. Shivery to recognize the critical role he has had and will play in the successful leadership of the Company through the close of the pending merger with NSTAR and as nonexecutive Chairman of the Board during the post-merger integration period. The RSUs will vest eighteen months after the closing of the merger with NSTAR, coinciding with Mr. Shivery’s commitment to remain as nonexecutive Chairman of the Board through that date. If Mr. Shivery dies or becomes disabled prior to the vesting date, then the RSUs will vest as of the date of death or disability. If Mr. Shivery does not serve on the Board through eighteen months after the merger closes, then the RSUs will be forfeited.

(4) We did not grant stock options to any of the Named Executive Officers in 2011. We have not granted any stock options since 2002.

(5) Includes payments to the Named Executive Officers under the 2011 Annual Incentive Program (Mr. Shivery: $0; Mr. McHale: $0; Mr. Olivier: $0; Mr. Butler: $0; and Mr. Robb: $0). Also includes performance cash payments under the 2009 – 2011 Long-Term Incentive Program (Mr. Shivery: $1,552,500; Mr. McHale: $393,750; Mr. Olivier: $412,500; Mr. Butler: $305,241; and Mr. Robb: $200,000). Performance goals under the 2011 Annual Incentive Program were communicated to each officer by the CEO or, in the case of the CEO, jointly by the Compensation Committee and Corporate Governance Committee, during the first 90 days of 2011. The Compensation Committee acting jointly with the Corporate Governance Committee determined the extent to which these goals were satisfied (based on input from the CEO, in the case of the other Named Executive Officers) in February 2012. Performance goals under the 2009 – 2011 Long-Term Incentive Program were communicated to each officer by the CEO or, in the case of the CEO, jointly by the Compensation Committee and Corporate Governance Committee, during the first 90 days of 2009. The Compensation Committee determined the extent to which the long-term goals were satisfied in February 2012.

(6) Includes the actuarial increase in the present value from December 31, 2010 to December 31, 2011 of the Named Executive Officer’s accumulated benefits under all of our defined benefit pension plans determined using interest rate and mortality rate assumptions consistent with those appearing under the caption entitled “Management’s Discussion and Analysis and Results of Operations” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2011. The Named Executive Officer may not be fully vested in such amounts. More information on this topic is set forth in the notes to the Pension Benefits table, appearing further below. Mr. Robb does not participate in our defined benefit pension plan. There were no above-market earnings on deferrals in 2011.

(7) Includes matching contributions of $7,350 allocated by us to the account of each of the Named Executive Officers under the 401k Plan; Med-Vantage employer contributions (Mr. Robb: $1,000); qualified K-Vantage employer contributions under the 401k Plan (Mr. Robb: $11,025); nonqualified K-Vantage employer contributions under the Deferral Plan (Mr. Robb: $22,666); and employer matching contributions under the Deferral Plan for the Named Executive Officers who deferred part of their salary in the fiscal year ended December 31, 2010 (Mr. Shivery: $24,548; Mr. McHale: $8,782; Mr. Olivier: $9,616; and Mr. Robb: $4,941). Mr. Butler did not participate in the Deferral Plan in 2011.

(8) Mr. Shivery’s 2011 total compensation includes the special grant of 76,406 RSUs valued at $2,574,118 as described in footnote 3 above. Excluding the value of this special grant, Mr. Shivery received total compensation of $7,111,123 for 2011.

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GRANTS OF PLAN-BASED AWARDS DURING 2011

The Grants of Plan-Based Awards Table provides information on the range of potential payouts under all incentive plan awards during the fiscal year ended December 31, 2011. The table also discloses the underlying stock awards and the grant date for equity-based awards. We have not granted any stock options since 2002. Accordingly, we did not grant stock options to any of the Named Executive Officers in 2011.

			Estimated Future Payouts Under Non-Equity Incentive Plan Awards						Estimated Future Payouts Under Equity Incentive Plan Awards (1)						All Other Stock  Awards: Number of Shares of Stock or Units (#) (2)		Grant Date Fair Value of Stock and Option Awards ($) (3)
Name	Grant Date		Threshold ($)		Target ($)		Maximum ($)		Threshold ($)		Target ($)		Maximum ($)
Charles W. Shivery
Annual Incentive (4)		2/8/2011		535,000		1,070,000		2,140,000		—		—		—		—		—
Long-Term Incentive (5)		2/8/2011		—		—		—		—		73,579		110,369		24,526		3,205,973
Special Equity Grant (6)		2/8/2011		—		—		—		—		—		—		76,406		2,574,118
David R. McHale
Annual Incentive (4)		2/8/2011		174,759		349,519		699,038		—		—		—		—		—
Long-Term Incentive (5)		2/8/2011		—		—		—		—		18,592		27,888		6,197		810,080
Leon J. Olivier
Annual Incentive (4)		2/8/2011		183,803		367,606		735,213		—		—		—		—		—
Long-Term Incentive (5)		2/8/2011		—		—		—		—		19,572		29,358		6,524		852,791
Gregory B. Butler
Annual Incentive (4)		2/8/2011		135,690		271,380		542,760		—		—		—		—		—
Long-Term Incentive (5)		2/8/2011		—		—		—		—		14,441		21,661		4,814		629,234
James B. Robb
Annual Incentive (4)		2/8/2011		102,423		204,846		409,692		—		—		—		—		—
Long-Term Incentive (5)		2/8/2011		—		—		—		—		9,444		14,166		3,148		411,494

(1) Reflects the number of performance shares granted to each of the Named Executive Officers on February 8, 2011 under the 2011 — 2013 Long-Term Incentive Program. Performance shares were granted with a three-year Performance Period that ends on December 31, 2013. At the end of the Performance Period, common shares will be awarded based on performance compared to goals, subject to reduction for applicable withholding taxes. Holders of performance shares are eligible to receive dividend equivalent units on outstanding performance shares held by them to the same extent that dividends are declared and paid on our common shares. Dividend equivalent units are accounted for as additional common shares that accrue and are distributed simultaneously with the common shares distributed in respect of the underlying performance shares. The Annual Incentive Program does not include an equity component.

(2) Reflects the number of RSUs granted to each of the Named Executive Officers on February 8, 2011 under the 2011 — 2013 Long-Term Incentive Program. RSUs vest in equal installments on February 25, 2012, 2013 and 2014. Except for Messrs. Shivery and Robb, we will distribute common shares in respect to vested RSUs on a one-for-one basis immediately upon vesting, after reduction for applicable withholding taxes. For Mr. Shivery, we will distribute common shares, after reduction for applicable withholding taxes, in respect of vested RSUs in three approximately equal annual installments beginning the later of (i) six months after he leaves the Company and (ii) January of the calendar year after he leaves the Company. For Mr. Robb, we will distribute common shares after reduction for applicable withholding taxes, in respect of vested RSUs beginning the earlier of (i) fifteen years beyond the vesting date or (ii) six months after he leaves the Company. Holders of RSUs are eligible to receive dividend equivalent units on outstanding RSUs held by them to the same extent that dividends are declared and paid on our common shares. Dividend equivalent units are accounted for as additional common shares that accrue and are distributed simultaneously with the common shares distributed in respect of the underlying RSUs. The Annual Incentive Program does not include an equity component.

Also includes the number of RSUs granted to certain Mr. Shivery on February 8, 2011 in connection with the merger with NSTAR. See note 3 to the Summary Compensation Table.

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(3) Reflects the grant-date fair value, determined in accordance with FASB ASC Topic 718, of: (i) RSUs and performance shares granted to the Named Executive Officers on February 8, 2011, under the 2011 — 2013 Long-Term Incentive Program; and (ii) RSUs granted to the Mr. Shivery on February 8, 2011 in connection with the merger with NSTAR. The Annual Incentive Program does not include an equity component.

(4) Amounts reflect the range of potential payouts, if any, under the 2011 Annual Incentive Program for each Named Executive Officer, as described in the Compensation Discussion and Analysis. The payment in 2012 for performance in 2011 is set forth in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table. The threshold payment under the Annual Incentive Program is 50% of target. However, based on Adjusted Net Income and individual performance, the actual payment under the Annual Incentive Program could be zero.

(5) Reflects the range of potential payouts, if any, pursuant to performance share awards under the 2011 — 2013 Long-Term Incentive Program, as described in the Compensation Discussion and Analysis. No performance share awards were made in 2011 under the 2011 — 2013 Long-Term Incentive Program.

(6) Reflects the number of RSUs granted to Mr. Shivery on February 8, 2011 in connection with the merger with NSTAR. See note 3 to the Summary Compensation Table.

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EQUITY GRANTS OUTSTANDING AT DECEMBER 31, 2011

The following table sets forth option, RSU and performance share grants outstanding at the end of our fiscal year ended December 31, 2011 for each of the Named Executive Officers. All outstanding options were fully vested as of December 31, 2011.

	Option Awards (1)						Stock Awards (2)
Name	Number of Securities Underlying Unexercised Options Exercisable (#)		Option Exercise Price ($)		Option Expiration Date		Number of Shares or Units of Stock that have not Vested (#) (3)		Market Value of Shares or Units of Stock that have not Vested ($) (4)		Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#) (5)		Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($) (6)
Charles W. Shivery		29,024	$	18.90		06/11/2012		137,804		4,970,590		148,508		5,536,683
David R. McHale		—		—		—		81,611		2,943,708		37,594		1,356,015
Leon J. Olivier		—		—		—		65,684		2,369,222		39,481		1,424,079
Gregory B. Butler		—		—		—		61,594		2,221,696		29,171		1,052,197
James B. Robb		—		—		—		40,925		1,476,164		19,097		688,828

(1) We have not granted stock options since 2002.

(2) Awards and market values of awards appearing in the table and the accompanying notes have been rounded to whole units.

(3) An additional 61,617 unvested RSUs will vest on February 25, 2012 (Mr. Shivery: 31,331; Mr. McHale: 7,938; Mr. Olivier: 8,327; Mr. Butler: 6,157; and Mr. Robb: 3,932). An additional 37,854 unvested RSUs will vest on February 25, 2013 (Mr. Shivery: 19,188; Mr. McHale: 4,859; Mr. Olivier: 5,101; Mr. Butler: 3,770; and Mr. Robb: 2,468). An additional 16,637 unvested RSUs will vest on February 25, 2014 (Mr. Shivery: 8,437; Mr. McHale: 2,132; Mr. Olivier: 2.244; Mr. Butler: 1,656; and Mr. Robb: 1,084).

In connection with the merger with NSTAR, on November 16, 2010, the Board of Trustees established a retention pool in an aggregate amount of $10 million to be allocated to key employees, including some or all executive officers, to help ensure their continued dedication to the Company both before and after completion of the merger. Awards were in the form of RSUs and generally vest subject to three years of continuous service following completion of the merger. Full payment will also be made if an eligible executive dies, becomes disabled, or is terminated by the Company without “cause” before the end of the retention period, in which case the retention payment will be reduced by the amount of any cash severance payable to the executive upon or during the year following termination. An additional 193,854 unvested RSUs granted pursuant to the retention pool will vest subject to three years of continuous service following completion of the merger with NSTAR (Mr. McHale: 64,618; Mr. Olivier: 48,463; Mr. Butler: 48,463; and Mr. Robb: 32,310).

(4) The market value of RSUs is determined by multiplying the number of RSUs by $36.07, the closing price per share of common shares on December 30, 2011, the last trading day of the year.

(5) Reflects the target payout level for 2011 and 2010 performance shares. Payouts for 2011 and 2010 performance shares will be based on actual performance. Performance shares are described in the CD&A and footnote (1) to the Grants of Plan-Based Awards table. Performance shares vest following a three-year performance period to the extent targets are achieved. Performance shares are also discussed in the CD&A under “Performance Units” above. A total of 133,891 unearned performance shares will vest on December 31, 2012 (Mr. Shivery: 72,579; Mr. McHale: 18,408; Mr. Olivier: 19,284; Mr. Butler: 14,269; and Mr. Robb: 9,351). An additional 149,706 unearned performance shares will vest on December 31, 2013 (Mr. Shivery: 75,929; Mr. McHale: 19,186; Mr. Olivier: 20,197; Mr. Butler: 14,902; and Mr. Robb: 9,746).

(6) The market value is determined by multiplying the number of performance shares in the adjacent column by $36.07, the closing price per share of common shares on December 30, 2011, the last trading day of the year.

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OPTIONS EXERCISED AND STOCK VESTED IN 2011

The following table reports amounts realized on equity compensation during the fiscal year ended December 31, 2011. None of the Named Executive Officers exercised options in 2011. The Stock Awards columns report the vesting of RSU grants to the Named Executive Officers in 2011.

	Option Awards				Stock Awards
Name	Number of Shares Acquired on Exercise (#)		Value Realized on Exercise ($) (1)		Number of Shares Acquired on Vesting (#) (2)		Value Realized on Vesting ($) (3)
Charles W. Shivery		—		—		49,119		1,612,086
David R. McHale		—		—		11,766		386,160
Leon J. Olivier		—		—		11,369		373,131
Gregory B. Butler		—		—		8,758		287,438
James B. Robb		—		—		5,961		195,640

(1) Represents the amounts realized upon option exercises, which is the difference between the option exercise price and the market price at the time of exercise.

(2) Includes RSUs granted to our Named Executive Officers under our long-term incentive programs, including dividend reinvestments, as follows:

	2008		2009		2010
Name	Program		Program		Program
Charles W. Shivery		26,224		12,143		10,752
David R. McHale		6,138		2,985		2,643
Leon J. Olivier		5,473		3,127		2,769
Gregory B. Butler		4,396		2,313		2,049
James B. Robb		3,012		1,564		1,385

In all cases, we reduce the distribution of common shares by that number of shares valued in an amount sufficient to satisfy tax withholding obligations, which amount we distribute in cash. Included in the value realized are values associated with deferred RSUs, which are also reported in the Registrant Contributions in Last Fiscal Year column of the Non-Qualified Deferred Compensation Table.

(3) Value realized on vesting for all amounts is based on $32.82 per share, the closing price of common shares on February 25, 2011. This value includes the value of vested RSUs for which the distribution of common shares is currently deferred.

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PENSION BENEFITS IN 2011

The Pension Benefits Table sets forth the estimated present value of accumulated retirement benefits that would be payable to each Named Executive Officer upon his retirement as of the first date upon which he is eligible to receive an unreduced pension benefit (see below). The table distinguishes the benefits among those available through the Retirement Plan, the Supplemental Plan and any additional benefits available under the respective officer’s employment agreement. The Supplemental Plan provides a make whole benefit that is based in part on compensation that is not permitted to be recognized under a tax-qualified plan and provides a target benefit if the eligible officer continues his or her employment until age 60. Benefits under the Supplemental Plan are also based on elements of compensation that are not included under the Retirement Plan. This includes compensation equal to: (i) deferred compensation; (ii) the value of awards under the Annual Incentive Program for officers; and (iii) long-term incentive awards only for Messrs. McHale and Butler (as to each of their respective make whole benefits), the values of which are frozen at the 2001 target levels.

The present value of accumulated benefits shown in the Pension Benefits Table was calculated as of December 31, 2011 assuming benefits would be paid in the form of a one-half spousal contingent annuitant option (the typical form of payment for the target benefit). For Mr. Olivier, who has a special retirement arrangement, we assumed that his special retirement benefit would be paid as a lump sum, and his Retirement Plan benefit would be paid in the form of a life annuity with a one-third spousal contingent annuitant option (the typical form of payment under the Retirement Plan). None of Mr. Olivier’s benefits will be provided under the Supplemental Plan. In addition, the present value of accrued benefits for any Named Executive Officer assumes that benefits commence at the earliest age at which the participant would be eligible to retire and receive unreduced benefits. Named Executive Officers are eligible to receive unreduced benefits upon the earlier of (a) attainment of age 65 or (b) attainment of at least age 55 when age plus service equals 85 or more years, except for Mr. Olivier. Mr. Olivier’s unreduced benefit is available at age 60 pursuant to his employment agreement. The target benefit is available for Messrs. Butler and McHale only after age 60. Accordingly, Mr. Shivery became eligible to receive unreduced benefits at age 65, Messrs. McHale and Olivier are eligible to receive unreduced benefits at age 60, and Mr. Butler is eligible to receive unreduced benefits at age 62. Mr. Robb does not participate in the Retirement Plan nor the Supplemental Plan.

The limitations applicable to the Retirement Plan under the Internal Revenue Code as of December 31, 2011 were used to determine the benefits under each plan. The accrued benefits reflect actual compensation (both salary and incentives) earned during 2011. Under the terms of the Supplemental Plan, annual incentives earned for services provided in a plan year are deemed to have been paid ratably over that plan year. For example, the March 2012 payment pursuant to the 2011 Annual Incentive Program was reflected in the 2011 plan compensation. We determined the present value of the benefit at retirement age by using the discount rate of 5.57% under Statement of Financial Accounting Standards No. 87 for the 2011 fiscal year end measurement (as of December 31, 2011). This present value assumes no pre-retirement mortality, turnover or disability. However, for the postretirement period beginning at the retirement age, we used the RP2000 Combined Healthy mortality table as published by the Society of Actuaries projected to 2012 with projection scale AA (same table used for financial reporting under FAS 87). Additional assumptions appear under the caption entitled “Management’s Discussion and Analysis and Results of Operations” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2011.

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Pension Benefits

Name	Plan Name	Number of Years Credited Service (#)		Present Value of Accumulated Benefit ($)		Payments During Last Fiscal Year ($)
Charles W. Shivery (1)	Retirement Plan		9.6		387,825		—
	Supplemental Plan		9.6		7,566,228		—
	Other Special Benefit		12.6		2,490,831		—
David R. McHale	Retirement Plan		30.3		918,365		—
	Supplemental Plan		30.3		3,541,056		—
Leon J. Olivier (2)	Retirement Plan		12.8		516,123		—
	Supplemental Plan		10.3		—		—
	Other Special Benefit		10.3		3,101,153		—
	Other Special Benefit		32.3		1,281,935		105,966
Gregory B. Butler	Retirement Plan		15.0		441,905		—
	Supplemental Plan		15.0		2,287,874		—
James B. Robb	Retirement Plan		—		—		—
	Supplemental Plan		—		—		—
	Supplemental Plan		10.1		648,809		—
	Other Special Benefit		31.1		1,419,229		—

(1) Mr. Shivery’s actual service with us totaled 9.6 years at December 31, 2011. However, Mr. Shivery’s employment agreement provides for a special retirement benefit consisting of an amount equal to the difference between: (i) the equivalent of fully-vested benefits under the Retirement Plan and the Supplemental Plan calculated by adding three years to his actual service and (ii) benefits otherwise payable from the Retirement Plan and the Supplemental Plan. The value of the additional three years of service on December 31, 2011 was approximately $2,490,831.

(2) Mr. Olivier was employed with Northeast Nuclear Energy Company, one of our subsidiaries, from October of 1998 through March of 2001. In connection with this employment, he received a special retirement benefit that provided credit for service with his previous employer, Boston Edison Company (BECO), when calculating the value of his defined benefit pension, offset by the pension benefit provided by BECO. The benefit, which commenced upon Mr. Olivier’s 55th birthday, provides an annuity of $105,966 per year in a form that provides no contingent annuitant benefit. The present value of future payments under this benefit was calculated using the actuarial assumptions currently used by the Retirement Plan. Mr. Olivier was rehired by us from Entergy in September 2001. Mr. Olivier’s current employment agreement provides for certain supplemental pension benefits in lieu of benefits under the Supplemental Plan, in order to provide a benefit similar to that provided by Entergy. Under this arrangement, Mr. Olivier became eligible during 2011 to receive a special benefit, subject to reduction for termination prior to age 65, consisting of three percent of final average compensation for each of his first 15 years of service since September 10, 2001, plus one percent of final average compensation for each of the second 15 years of service. Alternatively, if Mr. Olivier voluntarily terminates his employment with us, he is eligible to receive upon retirement a lump sum payment of $2,050,000 in lieu of benefits under the Supplemental Plan and the benefit described in the preceding sentence. These supplemental pension benefits will be offset by the value of any benefits he receives from the Retirement Plan. Amounts reported in the table assume the termination of his employment with our consent on December 31, 2011, and payment of the lump sum benefit of $3,617,276 offset by Retirement Plan benefits.

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NONQUALIFIED DEFERRED COMPENSATION IN 2011

Name	Executive Contributions in Last FY ($) (1)		Registrant Contributions in Last FY ($) (2)		Aggregate Earnings in Last FY ($)			Aggregate Withdrawals/ Distributions ($) (3)			Aggregate Balance at Last FYE ($) (4)
Charles W. Shivery		1,895,242		24,548		1,675,878			(109,106	)		14,311,086
David R. McHale		8,604		8,732		49,509			(132,570	)		279,759
Leon J. Olivier		113,110		9,616		(68,087	)		(199,810	)		1,757,016
Gregory B. Butler		—		—		59,117			(215,376	)		364,754
James B. Robb		46,602		27,607		77,882			—			322,792

(1) Includes deferrals by the Named Executive Officers under the 2011 Deferral Plan (Mr. Shivery: $31,898; Mr. McHale: $8,604; Mr. Olivier: $113,110; and Mr. Robb: $8,194). Named Executive Officers who participate in the Deferral Plan are provided with a variety of investment opportunities, which the individual can modify and reallocate at any time. Fund gains and losses are updated daily by our recordkeeper, Fidelity Investments. Contributions by the Named Executive Officer are vested at all times; however, the employer matching contribution vests after three years and will be forfeited if the executive’s employment terminates, other than for retirement, prior to vesting, but will become fully vested upon a change of control.

All other amounts relate to the value of common shares, the distribution of which was either automatically deferred upon vesting of underlying RSUs pursuant to the terms of the respective Long-Term Incentive Programs, or pursuant to the Named Executive Officer’s deferral election, calculated using $32.82 per share, the closing price of the common shares on February 25, 2011, the vesting date. For more information, see the footnotes to the Options Exercised and Stock Vested Table.

(2) Includes employer matching contributions made to the Deferral Plan as of December 31, 2011 and posted on January 31, 2012, as reported in the All Other Compensation column of the Summary Compensation Table (Mr. Shivery: $24,548; Mr. McHale: $8,782; Mr. Olivier: $9,616; and Mr. Robb: $4,941). The employer matching contribution is deemed to be invested in common shares but is paid in cash at the time of distribution. Also includes nonqualified K-Vantage employer contributions made to the Deferral Plan during fiscal year 2011 (Mr. Robb: $22,666).

(3) Includes distributions to Named Executive Officers under the Deferral Plan during fiscal year 2011 pursuant to their deferral elections (Mr. Olivier: $19,376); plus the value of previously vested deferred RSUs distributed in 2011, pursuant to the Named Executive Officer’s deferral election, valued at distribution at $32.82 per share, the closing price of our common shares on February 25, 2011.

(4) Includes the total market value of Deferral Plan balances at December 31, 2011, plus the value of vested RSUs for which the distribution of common shares is currently deferred, based on $36.07 per share, the closing price of our common shares on December 30, 2011, the last trading day of the year.

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POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE OF CONTROL

Generally, a “change of control” means a change in ownership or control effected through (i) the acquisition of 20% or more of the combined voting power of common shares or other voting securities, (ii) a change in the majority of the Board of Trustees over a 24-month period, unless approved by a majority of the incumbent Trustees, (iii) certain reorganizations, mergers or consolidations where substantially all of the persons who were the beneficial owners of the outstanding common shares immediately prior to such business combination do not beneficially own more than 50% (75% for Messrs. Olivier and Robb) of the voting power of the resulting business entity, and (iv) complete liquidation or dissolution of Northeast Utilities, or a sale or disposition of all or substantially all of the assets of Northeast Utilities other than to an entity with respect to which following completion of the transaction more than 50% (75% for Messrs. Olivier and Robb) of common shares or other voting securities is then owned by all or substantially all of the persons who were the beneficial owners of common shares and other voting securities immediately prior to such transaction.

In the event of a change of control, the NEOs are each entitled to receive compensation and benefits following either termination of employment without “cause” or upon termination of employment by the executive for “good reason” within 24 months following the change of control. The Compensation Committee believes that termination for good reason is conceptually the same as termination “without cause” and, in the absence of this provision, potential acquirers would have an incentive to constructively terminate executives to avoid paying severance. Termination for “cause” generally means termination due to a felony conviction; acts of fraud, embezzlement, or theft in the course of employment; intentional, wrongful damage to Company property; gross misconduct or gross negligence in the course of employment; or a material breach of obligations under the agreement. Termination for “good reason” generally is deemed to occur following an assignment to duties inconsistent with his position, a failure by the employer to satisfy material terms of the agreement, a reduction in the compensation or benefits of the executive officer (a material reduction in compensation or benefits for Messrs. Olivier and Robb), or the transfer of the executive to an office location more than 50 miles from his principal place of business immediately prior to a change of control.

With respect to the proposed merger with NSTAR, none of the Named Executive Officers will be entitled to receive any additional compensation and benefits in the absence of a termination of employment for cause or for good reason within two years (for Messrs. Olivier and Robb) after shareholder approval of the merger.

The discussion and tables below reflect the amount of compensation that would be payable to each of the Named Executive Officers in the event of: (i) termination of employment for cause; (ii) voluntary termination; (iii) involuntary not-for-cause termination (or voluntary termination for good reason); (iv) termination in the event of disability; (v) death; and (vi) termination following a change of control. The amounts shown assume that each termination was effective as of December 31, 2011, the last business day of the fiscal year as required under Securities and Exchange Commission reporting requirements.

Payments Upon Termination

Regardless of the manner in which the employment of a Named Executive Officer terminates, he is entitled to receive certain amounts earned during his term of employment. Such amounts include:

• Vested RSUs;

• Amounts contributed by the executive under the Deferral Plan;

• Vested matching contributions under the Deferral Plan;

• Pay for unused vacation; and

• Amounts accrued and vested through the Retirement Plan and the 401k Plan.

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I. Post-Employment Compensation: Termination for Cause

Type of Payment	Shivery ($)		McHale ($)		Olivier ($)		Butler ($)		Robb ($)
Incentive Programs
Annual Incentives		—		—		—		—		—
Performance Cash		—		—		—		—		—
Performance Shares		—		—		—		—		—
RSUs (1)		13,662,054		243,545		294,403		338,192		146,012
Pension and Deferred Compensation
Supplemental Plan (2)		4,323,395		—		—		—		—
Special Retirement Benefit (3)		—		—		1,553,877		—
Deferral Plan (4)		553,112		16,467		1,426,222		26,546		141,732
Other Benefits
Health and Welfare Cash Value		—		—		—		—		—
Perquisites		—		—		—		—		—
Separation Payments
Excise Tax & Gross-Up		—		—		—		—		—
Separation Payment for Non-Compete Agreement		—		—		—		—		—
Separation Payment for Liquidated Damages		—		—		—		—		—
Total		18,538,561		260,012		3,274,502		364,738		287,744

(1) Represents values of all RSUs granted to the Named Executive Officers under our long-term incentive programs that, as of the end of 2011, had been deferred upon vesting and remained deferred. Excludes retention pool RSU grants.

(2) Represents the actuarial present value at the end of 2011 of the benefit payable from the Supplemental Plan to Mr. Shivery upon termination. The benefit is payable as an annuity, and the present value was calculated as described in notes 1 and 2 to the Pension Benefits Table appearing above.

(3) Represents the actuarial present values at the end of 2011 of the amounts payable to the Named Executive Officers solely as the result of provisions in employment agreements, which are in addition to amounts payable by the Retirement Plan or the Supplemental Plan. Pursuant to the employment agreement with Mr. Olivier, a lump sum payment of $2,050,000, offset by the value of benefits from the Retirement Plan, would be payable to Mr. Olivier upon termination. Pension amounts reflected in the table are present values at the end of 2011 of benefits payable to each Named Executive Officer upon termination.

(4) Represents the vested Deferral Plan account balance of each Named Executive Officer accrued as of the end of 2011.

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II. Post-Employment Compensation: Voluntary Termination

Type of Payment	Shivery ($)		McHale ($)		Olivier ($)		Butler ($)		Robb ($)
Incentive Programs
Annual Incentives (1)		—		—		—		—		—
Performance Cash (2)		4,269,384		393,750		790,625		305,241		200,000
Performance Shares (3)		3,902,291		—		478,238		—		—
RSUs (4)		15,788,560		243,545		519,812		338,192		146,012
Pension and Deferred Compensation
Supplemental Plan (5)		7,566,228		—		—		—		—
Special Retirement Benefit (6)		2,490,831		—		1,533,877		—		—
Deferral Plan (7)		553,112		16,467		1,426,222		26,546		141,732
Other Benefits
Health and Welfare Benefits (8)		104,687		—		—		—		—
Perquisites		—		—		—		—		—
Separation Payments		—		—		—		—		—
Excise Tax & Gross-Up		—		—		—		—		—
Separation Payment for Non-Compete Agreement		—		—		—		—		—
Separation Payment for Liquidated Damages		—		—		—		—		—
Total		34,675,093		653,762		4,748,774		669,979		487,744

(1) Represents the actual 2011 annual incentive award for each Named Executive Officer, determined as described in the Compensation Discussion and Analysis.

(2) Represents the actual performance cash award under the 2009 — 2011 Long-Term Incentive Program for each Named Executive Officer. Also includes, for Messrs. Shivery and Olivier, performance cash awards under the 2010 — 2012 Long-Term Incentive Program, because each of them would be considered to be a “retiree” under those programs. Full grant amounts are awarded to Mr. Shivery because he has attained age 65, while amounts for Mr. Olivier are prorated for time worked in each three-year performance period, determined as described in the Compensation Discussion and Analysis.

(3) Includes, for Messrs. Shivery and Olivier, performance share awards under the 2010 — 2012 and 2011 — 2013 Long-Term Incentive Programs, because each of them would be considered to be a “retiree” under those programs. Full grant amounts are awarded to Mr. Shivery because he has attained age 65, while amounts for Mr. Olivier are prorated for time worked in the three-year performance period, determined as described in the Compensation Discussion and Analysis.

(4) Represents values of all RSUs granted to the Named Executive Officers under our long-term incentive programs that, as of the end of 2011, had been deferred upon vesting and remained deferred, or that had not yet vested according to their program grant vesting schedules. Under the terms of each RSU grant, RSUs vest on a prorated basis based on the Named Executive Officers’ years of credited service and age as of termination, and time worked during the vesting period. Full grant amounts are distributed without proration to Mr. Shivery because he has attained age 65. The values were calculated by multiplying the number of RSUs by $36.07, the closing price of our common shares on December 30, 2011, the last trading day of the year. Excludes retention pool RSU grants, which would not vest upon voluntary termination.

(5) Represents the actuarial present value at the end of 2011 of the benefit payable from the Supplemental Plan to Mr. Shivery upon termination. The benefit is payable as an annuity, and the present value was calculated as described in notes 1 and 2 to the Pension Benefits Table appearing above.

(6) Represents the actuarial present values at the end of 2011 of the amounts payable to the Named Executive Officers solely as the result of provisions in employment agreements, which are in addition to amounts payable by the Retirement Plan or the Supplemental Plan. Pursuant to the employment agreement with Mr. Shivery, pension benefits available upon voluntary termination were calculated with the addition of three years of service. Pursuant to the employment agreement with Mr. Olivier, a lump sum payment of $2,050,000 offset by the value of benefits from the Retirement Plan, would be payable to Mr. Olivier upon

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voluntary termination. Pension amounts reflected in the table are present values at the end of 2011 of benefits payable to each Named Executive Officer upon termination. Mr. Shivery’s benefit would be paid as an annuity calculated as described in notes 1 and 2 to the Pension Benefits Table appearing above.

(7) Represents the vested Deferral Plan account balance of each Named Executive Officer accrued as of the end of 2011.

(8) Represents the costs to the Company estimated by our benefits consultants as of the end of 2011 of providing post-employment welfare benefits to Mr. Shivery beyond those benefits that would be provided to a nonexecutive employee upon involuntary termination. Mr. Shivery is entitled to receive retiree health benefits under his employment agreement. To the extent these benefits are provided in excess of those provided to employees in general, Mr. Shivery would receive payments to offset the taxes incurred on such benefits.

III. Post-Employment Compensation: Involuntary Termination, Not for Cause

Type of Payment	Shivery ($)		McHale ($)		Olivier ($)		Butler ($)		Robb ($)
Incentive Programs
Annual Incentives (1)		—		—		—		—		—
Performance Cash (2)		4,269,384		754,683		790,625		585,048		200,000
Performance Shares (3)		3,902,291		455,521		478,238		353,434		—
RSUs (4)		15,788,560		782,611		859,656		755,919		531,939
Pension and Deferred Compensation
Supplemental Plan (5)		7,566,228		3,527,585		—		1,298,588		—
Special Retirement Benefit (6)		2,490,831		2,902,412		3,101,153		2,287,874		—
Deferral Plan (7)		553,112		16,467		1,426,222		26,546		141,732
Other Benefits
Health and Welfare Benefits (8)		104,687		69,125		—		67,851		—
Perquisites (9)		—		7,000		—		7,000		—
Separation Payments
Excise Tax & Gross-Up		—		—		—		—		—
Separation Payment for Non-Compete Agreement (10)		—		900,487		—		693,019		318,000
Separation Payment for Liquidated Damages (11)		—		900,487		—		693,019		318,000
Total		34,675,093		10,316,378		6,655,894		6,768,298		1,509,671

(1) Represents the actual 2011 annual incentive award for each Named Executive Officer, determined as described in the Compensation Discussion and Analysis.

(2) Represents the actual performance cash award under the 2009 — 2011 Long-Term Incentive Program for each Named Executive Officer. Also includes, for Messrs. Shivery, McHale, Olivier, and Butler, performance cash awards under the 2010 — 2012 Long-Term Incentive Program. Full grant amounts are awarded to Mr. Shivery because he has attained age 65, while amounts for Messrs. McHale, Olivier and Butler are prorated for time worked in each three-year performance period, because each of them would be considered to be a “retiree” under those programs, determined as described in the Compensation Discussion and Analysis.

(3) Includes, for Messrs. Shivery, McHale, Olivier and Butler, performance share awards under the 2010 — 2012 and 2011 — 2013 Long-Term Incentive Programs. Full grant amounts are awarded to Mr. Shivery because he has attained age 65, while amounts for Messrs. McHale, Olivier and Butler are prorated for time worked in the three-year performance period, because each of them would be considered to be a “retiree” under those programs, determined as described in the Compensation Discussion and Analysis.

(4) Represents values of all RSUs granted to the Named Executive Officers under our long-term incentive programs and the retention program that, as of the end of 2011, had been deferred upon vesting and

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remained deferred, or that had not yet vested according to their program grant vesting schedules. Under the terms of the long-term incentive programs, RSUs vest on a prorated basis based on the Named Executive Officers’ years of credited service and age as of termination, and time worked during the vesting period. Full grant amounts are distributed without proration to Mr. Shivery because he has attained age 65. Under the retention program, RSUs vest fully upon termination without cause of the Named Executive Officers and the value is reduced by any separation payments as described in notes 10 and 11. The values were calculated by multiplying the number of RSUs by $36.07, the closing price of our common shares on December 30, 2011, the last trading day of the year.

(5) Represents the actuarial present value at the end of 2011 of the benefit payable from the Supplemental Plan to Mr. Shivery upon termination. The benefit is payable as an annuity, and the present value was calculated as described in notes 1 and 2 to the Pension Benefits Table appearing above.

(6) Represents the actuarial present values at the end of 2011 of the amounts payable to the Named Executive Officers solely as the result of provisions in employment agreements, which are in addition to amounts payable by the Retirement Plan or the Supplemental Plan. Pursuant to the employment agreements with Messrs. McHale and Butler, pension benefits available upon an involuntary termination other than for cause were calculated with the addition of two years of age and service. Pursuant to the employment agreement with Mr. Shivery, pension benefits were calculated with the addition of three years of service. Pursuant to the employment agreement with Mr. Olivier, a lump sum payment of $3,101,153 offset by the value of benefits from the Retirement Plan, would be payable to Mr. Olivier upon an involuntary termination other than for cause. Pension amounts reflected in the table are present values at the end of 2011 of benefits payable to each Named Executive Officer upon termination. Except for the benefit payable to Mr. Olivier, all benefits are annuities calculated as described in notes 1 and 2 to the Pension Benefits Table appearing above.

(7) Represents the vested Deferral Plan account balance of each Named Executive Officer accrued as of the end of 2011.

(8) Represents the costs to the Company estimated by our benefits consultants as of the end of 2011 of providing post-employment welfare benefits to the Named Executive Officers beyond those benefits that would be provided to a nonexecutive employee upon involuntary termination. Each of Messrs. McHale and Butler is entitled to receive active health and welfare benefits and the cash value of Company-paid active long-term disability and life insurance benefits for two years under the terms of his respective employment agreement, plus tax gross-up with respect to such taxable subsidized coverage and are eligible to receive qualified benefits under the retiree health plan. Mr. Shivery is entitled to receive retiree health benefits under his employment agreement. Therefore, the amount reported in the table for Messrs. McHale and Butler represents (a) the value of 24 months of employer contributions toward active health, long-term disability, and life insurance benefits, plus (b) tax gross-up payments thereon. The amount reported in the table for Mr. Shivery represents (a) the value of lifetime retiree health coverage, plus (b) tax gross-up payments thereon.

(9) Represents the cost to us of reimbursing fees for financial planning and tax preparation services to Messrs. McHale and Butler for two years.

(10) Represents payments made as consideration for agreements by each of Messrs. McHale, Butler and Robb not to compete with the Company following termination. Employment or other agreements with Messrs. McHale, Butler and Robb provide for a lump-sum payment in an amount equal to the sum (one-half of the sum for Mr. Robb) of their 2011 annual salary plus annual incentive award at target (2010 for Mr. Robb). These payments do not replace, offset or otherwise affect the calculation or payment of the annual incentive awards.

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(11) Represents severance payments to Messrs. McHale, Butler and Robb paid in addition to the non-compete agreement payments described in note 10. This payment is an amount equal to the sum (one-half of the sum for Mr. Robb) of their actual base salary paid in 2011 plus the annual incentive award at target (2010 for Mr. Robb). These payments do not replace, offset or otherwise affect the calculation or payment of the annual incentive awards.

IV. Post-Employment Compensation: Termination Upon Disability

Type of Payment	Shivery ($)		McHale ($)		Olivier ($)		Butler ($)		Robb ($)
Incentive Programs
Annual Incentives (1)		—		—		—		—		—
Performance Cash (2)		4,269,384		754,683		790,625		585,048		383,329
Performance Shares (3)		3,902,291		455,521		478,238		353,434		231,391
RSUs (4)		15,788,560		2,843,641		2,323,709		2,803,403		1,337,400
Pension and Deferred Compensation
Supplemental Plan (5)		7,566,228		3,527,585		—		1,298,558		—
Special Retirement Benefit (6)		2,490,831		—		3,101,153		—		—
Deferral Plan (7)		553,112		16,467		1,426,222		26,546		141,732
Other Benefits
Health and Welfare Benefits (8)		104,687		—		—		—		—
Perquisites		—		—		—		—		—
Separation Payments
Excise Tax & Gross-Up		—		—		—		—		—
Separation Payment for Non-Compete Agreement		—		—		—		—		—
Separation Payment for Liquidated Damages		—		—		—		—		—
Total		34,675,093		7,597,897		8,119,947		5,067,329		2,093,852

(1) Represents the actual 2011 annual incentive award for each Named Executive Officer, determined as described in the Compensation Discussion and Analysis.

(2) Represents the actual performance cash award under the 2009 — 2011 Long-Term Incentive Program determined as described in the Compensation Discussion and Analysis , plus performance cash awards at target under the 2010 — 2012 Long-Term Incentive Program prorated for time worked in each three-year performance period.

(3) Represents the performance share award at target under the 2010 — 2012 and 2011 — 2013 Long-Term Incentive Programs prorated for time worked in the three-year performance period, as described in the Compensation Discussion and Analysis.

(4) Represents values of all RSUs granted to the Named Executive Officers under our long-term incentive programs and the retention program that, as of the end of 2011, had been deferred upon vesting and remained deferred, or that had not yet vested according to their program grant vesting schedules. Under the terms of the long-term incentive programs, RSUs vest on a prorated basis based on the Named Executive Officers’ years of credited service and age as of termination, and time worked during the vesting period. Under the retention program, RSUs vest fully upon termination due to disability of the Named Executive Officer. The values were calculated by multiplying the number of RSUs by $36.07, the closing price of our common shares on December 30, 2011¸ the last trading day of the year.

(5) Represents the actuarial present value at the end of 2011 of the benefit payable from the Supplemental Plan to each NEO other than Mr. Olivier. For purposes of valuing the pension benefits, we have assumed that each Named Executive Officer would remain on our Long Term Disability plan until the executive’s first unreduced combined pension benefit age. Therefore, the numbers shown represent the actuarial present values at the end of 2011 of nonqualified pension benefits payable to each Named Executive Officer,

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assuming termination of employment at the earliest unreduced benefit age. The earliest unreduced benefit ages are different for each NEO based on employment agreement provisions and years of service, as follows: Mr. Shivery: immediately; Mr. McHale: age 55; Mr. Olivier: immediately; and Mr. Butler: age 62. The benefit is payable as an annuity, and the present value was calculated as described in notes 1 and 2 to the Pension Benefits Table appearing above.

(6) Represents the actuarial present values at the end of 2011 of the amounts payable to the Named Executive Officers under the assumptions discussed in note 5, solely as the result of provisions in employment agreements, which are in addition to amounts payable by the Retirement Plan or the Supplemental Plan. Pursuant to the employment agreement with Mr. Shivery, pension benefits available upon disability termination were calculated with the addition of three years of service. Pursuant to the employment agreement with Mr. Olivier, a lump sum payment of $3,101,153, offset by the value of benefits from the Retirement Plan, would be payable to Mr. Olivier upon disability termination. Mr. Shivery’s benefit would be paid as an annuity calculated as described in notes 1 and 2 to the Pension Benefits Table appearing above.

(7) Represents the Deferral Plan account balance of each Named Executive Officer accrued as of the end of 2011.

(8) Represents the costs to the Company estimated by our benefits consultants as of the end of 2011 of providing post-employment welfare benefits to Mr. Shivery beyond those benefits that would be provided to a nonexecutive employee upon disability termination. Mr. Shivery is entitled to receive retiree health benefits under his employment agreement. To the extent these benefits are provided in excess of those provided to employees in general, Mr. Shivery would receive payments to offset the taxes incurred on such benefits.

V. Post-Employment Compensation: Death

Type of Payment	Shivery ($)		McHale ($)		Olivier ($)		Butler ($)		Robb ($)
Incentive Programs
Annual Incentives (1)		—		—		—		—		—
Performance Cash (2)		4,269,384		754,683		790,625		585,048		383,329
Performance Shares (3)		3,902,291		455,521		478,238		353,434		231,391
RSUs (4)		15,788,560		2,843,641		2,323,709		2,803,403		1,337,400
Pension and Deferred Compensation
Supplemental Plan (5)		3,858,776		3,527,585		—		1,298,558		—
Special Retirement Benefit (6)		1,270,324		—		3,214,047		—		—
Deferral Plan (7)		553,112		16,467		1,426,222		26,546		141,732
Other Benefits
Health and Welfare Benefits (8)		61,988		—		—		—		—
Perquisites		—		—		—		—		—
Separation Payments
Excise Tax & Gross-Up		—		—		—		—		—
Separation Payment for Non-Compete Agreement		—		—		—		—		—
Separation Payment for Liquidated Damages		—		—		—		—		—
Total		29,704,435		7,597,897		8,119,947		5,067,329		2,093,852

(1) Represents the actual 2011 annual incentive award for each Named Executive Officer, determined as described in the Compensation Discussion and Analysis.

(2) Represents the actual performance cash award under the 2009 — 2011 Long-Term Incentive Program determined as described in the Compensation Discussion and Analysis above, plus performance cash awards at target under the 2010 — 2012 Long-Term Incentive Program prorated for time worked in each three-year performance period.

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(3) Represents the performance share awards at target under the 2010 — 2012 and 2011 — 2013 Long-Term Incentive Programs prorated for time worked in the three-year performance period, as described in the Compensation Discussion and Analysis.

(4) Represents values of all RSUs granted to the Named Executive Officers under our long-term incentive programs and the retention program that, as of the end of 2011, had been deferred upon vesting and remained deferred, or that had not yet vested according to their program grant vesting schedules. Under the terms of the long-term incentive programs, RSUs vest on a prorated basis based on the Named Executive Officers’ years of credited service and age as of termination upon death, and time worked during the vesting period. Under the retention program, RSUs vest fully upon termination due to death of the Named Executive Officer. The values were calculated by multiplying the number of RSUs by $36.07, the closing price of our common shares on December 30, 2011, the last trading day of the year.

(5) Represents the lump sum present value of pension payments from the Supplemental Plan to the surviving spouse of each Named Executive Officer. The benefits are payable as annuities, and the present values are calculated as described in notes 1 and 2 to the Pension Benefits Table appearing above.

(6) Represents the actuarial present values at the end of 2011 of the amounts payable to the surviving spouses of the Named Executive Officers, solely as the result of provisions in employment agreements, which are in addition to amounts payable by the Retirement Plan or the Supplemental Plan. Pursuant to the employment agreement with Mr. Shivery, pension benefits available upon death were calculated with the addition of three years of service. Pursuant to the employment agreement with Mr. Olivier, a lump sum payment of $3,214,047, offset by the value of benefits from the Retirement Plan, would be payable to Mr. Olivier’s spouse upon death. Pension amounts reflected in the table are present values at the end of 2011 of benefits payable immediately to each Named Executive Officer’s surviving spouse or estate. Mr. Shivery’s benefit would be paid as an annuity calculated as described in notes 1 and 2 to the Pension Benefits Table appearing above.

(7) Represents the Deferral Plan account balance of each Named Executive Officer accrued as of the end of 2011.

(8) Represents the costs to the Company estimated by our benefits consultants as of the end of 2011 of providing post-employment welfare benefits to the Mr. Shivery’s surviving spouse beyond those benefits that would be provided to a nonexecutive employee’s spouse upon the employee’s death. Mr. Shivery’s surviving spouse is entitled to receive retiree health benefits under Mr. Shivery’s employment agreement. To the extent these benefits are taxable to Mr. Shivery’s surviving spouse, she would receive payments to offset the taxes incurred on such benefits.

Payments Made Upon a Change of Control

The employment or other agreements with Messrs. McHale, Olivier, Butler and Robb include change of control benefits. Mr. Olivier participates in the SSP, which provides benefits upon termination of employment in connection with a change of control. The employment agreements and the SSP are binding on us and on certain of our majority-owned subsidiaries. The terms of the various employment agreements are substantially similar, except for the agreement with Mr. Olivier, which refers instead to the change of control provisions of the SSP, and the agreement with Mr. Robb.

Pursuant to the employment or other agreements and under the terms of the SSP, if an executive officer’s employment terminates following a change of control, other than termination of employment for “cause” (as defined in the employment agreements, generally meaning willful and continued failure to perform his duties after written notice, a violation of our Standards of Business Conduct or conviction of a felony), or by reason of death or disability), or if the executive officer terminates his employment for “good reason” (as defined in the employment agreements, generally meaning an assignment to duties inconsistent with his position, a failure by the employer to satisfy material terms of the agreement or the transfer of the executive to an office location more than 50 miles from his principal place of business immediately prior to a change of control), then the executive officer will receive the benefits listed below, which receipt is conditioned upon delivery of a binding release of all legal claims against the Company:

• A lump sum severance payment of two-times (one-times for Mr. Olivier and one-half times for Mr. Robb) the sum of the executive’s base salary plus all annual awards that would be payable for the relevant year determined at target (Base Compensation);

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• As consideration for a non-competition and non-solicitation covenant, a lump sum payment in an amount equal to the Base Compensation (one-half times Base Compensation for Mr. Robb);

• Active health benefits continuation, provided by us for three years (two years for Mr. Olivier and none for Mr. Robb);

• Benefits as if provided under the Supplemental Plan, notwithstanding eligibility requirements for the Target Benefit, including favorable actuarial reductions and the addition of three years to the executive’s age and years of service as compared to benefits available upon voluntary termination of employment (except for Mr. Olivier whose benefits are described below, and Mr. Robb, who does not participate in the Supplemental Plan);

• Automatic vesting and distribution of common shares in respect of all unvested RSUs and performance units at target; and

• A lump sum payment in an amount equal to the excise tax charged to the executive under the Internal Revenue Code as a result of the receipt of any change of control payments, plus tax gross-up (except for Messrs. Olivier and Robb).

The summaries of the employment agreements above do not purport to be complete and are qualified in their entirety by the actual terms and provisions of the employment agreements, copies of which have been filed as exhibits to our Annual Report on Form 10-K for the year ended December 31, 2011.

VI. Post-Employment Compensation: Termination Following a Change of Control

Type of Payment	Shivery ($)		McHale ($)		Olivier ($)		Butler ($)		Robb ($)
Incentive Programs
Annual Incentives (1)		—		—		—		—		—
Performance Cash (2)		4,269,684		1,082,800		1,134,376		839,420		549,987
Performance Shares (3)		3,902,291		987,447		1,037,555		766,406		501,590
RSUs (4)		15,788,560		782,611		859,656		755,919		273,483
Pension and Deferred Compensation
Supplemental Plan (5)		7,566,228		3,527,585		—		1,298,558		—
Special Retirement Benefit (6)		2,490,831		2,902,412		3,101,153		2,287,874		—
Deferral Plan (7)		553,112		16,467		1,426,222		26,546		141,742
Other Benefits
Health and Welfare Benefits (8)		101,181		98,890		20,053		86,064		—
Perquisites (9)		—		8,500		—		8,500		—
Separation Payments
Excise Tax and Gross-Up (10)		—		4,001,955		—		2,767,501		—
Separation Payment for Non-Compete Agreement (11)		—		900,487		939,262		693,019		309,000
Separation Payment for Liquidated Damages (12)		—		1,800,874		939,262		1,386,038		309,000
Total		34,671,887		16,110,028		9,457,539		10,915,845		2,084,802

(1) Represents the actual 2011 annual incentive award for each Named Executive Officer, determined as described in the Compensation Discussion and Analysis.

(2) Represents the actual performance cash award under the 2009 — 2011 Long-Term Incentive Program for each Named Executive Officer, determined as described in the Compensation Discussion and Analysis, plus performance cash awards at target for each Named Executive Officer under the 2010 — 2012 Long-Term Incentive Program.

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(3) Represents the performance share award at target for each Named Executive Officer under the 2010 — 2012 and 2011 — 2013 Long-Term Incentive Programs, determined as described in the Compensation Discussion and Analysis.

(4) Represents values of all RSUs granted to the Named Executive Officers under our long-term incentive programs and the retention program that, as of the end of 2011, had been deferred upon vesting and remained deferred, or that had not yet vested according to their program grant vesting schedules. Under the terms of the long-term incentive programs, RSUs vest fully on termination following a change of control. Under the retention program, RSUs vest fully upon termination without cause of the Named Executive Officer and the value is reduced by any separation payments as described in notes 11 and 12. For Messrs. McHale, Olivier and Butler, retention program RSU grants are fully eliminated when offset by separation payments. The values were calculated by multiplying the number of RSUs by $36.07, the closing price of our common shares on December 30, 2011, the last trading day of the year.

(5) Represents the actuarial present value at the end of 2011 of the benefit payable from the Supplemental Plan to Messrs. Shivery, McHale and Butler upon termination. The benefit is payable as an annuity, and the present value was calculated as described in notes 1 and 2 to the Pension Benefits Table appearing above.

(6) Represents the actuarial present values at the end of 2011 of the amounts payable to the Named Executive Officers solely as the result of provisions in employment agreements, which are in addition to amounts payable by the Retirement Plan or the Supplemental Plan. Pursuant to the employment agreements with Messrs. McHale and Butler, pension benefits available upon termination following a Change of Control were calculated with the addition of three years of age and service. Pursuant to the employment agreement with Mr. Shivery, pension benefits available upon retirement were calculated with the addition of three years of service. Pursuant to the employment agreement with Mr. Butler, the value of the Supplemental Plan and Special Retirement Benefits will be paid as a single lump sum rather than as an annuity if his termination date occurs within two years following a change in control that qualifies under Section 1.409A of the Treasury Regulations. Pursuant to the employment agreement with Mr. Olivier, a lump sum payment of $3,101,153, offset by the value of benefits from the Retirement Plan, would be payable to Mr. Olivier upon termination following a Change in Control. Pension amounts reflected in the table are present values at the end of 2011 of benefits payable to each Named Executive Officer upon termination Except for the benefits payable to Messrs. Butler and Olivier, all benefits are annuities calculated as described in notes 1 and 2 to the Pension Benefits Table appearing above.

(7) Represents the Deferral Plan account balance of each Named Executive Officer accrued as of the end of 2011.

(8) Represents the costs to the Company estimated by our benefits consultants as of the end of 2011 of providing post-employment welfare benefits to the Named Executive Officers beyond those benefits that would be provided to a nonexecutive employee upon involuntary termination. Each of Messrs. McHale and Butler is entitled to receive active health and welfare benefits and the cash value of Company-paid active long-term disability and life insurance benefits for three years under the terms of his respective employment agreement, plus tax gross-up with respect to such taxable subsidized coverage and are eligible for qualified benefits under the retiree health plan. Mr. Olivier participates in the SSP and each is eligible for two years of active health benefits continuation plus gross-up payments on the value thereof. Mr. Shivery is entitled to receive retiree health benefits under his employment agreement. The amount reported in the table for Mr. McHale represents (a) the value of 36 months of employer contributions toward active health, long-term disability, and life insurance benefits, plus (b) tax gross-up payments thereon. The amount reported in the table for Mr. Butler represents (a) the value of 36 months of employer contributions toward active health, long-term disability, and life insurance benefits, plus (b) tax gross-up payments thereon, less (c) the value of 12 months of retiree health coverage at retiree rates. The amounts reported in the table for Mr. Olivier represents (a) the value of 24 months of employer contributions toward active health benefits, plus (b) tax gross-up payments thereon, less (c) the value of 24 months of retiree health coverage at retiree rates. The amount reported in the table for Mr. Shivery represents (a) the value of lifetime retiree health coverage, plus (b) tax gross-up payments thereon.

(9) Represents the cost to us of reimbursing fees for financial planning and tax preparation services to Messrs. McHale, and Butler for three years.

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(10) Represents payments made to offset costs to Messrs. McHale, and Butler associated with certain excise taxes under Section 280G of the Internal Revenue Code. Employees may be subject to certain excise taxes under Section 280G if they receive payments and benefits related to a termination following a Change of Control that exceed specified Internal Revenue Service limits. Employment agreements with each Named Executive Officer except Messrs. Olivier and Robb provide for a grossed-up reimbursement of these excise taxes. The amounts in the table are based on the Section 280G excise tax rate of 20%, the statutory federal income tax withholding rate of 35%, the Connecticut state income tax rate of 6.5%, and the Medicare tax rate of 1.45%.

(11) Represents payments made as consideration for each Named Executive Officer’s agreement not to compete with the Company following termination of employment. This payment equals the sum (one-half of the sum for Mr. Robb) of the actual base salary paid in 2011 (2010 for Mr. Robb) plus annual incentive award at target. Agreements with each Named Executive Officer or the SSP provide for a lump-sum payment equal to their annual salary plus their annual incentive award at target. These payments do not replace, offset or otherwise affect the calculation or payment of the annual incentive awards.

(12) Represents severance payments to each Named Executive Officer paid in addition to the non-compete agreement payments described in note 11. For Messrs. McHale, and Butler, this payment equals two-times the sum of the actual base salary paid in 2011 plus annual incentive award at target. For Mr. Olivier, this payment equals the sum of the actual base salary paid in 2011 plus annual incentive award at target. For Mr. Robb this payment equals one-half of the sum of his actual base salary paid in 2010 plus annual incentive award at target. These payments do not replace, offset or otherwise affect the calculation or payment of the annual incentive awards.

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TRUSTEE COMPENSATION

The Compensation Committee determines compensation for the Trustees based on competitive market practices for the total value of compensation and the allocation of cash and equity. The Committee uses data obtained from similarly-sized general industry companies as guidelines for setting Trustee compensation. The compensation elements consist of an annual retainer, meeting fees and equity grants in the form of RSUs. The level of Trustee compensation established by the Committee enables us to attract Trustees who have a broad range of backgrounds and experiences.

In 2011, we paid an annual retainer to each Trustee who is not employed by us or our subsidiaries. We pay an additional retainer to our Lead Trustee and the chairs of each of the Audit, Compensation, Corporate Responsibility, Corporate Governance and Finance Committees. Each retainer was paid in four equal quarterly installments. We paid one-half of the value of the retainers payable to the chairs of each of the Audit and Compensation Committees in the form of common shares. The following table sets forth the amounts of non-employee Trustee retainers for 2011:

Retainer	Annual Amount
Annual Retainer (all Trustees)	$	45,000
Lead Trustee	$	50,000
Audit Committee Chair	$	20,000
Compensation Committee Chair	$	15,000
Corporate Responsibility Committee Chair	$	7,500
Corporate Governance Committee Chair	$	7,500
Finance Committee Chair	$	10,000

During 2011, we paid each non-employee Trustee $1,500 for attendance in person or by telephone at each meeting of the full Board and each committee on which he or she served. In 2011, in addition to regularly scheduled meetings, the Board and various committees of the Board conducted meetings in connection with our pending merger with NSTAR and the impact of Tropical storm Irene and the October 29, 2011 snowstorm.

Under the Northeast Utilities Incentive Plan, each non-employee Trustee is eligible to receive share-based grants during each calendar year. On January 3, 2011, each non-employee Trustee was granted 3,000 RSUs under the Incentive Plan, all of which vested on January 10, 2012.

The share ownership guidelines set forth in the Company’s Corporate Governance Guidelines required Trustees to attain, by January 2012, 7,500 common shares and/or RSUs, which have a fair market value equal to approximately five times the value of the current annual retainer; provided, however, that Trustees who join the Board after January 1, 2007 will be required to attain such shares no later than five years from January 1 of the year succeeding their date of election to the Board. All of the current Trustees exceed the required share ownership threshold.

Prior to the beginning of each calendar year, non-employee Trustees may irrevocably elect to receive all or any portion of their retainers and fees in the form of common shares. Pursuant to the Northeast Utilities Deferred Compensation Plan for Trustees, each Trustee may also irrevocably elect to defer receipt of all or a portion of cash and/or equity compensation, including RSUs issued under the Incentive Plan. Deferred funds are credited with interest at the rate set forth in Section 37-1 of the Connecticut General Statutes, which rate was 8% for all of 2011. Deferred compensation is payable either in a lump sum or in one to five annual installments in accordance with the Trustee’s prior election.

A non-employee Trustee who performs additional Board-related services in the interest of Northeast Utilities or any of its subsidiaries upon the request of either the Board or the Chairman of the Board is entitled to receive additional compensation equal to $750 per half-day plus reasonable expenses. In addition, we pay travel-related expenses for spouses of Trustees who attend Board functions. The Internal Revenue Service considers payment of travel expenses for a Trustee’s spouse to be imputed income to the individual Trustee. Effective January 1, 2009, we discontinued tax gross-up payments in connection with spousal travel expenses.

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The table below sets forth all compensation paid to or accrued by each non-employee Trustee in 2011.

Trustee	Fees Earned or Paid in Cash ($) (1)		Stock Awards ($) (2)		Option Awards ($) (3)		Non-Equity Incentive Compensation ($)		Change in Pension Value and Non- Qualified Deferred Compensation Earnings ($) (4)		All Other Compen- sation ($)		Total ($)
Richard H. Booth		118,000		105,850		—		—		—		—		223,850
John S. Clarkeson		112,500		103,350		—		—		—		—		215,850
Cotton M. Cleveland		102,000		95,850		—		—		35,588		—		233,438
Sanford Cloud, Jr.		112,500		95,850		—		—		2,209		—		210,559
John G. Graham (5)		105,000		95,850		—		—		19,194		—		220,044
Elizabeth T. Kennan (5)		183,500		95,850		—		—		—		—		279,350
Kenneth R. Leibler		128,500		95,850		—		—		—		—		224,350
Robert E. Patricelli (5)		0		194,850		—		—		—		—		194,850
John F. Swope (5)		99,000		103,350		—		—		—		—		202,350
Dennis R. Wraase		106,500		95,850		—		—		—		—		202,350

(1) Represents the aggregate dollar amount of all fees earned or paid in cash, including annual retainer fees, committee and/or committee chair fees, and meeting attendance fees. Also includes the amount of cash compensation deferred at the election of the Trustee. For 2011, Ms. Cleveland deferred receipt of 75% of her board retainer and meeting fees.

(2) Includes the grant date market value of RSU grants in 2011. Each trustee received a grant of 3,000 RSUs on January 3, 2011 at a grant date market value of $95,850, which vested on January 10, 2012. We paid one-half of the retainers for the Chair of the Audit Committee and the Chair of the Compensation Committee in cash. We paid the balance of these retainers in common shares with an acquisition date market value equal to one-half of the amount of the retainer on the payment dates. The amounts reported for Mr. Booth and Mr. Clarkeson include the grant date market value of these common shares. For Mr. Booth, the amount includes one-half the retainer paid to him on four different dates as Chair of the Audit Committee, or $10,000, which equaled the market value of 297 common shares on the grant dates. Mr. Booth deferred the receipt of these shares in accordance with the provisions of the Northeast Utilities Deferred Compensation Plan for Trustees. For Mr. Clarkeson, the amount includes one-half of the retainer paid to him on four different dates as Chair of the Compensation Committee, totaling $7,500, which equaled the market value of 291 common shares on the grant dates. The amounts reported for Mr. Patricelli and Mr. Swope include the voluntary conversion to shares of amounts earned for retainers and/or meeting fees. The amounts reported for Mr. Patricelli and Mr. Swope include the acquisition date market value of these common shares. For Mr. Patricelli, the amount includes the conversion of $99,000 to shares, which equaled the market value of 2,856 shares on five different dates, and included (i) 100% of his board retainer, or $45,000; and (ii) 100% of the amount earned for his attendance at board and committee meetings, or $54,000. For Mr. Swope, the amount includes the conversion of 100% of the retainer paid to him on four different dates as Chair of the Corporate Responsibility Committee, totaling $7,500, which equaled the market value of 223 shares. Mr. Swope deferred the receipt of these shares in accordance with the provisions of the Northeast Utilities Deferred Compensation Plan for Trustees. In addition, outstanding RSU grants accrued corresponding dividend-equivalent units that are subject to the same restrictions as the underlying RSUs. There were no outstanding option awards as of December 31, 2011. Total deferred RSU awards held by our Trustees as of December 31, 2011 were as follows:

Trustee	RSUs and Dividend Equivalent Units Outstanding on December 31, 2011
Richard H. Booth		27,998
John S. Clarkeson		3,096
Cotton M. Cleveland		27,998
Sanford Cloud, Jr.		13,101
John G. Graham		27,998
Elizabeth T. Kennan		28,776
Kenneth R. Leibler		3,096
Robert E. Patricelli		3,096
John F. Swope		27,998
Dennis R. Wraase		6,275

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RSUs and dividend equivalent units outstanding at December 31, 2011 included 3,000 unvested RSUs granted to each Trustee on January 3, 2011, plus 96 unvested dividend equivalent units accrued on such RSUs, all of which vested on January 10, 2012. RSUs and dividend equivalent units in excess of 3,096, if any, reflect vested deferred RSUs and/or vested deferred dividend equivalent units.

All equity holdings are reported in the table captioned “Common Stock Ownership of Trustees and Management” appearing on page 25 of this proxy statement. Assumptions used in the calculation of this amount appear in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our Annual Report on Form 10-K for the year ended December 31, 2011. Forfeitures are estimated, and the compensation cost of the restricted share unit awards will be reversed if the non-employee Trustee does not remain a Trustee throughout the one-year vesting period.

(3) We did not grant options to non-employee Trustees in 2011. We have not granted stock options since 2002.

(4) Reflects the difference between the interest earned on amounts deferred by non-employee Trustees under the Northeast Utilities Deferred Compensation Plan for Trustees and interest calculated at 120% of the Internal Revenue Service prescribed applicable monthly long-term federal rate which represents a market rate of return. We do not provide pension benefits to our non-employee Trustees.

(5) Effective upon completion of the Merger with NSTAR on April 10, 2012, John G. Graham, Elizabeth T. Kennan, Robert E. Patricelli and John F. Swope each retired as a Trustee of Northeast Utilities and from all committees of the Board on which each of them served.

CHANGES IN TRUSTEE COMPENSATION

Effective July 17, 2012, the Board of Trustees approved a new compensation structure for non-employee Trustees. Under the new structure, each non-employee Trustee serving on January 1, 2013, and on January 1 of any succeeding year, will receive an annual cash retainer in the amount of $100,000 for service on the Board during his or her term of office, including participation in all Board and committee meetings. The retainer will be payable in equal installments on the first business day of each calendar quarter. In addition, each non-employee Trustee serving on January 1, 2013, and on January 1 of any succeeding year, will receive a grant under the Northeast Utilities Incentive Plan (the “Plan”), effective on the 10th business day of each such year, of that number of RSUs resulting from dividing $100,000 by the average closing price of our common shares as reported on the NYSE for the 10 trading days immediately preceding such date and rounding the resulting amount to the nearest whole RSU. Any individual who is elected to serve as a Trustee after January 1 of any calendar year will receive an RSU grant prorated from the date of such election and granted on the first business day of the month following such election. Finally, effective on the first business day of each calendar quarter beginning in January 2013, Trustees holding the positions of Non-Executive Chairman of the Board, Lead Trustee, Chair of the Audit Committee, Chair of the Compensation Committee, Chair of the Corporate Governance Committee, and Chair of the Finance Committee will receive additional annual cash payments in the amounts set forth below, payable in equal installments on the first business day of each calendar quarter, as retainers for additional Trustee service during his or her term of office in these positions, including participation in all meetings of the Board and committees thereof:

Position	Additional Annual Cash Retainer
Non-Executive Chairman of the Board	$	200,000
Lead Trustee	$	25,000
Chair of Audit Committee	$	15,000
Chair of Compensation Committee	$	10,000
Chair of Corporate Governance Committee	$	10,000
Chair of Finance Committee	$	10,000

On July 17, 2012, the Board approved pro-rata annual cash retainers, pro-rata annual RSU grants, and pro-rata additional annual cash retainers, for service as a Trustee of Northeast Utilities, based on the amounts described above, adjusted to account for fees received for service in 2012 as a Trustee of Northeast Utilities or as a Trustee of NSTAR, as the case may be.

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SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE

Section 16(a) of the Securities Exchange Act of 1934 requires the Trustees and executive officers of Northeast Utilities and persons who beneficially own more than ten percent of the outstanding common shares of Northeast Utilities to file reports of ownership and changes in ownership with the Securities and Exchange Commission and the New York Stock Exchange. As a practical matter, we assist our Trustees and executive officers by monitoring transactions and completing and filing Section 16 reports on their behalf. Based on such reports and the written representations of our Trustees and executive officers, we believe that for the year ended December 31, 2011, all such reporting requirements were complied with in a timely manner.

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PROPOSAL 2

ADVISORY VOTE ON EXECUTIVE COMPENSATION

Under the terms of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), shareholders are entitled to vote on a non-binding advisory proposal to approve the compensation of our Named Executive Officers, as disclosed in the compensation discussion and analysis (CD&A), compensation tables and narrative discussion in this proxy statement, commonly known as “Say-on-Pay.” Pursuant to the Dodd-Frank Act, the shareholder vote is advisory only and is not binding on us or the Board of Trustees. The Board of Trustees, however, will review the voting results and will take them into consideration when making future decisions regarding the compensation of our Named Executive Officers.

The fundamental objective of our Executive Compensation Program is to motivate executives and key employees to support our strategy of investing in and operating businesses that benefit customers, employees, and shareholders. We strive to provide executive officers with base salary, performance-based annual incentive compensation and long-term incentive compensation opportunities that are competitive with the market. With respect to incentive compensation, the Compensation Committee believes it is important to balance short-term goals, such as generating earnings, with longer-term goals, such as long-term value creation and maintaining a strong balance sheet. Shareholders are encouraged to read the CD&A, compensation tables and narrative discussion in this proxy statement.

Our 2011 Executive Compensation Program included the following material elements:

• Base Salary;

• Annual Incentive Program;

• Long-Term Incentives (consisting of RSUs and performance units);

• Nonqualified Deferred Compensation;

• Supplemental Executive Retirement Plan;

• Certain officer perquisites; and

• Employment Agreements that provide payments and benefits upon involuntary termination of employment and termination of employment resulting from a change in control.

The Executive Compensation Program also features share ownership guidelines to emphasize the importance of share ownership.

The compensation of our Named Executive Officers during 2011 was consistent with the following achievements and financial performance:

• Earnings of $394.7 million, or $2.22 per share, in 2011, compared with $387.9 million, or $2.19 per share, in 2010;

• Adjusted Net Income (ANI) of $406.0 million in 2011 compared with $400.6 million in 2010;

• Share price appreciation of 13.1% from a closing price of $31.88 per share on December 31, 2010 to a closing price of $36.07 on December 31, 2011; and

• Substantial progress in achieving the merger with NSTAR, which was completed on April 10, 2012.

We believe that the compensation of our Named Executive Officers is aligned with our financial performance. We exceeded our financial objectives in 2011 and as a result, the Compensation Committee provided base pay increases to the executive officers, including the Named Executive Officers, for the first time in three years.

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Mr. Shivery’s 2011 total compensation reported in the Summary Compensation Table exceeded his 2010 amount by 17.3%. However, as described in the CD&A included in this proxy statement, Mr. Shivery’s 2011 compensation included a special grant of 76,406 RSUs, valued at $2,574,118, to recognize Mr. Shivery’s role in the Merger with NSTAR. He did not receive a comparable grant in 2010. Excluding the value of the 2011 special grant, Mr. Shivery received compensation of $7,011,939 for 2011, a decrease of 16% as compared with total compensation of $8,254,374 for 2010. In addition, as described in the CD&A, Mr. Shivery did not receive an annual cash incentive payment for 2011, compared with an annual cash incentive for 2010 of $1,987,200.

The Compensation Committee and the Board of Trustees believe that our Executive Compensation Program is effective in implementing our compensation philosophy and in achieving its goals. We are requesting your non-binding vote on the following resolution:

“RESOLVED, that the compensation paid to the Company’s named executive officers, as disclosed pursuant to the compensation disclosure rules of the Securities and Exchange Commission, including the compensation discussion and analysis, the compensation tables and any related material disclosed in this proxy statement, is hereby APPROVED.”

The Board of Trustees recommends that shareholders vote FOR this proposal.

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PROPOSAL 3

RE-APPROVAL OF MATERIAL TERMS OF PERFORMANCE GOALS UNDER THE 2009 NORTHEAST UTILITIES INCENTIVE PLAN

The Board of Trustees recommends that shareholders vote “FOR” the re-approval of the material terms of the performance goals under the Northeast Utilities Incentive Plan as amended and restated effective January 1, 2009 (the “Plan”). A description of such material terms of the Plan is included below. The description is qualified in its entirety by reference to the Plan, a copy of which is attached to this proxy statement as Appendix A. You may also obtain a copy upon written request to our Assistant Secretary at the address set forth on page 7 of this proxy statement.

Background

You are being asked to re-approve the material terms of the performance goals currently included in the Plan so that we can continue to deduct from our federal income taxes the full amount of incentive awards paid under the Plan that otherwise qualify as “performance-based compensation” under Section 162(m) of the Internal Revenue Code of 1986, as amended (Section 162(m)). Under Section 162(m) and related regulations, compensation in excess of $1 million paid in any one year to a public company’s covered employees cannot be so deducted unless such compensation qualifies as “performance-based compensation” under Section 162(m) (or another exception is met). Covered employees include our Chief Executive Officer, our Chief Financial Officer and our three other most highly compensated executive officers.

For compensation to qualify as “performance-based,” Section 162(m) requires our shareholders to re-approve the material terms of the Plan’s performance goals every five years. Such material terms were re-approved by shareholders five years ago at our 2007 Annual Meeting of Shareholders. Eligible compensation paid to our covered employees under the Plan will continue to be fully tax deductible by the Company if the Plan’s performance goals are re-approved at this Annual Meeting of Shareholders (and if other applicable Section 162(m) requirements are met). If the Plan’s performance goals are not re-approved at this Annual Meeting of Shareholders, then otherwise eligible amounts paid to our covered employees will not qualify as “performance-based compensation.” As a result, we will be subject to Section 162(m)’s disallowance of deductions for covered employee compensation in excess of $1 million.

Eligibility

Under the Plan, the Compensation Committee of the Board is authorized: (a) to make annual incentive awards to officers of the Company at or above the Vice President level (the “Awards”), and (b) to grant incentive stock options, nonqualified stock options, restricted stock, restricted share units, stock appreciation rights and performance units to selected Company employees (including employees who are also Trustees of the Company), non-employee Trustees of the Company (with respect to all of the foregoing except incentive stock options) and Company contractors (with respect to nonqualified stock options only) (collectively, the “Grants”). The number of persons eligible to participate in the Plan and the number of participants may vary from year to year. As of May 1, 2012, approximately 45 employees were eligible to receive Awards under the Plan, and approximately 6,275 employees and 13 non-employee Trustees were eligible to receive Grants under the Plan.

Performance Measures

To determine the payouts and/or vesting with respect to Awards and Grants under the Plan that are designed to qualify as performance-based compensation under Section 162(m), the Plan permits the Compensation Committee to use any one or more of the following objective performance measures:

Cash flow; earnings (including, but not limited to, earnings before interest, taxes, depreciation and amortization or operating earnings); earnings per share from continuing operations; inventory turnover;

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debt; credit rating; return on investment; net or gross sales; economic value added; change in assets; unit volume; delivery performance; safety record; return on equity; return on capital; revenue; operating income or net operating income; gross margin; completion of acquisitions, divestitures, business expansion, product diversification, new or expanded market penetration; other strategic business criteria consisting of one or more objectives based on satisfaction of specified revenue goals, geographic business expansion goals, or cost targets; cash flow from operations; earnings per share, diluted or basic; net asset turnover; capital expenditures; debt reduction; working capital; return on sales; market share; cost of capital; expense reduction levels; productivity; service levels; stock price; total shareholder return; return on assets or net assets; income or net income; operating profit or net operating profit; operating margin or profit margin; and other non-financial operating and management performance objectives.

The Compensation Committee establishes in writing the objective performance measures (based on the measures listed above) and other conditions of the Awards and Grants within the time required by Section 162(m) (where applicable). At the end of the applicable performance period, the Compensation Committee certifies the results of the performance measures and the extent to which the performance measures have been achieved.

With respect to Awards and Grants intended to qualify as performance-based compensation (and to the extent consistent with Section 162(m) and the regulations thereunder), the Compensation Committee may, unless it otherwise determines at the time such performance measures are established, adjust such performance measures to exclude the effect of any of the following events that occur during a Performance Period: the impairment of tangible or intangible assets; litigation or claim judgments or settlements; changes in tax law, accounting principles or other such laws or provisions affecting reported results; business combinations, reorganizations and/or restructuring programs that have been approved by the Board; reductions in force and early retirement incentives; and any extraordinary, unusual, infrequent or non-recurring items separately identified in the financial statements and/or notes thereto in accordance with generally accepted accounting principles. With respect to Awards and Grants intended to qualify as performance-based compensation (except as provided above or in the Plan), the Compensation Committee does not have discretion to increase the amount of compensation payable upon achievement of pre-established performance measures.

Maximum Amounts

The following maximums apply under the Plan:

• The aggregate number of common shares of Northeast Utilities par value $5.00 that may be subject to grants of incentive stock options and nonqualified stock options, or transferred on account of other Grants or Awards under the Plan, shall not exceed 4.5 million shares.

• No individual may receive aggregate Grants and Awards in excess of 1 million shares over the term of the Plan.

• Annual incentive Awards for any individual shall not exceed $4 million.

• The number of performance units paid in cash to any individual with respect to a performance period shall not exceed $4 million.

• The number of performance units granted and paid in shares shall not exceed 4.5 million shares.

Other Key Provisions of the Plan

The terms of the Plan will remain unchanged, and the re-approval does not affect the nature and amount of Awards and Grants under the Plan. The Compensation Committee or the Board of Trustees may amend, suspend or terminate the Plan, in whole or in part, at any time; however, any amendment must be made with shareholder approval where such approval is required by Section 162(m).

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Subject to certain anti-dilution and other adjustments, the number of common shares of the Company that may be issued under the Plan is limited to 4.5 million shares over the ten year period ending May 7, 2017, of which approximately 2,532,334 shares remained available for Awards and Grants as of September 4, 2012. If an Award or Grant lapses or is forfeited, the common shares of Company that would have been issued in connection with that Award or Grant become available to be used for other Awards or Grants. The Awards and Grants that have been made under the Plan for the last three completed fiscal years to named executive officers are presented in the “Summary Compensation Table” on pages 55-56 of this proxy statement.

The Board of Trustees recommends that shareholders vote FOR this proposal.

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PROPOSAL 4

RATIFICATION OF THE SELECTION OF

INDEPENDENT REGISTERED PUBLIC ACCOUNTANTS

The Audit Committee selected the independent registered public accounting firm of Deloitte & Touche LLP to serve as independent registered public accountants of Northeast Utilities and its subsidiaries for 2012. Pursuant to the recommendation of the Audit Committee, the Board of Trustees recommends that shareholders ratify the selection of Deloitte & Touche LLP to conduct an audit of Northeast Utilities for 2012. Our Declaration of Trust does not require that our shareholders ratify the selection of independent registered public accountants. The Board is submitting the selection of Deloitte & Touche LLP to our shareholders for ratification as a matter of good corporate practice. Whether or not the selection of Deloitte & Touche LLP is ratified by our shareholders, the Audit Committee may, in its discretion, change the selection at any time during the year if it determines that such change would be in the best interests of the Company and its shareholders. This is consistent with the responsibilities of the Audit Committee as outlined in its charter.

Representatives of Deloitte & Touche LLP are expected to be present at the Annual Meeting. They will have the opportunity to make a statement, if they desire to do so, and to respond to appropriate questions raised by shareholders at the meeting.

The affirmative vote of a majority of those votes cast at the meeting is required to ratify the selection of Deloitte & Touche LLP.

The Board of Trustees recommends that shareholders vote FOR this proposal.

RELATIONSHIP WITH INDEPENDENT REGISTERED PUBLIC ACCOUNTANTS

Pre-Approval of Services Provided by Principal Independent Registered Public Accountants

The Audit Committee has established policies and procedures regarding the pre-approval of services provided by the independent registered public accountants. Those policies and procedures delegate pre-approval of services to the Audit Committee Chair and/or Vice Chair provided that such offices are held by Trustees who are “independent” within the meaning of the Sarbanes-Oxley Act of 2002 and that all such pre-approvals are presented to the Audit Committee at the next regularly scheduled meeting of the Committee.

Fees Paid to Principal Independent Registered Public Accountants

Northeast Utilities and its subsidiaries paid Deloitte & Touche LLP fees aggregating $4,366,359 and $3,697,371 for the years ended December 31, 2011 and 2010, respectively, comprised of the following:

1. Audit Fees

The aggregate fees billed to Northeast Utilities and its subsidiaries by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu and their respective affiliates (collectively, the Deloitte Entities), for audit services rendered for the years ended December 31, 2011 and 2010 totaled $2,956,000 and $2,713,150, respectively. The audit fees were incurred for audits of Northeast Utilities’ annual consolidated financial statements and those of its subsidiaries, reviews of financial statements included in Northeast Utilities’ Quarterly Reports on Form 10-Q and those of its subsidiaries, comfort letters, consents and other costs related to registration statements and financings. The fees also included audits of internal controls over financial reporting as of December 31, 2011 and 2010, as well as auditing the implementation of new accounting standards and the accounting for new contracts.

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2. Audit Related Fees

The aggregate fees billed to us and our subsidiaries by the Deloitte Entities for audit related services rendered for the years ended December 31, 2011 and 2010 totaled $519,000 and $480,166, respectively.

3. Tax Fees

The aggregate fees billed to Northeast Utilities and its subsidiaries by the Deloitte Entities for tax services for the years ended December 31, 2011 and 2010 totaled $39,859 and $52,535, respectively. These services related primarily to the reviews of tax returns and reviewing the tax impacts of proposed transactions in 2011 and 2010.

4. All Other Fees

The aggregate fees billed to us and our subsidiaries by the Deloitte Entities for services other than the services described above for the years ended December 31, 2011 and 2010 totaled $851,500 and $451,500, respectively. All other fees in 2011 consisted primarily of consulting services related to the Company’s consideration of implementing enterprise resource planning systems. All other fees in 2010 consisted primarily of advisory services related to enterprise resource planning. All other fees in 2011 and 2010 also included a license fee for access to an accounting research tool.

The Audit Committee pre-approves all auditing services and permitted non-audit services (including the fees and terms thereof) to be performed for us by our independent registered public accountants, subject to the de minimis exceptions for non-audit services described in Section 10A(i)(1)(B) of the Securities Exchange Act of 1934, which are approved by the Audit Committee prior to the completion of the audit. The Audit Committee may form and delegate its authority to subcommittees consisting of one or more members when appropriate, including the authority to grant pre-approvals of audit and permitted non-audit services, provided that decisions of such subcommittee to grant pre-approvals are presented to the full Audit Committee at its next scheduled meeting. During 2011, all services described above were pre-approved by the Audit Committee.

The Audit Committee has considered whether the provision by the Deloitte Entities of the non-audit services described above was allowed under Rule 2-01(c)(4) of Regulation S-X and was compatible with maintaining the independence of the registered public accountants and has concluded that the Deloitte Entities were and are independent of us in all respects.

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REPORT OF THE AUDIT COMMITTEE

The Audit Committee is solely responsible for oversight of the relationship of Northeast Utilities with our independent registered public accountants on behalf of the Board of Trustees. As part of its responsibilities, during 2011, the Audit Committee:

• Received from the independent registered public accountants the written disclosure, including the letter from the independent registered public accountants required by the Independence Standards Board Standard No. 1 and has discussed these matters and the independent registered public accountants’ independence with the independent registered public accountants as required by the Securities and Exchange Commission independence rules, Rule 2-01 of Regulation S-X;

• Discussed with the independent registered public accountants the matters required to be discussed by Statement on Auditing Standards No. 61; and

• Reviewed and discussed the audited consolidated financial statements of Northeast Utilities for the years ended December 31, 2011 and 2010 with management.

The Board of Trustees and the Audit Committee are aware of the requirements of the Sarbanes-Oxley Act of 2002, the related increased scrutiny of financial statement disclosures of publicly held companies and the related rulemaking issued by the Securities and Exchange Commission. The Audit Committee has discussed the appropriateness and adequacy of disclosures in the consolidated financial statements with management and the independent registered public accountants in light of this guidance.

Based on the review and discussions referred to above, the Audit Committee recommended to the Board of Trustees that the audited consolidated financial statements be included in Northeast Utilities’ Annual Report on Form 10-K for the year ended December 31, 2011 for filing with the Securities and Exchange Commission.

The Committee has directed the preparation of this report and has approved its content and submission to shareholders.

Respectfully submitted,

Richard H. Booth (Chair)

Dennis R. Wraase (Vice Chair)

John G. Graham

Elizabeth T. Kennan

Kenneth R. Leibler

February 22, 2012

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OTHER MATTERS

The Board of Trustees knows of no matters other than the foregoing to come before the meeting. However, if any other matters come before the meeting, the persons named in the enclosed proxy will vote in their discretion with respect to such other matters.

By Order of the Board of Trustees,

Gregory B. Butler

Senior Vice President, General Counsel

and Secretary

ANNUAL REPORT TO SHAREHOLDERS AND

ANNUAL REPORT ON FORM 10-K

Northeast Utilities’ Annual Report to Shareholders for the year ended December 31, 2011, including financial statements, is included as Appendix B to this proxy statement. We will mail an additional copy of the Annual Report to any shareholder upon request. We will provide shareholders with a copy of our Annual Report on Form 10-K for the year ended December 31, 2011 filed with the Securities and Exchange Commission on February 24, 2012, including the financial statements and schedules thereto, without charge, upon receipt of a written request sent to:

Richard J. Morrison

Assistant Secretary

Northeast Utilities

Post Office Box 270

Hartford, Connecticut 06141-0270

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Appendix A

Northeast Utilities Incentive Plan

Amended, Restated and Adopted by Northeast Utilities

Compensation Committee of the Board of Trustees on

February 13, 2007 as Approved by Northeast Utilities

Shareholders on May 8, 2007

Amended and Restated Effective

January 1, 2009

ARTICLE I

PURPOSE

The purpose of the Northeast Utilities Incentive Plan (the “Plan”) is to provide (i) designated employees of the Company (as hereinafter defined in Article X) and (ii) non-employee members of the Board of Trustees (the “Board”) of Northeast Utilities, a Massachusetts business trust, (“NU”) with the opportunity to receive annual incentive compensation and grants of incentive stock options, nonqualified stock options, stock appreciation rights, restricted shares, restricted share units and performance units. The Company believes that the Plan will assist it in recruiting talented employees who will contribute materially to the growth of the Company, thereby benefiting NU’s shareholders and aligning the economic interests of the participants with those of the shareholders.

For purposes of the Plan, definitions appear in the Plan and as set forth in Article XIV.

ARTICLE II

ADMINISTRATION

1. Committee. The Plan shall be administered and interpreted by the Board’s Compensation Committee, or the person or persons to which such committee delegates any of its functions under the Plan (the “Committee”). The Committee may consist of two or more persons appointed by the Board, all of whom shall be “outside directors” as defined under section 162(m) of the Internal Revenue Code of 1986, as amended (the “Code”) and related Treasury regulations and “non-employee directors” as defined under Rule 16b-3 under the Exchange Act. Members of the Committee shall be “independent” as defined under the listing standards of the New York Stock Exchange. However, the Board may ratify or approve any grants as it deems appropriate or as are submitted by the Committee.

2. Committee Authority. The Committee shall have the authority to amend or terminate the Plan as provided in Article XII. The Committee shall have the sole authority to (a) establish, and review the Company’s and the Grantee’s, as defined below, performance against annual goals for purpose of the annual incentives to be distributed and determine the individuals to whom grants shall be made under the Plan, (b) determine the type, size and terms of the grants to be made to each such individual, (c) determine the time when the grants will be made and the duration of any applicable exercise or restriction period, including the criteria for exercisability and the acceleration of exercisability (d) establish such rules and regulations or take such action as it deems necessary or advisable for the proper administration of the Plan, including the delegation of day-to-day plan administration, and (e) deal with any other matters arising under the Plan.

3. Committee Determinations. The Committee shall have full power and authority to administer and interpret the Plan, to make factual determinations and to adopt or amend such rules, regulations, agreements and instruments for implementing the Plan and for the conduct of its business as it deems necessary or advisable, in its sole discretion. The Committee’s interpretations of the Plan and all determinations made by the Committee pursuant to the powers vested in it hereunder shall be conclusive and binding on all persons having any interest in the Plan or in any awards granted hereunder including, but not limited to, the Company, the Committee, the Board, the affected Participants, and their respective successors in interest. All powers of the Committee shall be executed in its sole discretion, in the best interest of the Company, not as a fiduciary, and in keeping with the objectives of the Plan and need not be uniform as to similarly situated individuals.

ARTICLE III

ANNUAL INCENTIVE AWARDS

1. Eligibility for Participation. Each employee of the Company classified as a Vice President or higher (an “Executive Employee”) shall be eligible to receive an annual incentive award (an “Award”) under the Plan

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2. Annual Awards.

(a) As soon as practicable after the start of each fiscal year of NU, but in any event within 90 days, the Committee shall set the Performance Goals for the Company which shall be the basis for determining the Awards to be paid to each Executive Employee for such fiscal year and the Committee shall communicate the target and the percentages (including minimums and maximums) for each Executive Employee applicable to each level of achievement against the target set. In no event may an individual Award for an Executive Employee exceed $4,000,000.

(b) The maximum amount of an Award for an Executive Employee shall be based upon the Company’s performance compared against the Performance Goals set for that fiscal year. The actual amount of the Award for any Executive Employee shall be reduced, accordingly, by the Committee if the Executive Employee does not satisfy one or more individual financial or nonfinancial objectives set by the Committee for that Executive Employee as of the beginning of the relevant fiscal year. Any such objectives for an Executive Employee shall be set by the Committee and announced to the affected Executive Employee no later than 90 days after the commencement of the relevant fiscal year of NU.

(c) The Committee shall certify and announce the Awards that will be paid by the Company to each Executive Employee as soon as practicable following the final determination of the Company’s financial results for the relevant fiscal year. Payment of Awards that an Executive Employee has not expressly deferred pursuant to Section 3 below shall be made in cash, or in shares of Company Stock or Options, the value of which shall equal the amount to be distributed, all as determined by the Committee, after the end of the relevant fiscal year but not later than two and one-half months after the end of such fiscal year, provided that the Executive Employee has not separated from employment by the Company prior to the date that payment is due except as otherwise specifically provided in a contract between the Company and the Executive Employee. The Committee may provide for complete or partial exceptions to this requirement if an Executive Employee’s employment terminated on account of Retirement, termination without Cause, death, Disability or a Change of Control.

3. Deferral of Annual Awards. The Committee may permit an Executive Employee to defer an Award in accordance with such procedures as the Committee may from time to time specify subject to the limitations set forth in Section 3 of Article XIII of this Plan.

ARTICLE IV

STOCK-BASED GRANTS

1. Grants. Grants under the Plan may consist of grants of incentive stock options (“Incentive Stock Options”) or nonqualified stock options (“Nonqualified Stock Options”)(Incentive Stock Options and Nonqualified Stock Options are collectively referred to as “Options”), restricted stock (“Restricted Stock”), restricted share units (Restricted Share Units” or “RSUs”), stock appreciation rights (“SARs”), and/or performance units (“Performance Units”) (hereinafter collectively referred to as “Grants”). Grants may be awarded singly, in combination or in tandem with other Grants. All Grants shall be subject to the terms and conditions set forth herein and to such other terms and conditions consistent with this Plan as the Committee deems appropriate and as are specified in writing by the Committee in program documents applicable to particular years and/or Grants and in individual grant instruments or amendments to the same (each a “Grant Instrument”). The Committee shall approve the form and provisions of each Grant Instrument. Grants under a particular Section of the Plan need not be uniform as among the Grantees, as defined below.

2. Eligibility for Participation.

(a) Eligible Persons. All employees of the Company (“Employees”), including Employees who are officers or members of the Board, contractors of the Company (“Contractors”), and members of the Board who are not Employees (“Non-Employee Trustees”) shall be eligible to receive Grants under the Plan. Contractors shall be eligible to receive Grants only of Nonqualified Stock Options.

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(b) Selection of Grantees. The Committee shall select the Employees and Contractors to receive Grants and shall determine the number of shares of Company Stock subject to a particular Grant in such manner as the Committee determines. Employees, Contractors and Non-Employee Trustees who receive Grants under this Plan shall hereinafter be referred to as “Grantees”.

(c) Collective Bargaining Employees. Anything to the contrary in this Plan notwithstanding, no Employee whose terms and conditions of employment are subject to negotiation with a collective bargaining agent shall be eligible to receive Grants under this Plan until the agreement between the Company and such collective bargaining agent with respect to the Employee provides for participation in the Plan.

3. Granting of Options.

(a) Number of Shares. The Committee shall determine the number of shares of Company Stock that will be subject to each Grant of Options to Employees and Contractors subject to the overall limits of Article IX.

(b) Type of Option and Price.

(i) The Committee may grant Incentive Stock Options that are intended to qualify as “incentive stock options” within the meaning of section 422 of the Code or Nonqualified Stock Options that are not intended so to qualify or any combination of Incentive Stock Options and Nonqualified Stock Options, all in accordance with the terms and conditions set forth herein. Incentive Stock Options may be granted only to Employees. Nonqualified Stock Options may be granted to Employees, Contractors and Non-Employee Trustees.

(ii) The purchase price (the “Exercise Price”) of Company Stock subject to an Option shall be determined by the Committee and shall be equal to or greater than the Fair Market Value (as defined below) of a share of Company Stock on the date the Option is granted; provided, however, that an Incentive Stock Option may not be granted to an Employee who, at the time of grant, owns stock possessing more than 10 percent of the total combined voting power of all classes of stock of the Company or any parent or subsidiary of the Company, unless the Exercise Price per share is not less than 110% of the Fair Market Value of Company Stock on the date of grant. The Committee may not modify the applicable Exercise Price after the date of Grant.

(iii) If the Company Stock is publicly traded, then the Fair Market Value per share shall be the closing price of the Company Stock as reported in the Wall Street Journal as composite transactions for the relevant date (or the latest date for which such price was reported if such date is not a business day), or if not available, determined as follows: (A) if the principal trading market for the Company Stock is the New York Stock Exchange, the last reported sale price thereof on the relevant date or (if there were no trades on that date) the latest preceding date upon which a sale was reported, (B) if the principal trading market for the Company Stock is a national securities exchange other than the New York Stock Exchange or is the NASDAQ National Market, the last reported sale price thereof on the relevant date or (if there were no trades on that date) the latest preceding date upon which a sale was reported, or (C) if the Company Stock is not principally traded on such exchange or market, the mean between the last reported “bid” and “asked” prices of Company Stock on the relevant date, as reported on NASDAQ or, if not so reported, as reported by the National Daily Quotation Bureau, Inc. or as reported in a customary financial reporting service, as applicable and as the Committee determines. If the Company Stock is not publicly traded or, if publicly traded, is not subject to reported transactions or “bid” or “asked” quotations as set forth above, the Fair Market Value per share shall be as determined by the Committee in accordance with the requirements of Section 1.409A-1(b)(5)(iv)(B) of the Treasury Regulations.

(c) Option Term. The Committee shall determine the term of each Option. The term of any Option shall not exceed ten years from the date of grant. However, an Incentive Stock Option that is granted to an Employee who, at the time of grant, owns stock possessing more than 10 percent of the total combined voting power of all classes of stock of the Company, or any parent or subsidiary of the Company, may not have a term that exceeds five years from the date of grant.

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(d) Exercisability of Options. Options shall become exercisable in accordance with such terms and conditions, consistent with the Plan, as may be determined by the Committee and specified in the Grant Instrument. The Committee may accelerate the exercisability of any or all outstanding Options at any time for any reason.

(e) Termination of Employment, Retirement, Disability or Death.

(i) Except as provided below, an Option may be exercised only while the Grantee is employed by, or providing service to, the Company as an Employee, a Contractor, or a member of the Board. In the event that a Grantee ceases to be employed by, or provide service to, the Company then, unless the Committee deems otherwise, all outstanding Options will expire upon termination from employment or service with the Board for Cause, or any other reason, including termination on account of “Retirement,” “Disability,” or death.

(ii) For purposes of this Plan and programs thereunder:

(A) “Cause” shall mean, except to the extent specified otherwise by the Committee acting on behalf of the Company, (x) the Grantee’s conviction of a felony, (y) in the reasonable determination of the Committee, the Grantee’s (I) commission of an act of fraud, embezzlement, or theft in connection with the Grantee’s duties in the course of the Grantee’s employment with the Company, (II) acts or omissions causing intentional, wrongful damage to the property of the Company or intentional and wrongful disclosure of confidential information of the Company, or (III) engaging in gross misconduct or gross negligence in the course of the Grantee’s employment with the Company, or (z) the Grantee’s material breach of his or her obligations under any written agreement with the Company if such breach shall not have been remedied within 30 days after receiving written notice from the Committee specifying the details thereof. For purposes of this Program, an act or omission on the part of a Grantee shall be deemed “intentional” only if it was not due primarily to an error in judgment or negligence and was done by Grantee not in good faith and without reasonable belief that the act or omission was in the best interest of the Company. In the event a Grantee’s employment or service is terminated for cause, in addition to the immediate termination of all Grants, the Grantee shall automatically forfeit all shares underlying any exercised portion of an Option for which the Company has not yet delivered the share certificates, upon refund by the Company of the Exercise Price paid by the Grantee for such shares.

(B) “Disability” shall mean a Grantee’s being determined to be disabled within the meaning of the long-term disability plan or program that is a part of the Northeast Utilities Service Company Flexible Benefits Plan (or any successor plan or program, hereafter, the “LTD Program”).

(C) “Employed by, or provide service to, the Company” shall mean employment or service as an Employee, Contractor or member of the Board (so that, for purposes of exercising Options and SARs and satisfying conditions with respect to Restricted Stock, RSUs and Performance Units, a Grantee shall not be considered to have terminated employment or service until the Grantee ceases to be an Employee, Contractor and member of the Board), unless the Committee determines otherwise.

(D) “Retired” shall mean a termination of employment from the Company, other than for “Cause” on or after the earlier to occur of (x) attainment of age 65, (y) eligibility for pension payments under the Supplemental Executive Retirement Plan for Officers of Northeast Utilities System Companies, or employment-related agreement with the Company, or (z) attainment of age 55 after completing at least ten years of vesting service under the Northeast Utilities Service Company 401k Plan.

(f) Exercise of Options. A Grantee may exercise an Option that has become exercisable, in whole or in part, by delivering a notice of exercise to the Company with payment of the Exercise Price. The Grantee shall pay the Exercise Price for an Option as specified by the Committee:

(i) in cash,

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(ii) with the approval of the Committee, by delivering shares of Company Stock owned by the Grantee (including Company Stock acquired in connection with the exercise of an Option or Restricted Stock, as defined below, granted under this Plan, subject to such restrictions as the Committee deems appropriate including placing the same restrictions on the shares of Company Stock obtained through the exchange of the Restricted Stock) and having a Fair Market Value on the date of exercise equal to the Exercise Price, or

(iii) by such other method as the Committee may approve, including payment through a broker in accordance with procedures permitted by Regulation T of the Federal Reserve Board. The Grantee shall pay the Exercise Price and the amount of any withholding tax due at the time of exercise.

(g) Limits on Incentive Stock Options. Each Incentive Stock Option shall provide that, if the aggregate Fair Market Value of the stock on the date of the grant with respect to which Incentive Stock Options are exercisable for the first time by a Grantee during any calendar year, under the Plan or any other stock option plan of the Company exceeds $100,000, then the option, as to the excess, shall be treated as a Nonqualified Stock Option. An Incentive Stock Option shall not be granted to any person who is not an Employee of the Company.

ARTICLE V

STOCK-BASED GRANTS TO NON-EMPLOYEE TRUSTEES

1. Eligibility for Participation. Non-Employee Trustees shall be eligible to receive Grants as set forth in Article IV; provided, that the number of shares of Company Stock subject to each Grant of Options, as well as the terms of all Grants, to Non-Employee Trustees shall be approved by the Board, in accordance with Article (9) of the Declaration of Trust of Northeast Utilities, as amended.

2. Terms of Retirement. The words “age 65” in the definition of “Retired” in Section 3(e)(ii)(D) of Article IV shall be read as “age 70” with respect to Non-Employee Trustees.

ARTICLE VI

RESTRICTED STOCK AND RESTRICTED SHARE UNIT GRANTS

1. Restricted Stock Grants. Subject to the terms and conditions of the Plan, the Committee may issue or transfer shares of Company Stock to a Grantee with such restrictions as the Committee deems appropriate (“Restricted Stock”). The following provisions are applicable to Restricted Stock:

(a) General Requirements. Shares of Company Stock issued or transferred pursuant to Restricted Stock Grants may be issued or transferred in exchange for services performed or to be performed. The Committee may establish conditions under which restrictions on shares of Restricted Stock shall lapse over a period of time or according to such other criteria as the Committee deems appropriate. The period of time during which the Restricted Stock will remain subject to restrictions (the “Restriction Period”) will be designated in the Grant Instrument

(b) Number of Shares. The Committee shall determine the number of shares of Company Stock to be issued or transferred pursuant to a Restricted Stock Grant and the restrictions applicable to such shares, subject to the limitations contained in Article IX.

(c) Requirement of Employment or Service. If the Grantee ceases to be employed by, or provide service to, the Company during the Restriction Period, or if other specified conditions are not met, the Restricted Stock Grant shall terminate as to all shares covered by the Grant as to which the restrictions have not lapsed, and those shares of Company Stock must be immediately returned to the Company. The Committee may, however, provide for complete or partial exceptions to this requirement as it deems appropriate.

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(d) Restrictions on Transfer and Legend on Share Certificate. During the Restriction Period, a Grantee may not sell, assign, transfer, pledge or otherwise dispose of the shares of Restricted Stock except to a Successor Grantee, as defined below. The Committee may determine that the Company will issue certificates for shares of Restricted Stock, in which case each certificate for a share of Restricted Stock shall contain a legend giving appropriate notice of the restrictions in the Grant. The Grantee shall be entitled to have the legend removed from the share certificate covering the shares subject to restrictions when all restrictions on such shares have lapsed. The Committee may determine that the Company will not issue certificates for shares of Restricted Stock until all restrictions on such shares have lapsed, or that the Company will retain possession of certificates for shares of Restricted Stock until all restrictions on such shares have lapsed.

(e) Right to Vote and to Receive Dividends. Unless the Committee determines otherwise, the Grantee shall have the right to vote Restricted Stock and to receive any dividends or other distributions paid on such shares during the Restriction Period subject to any restrictions deemed appropriate by the Committee.

(f) Lapse of Restrictions. All restrictions imposed on Restricted Stock shall lapse upon the expiration of the applicable Restriction Period and the satisfaction of all conditions imposed by the Committee. The Committee may determine, as to any or all Restricted Stock Grants, that the restrictions shall lapse without regard to any Restriction Period.

2. Restricted Share Unit Grants.

(a) Restriction Period. The Committee may make Grants of Restricted Share Units to Employees and Non-Employee Trustees representing the right to receive shares of Company Stock, cash, or both, as determined by the Committee (hereafter, “Restricted Share Units”). Between the end of the Restriction Period and the second payroll date following the end of the Restriction Period, subject to any deferral election that may be made or applied to the Grant pursuant to subsection (e) below and further subject to the limitations set forth in Section 3 of Article XIII of this Plan with respect to a Grant of Restricted Share Units that is subject to Section 409A of the Code, cash or shares or both shall be delivered to the Grantee (unless previously forfeited). Restricted Share Units may not be sold, assigned, transferred, pledged or otherwise encumbered during the Restriction Period. A Grantee of Restricted Share Units shall have none of the rights of a holder of Company Stock unless and until shares of Company Stock are actually delivered in satisfaction of such Restricted Share Units.

(b) Number of Units. The Committee shall determine the number of Restricted Share Units pursuant to a Restricted Share Unit Grant and the restrictions applicable to such shares, subject to the limitations contained in Article IX.

(c) Requirement of Employment or Service. If the Grantee ceases to be employed by, or provide service to, the Company during a period designated in the Grant Instrument as the Restriction Period, or if other specified conditions are not met, the Restricted Share Unit Grant shall terminate as to all Restricted Share Units covered by the Grant as to which the restrictions have not lapsed. The Committee may, however, provide in the Grant Instrument for complete or partial exceptions to this requirement if an Employee’s employment or Non-Employee Trustee’s service with the Board ends on account of Retirement, termination without Cause, death or Disability or due to a Change of Control, as it deems appropriate subject to the limitations set forth in Section 3 of Article XIII of this Plan.

(d) Dividend Equivalents. The Committee may determine that a Grant Instrument with respect to Restricted Share Units may provide that the Grantee shall be entitled to receive as compensation from the Company dividend equivalents with respect thereto, in the form determined by the Committee from the effective date of the Grant Instrument through the earlier of (i) the date the Restricted Share Unit is forfeited, and (ii) the date Company Stock representing such Restricted Share Units or cash is delivered to the Grantee as provided herein.

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(e) Deferrals of Restricted Share Units. The Committee may provide in the Grant Instrument for the automatic deferral of the payment of Restricted Share Units upon the lapse of restrictions on the Grant or permit a Grantee to elect deferral by filing a written election with the Committee in accordance with such procedures as the Committee may from time to time specify, subject to the limitations set forth in Section 3 of Article XIII of this Plan.

3. Withholding. The Company shall have the right to deduct from any settlement of a Grant of Restricted Shares or Restricted Share Units, including the delivery or vesting of shares or dividend equivalents, an amount sufficient to cover withholding required by law for any federal, state or local taxes or to take such other action as may be necessary to satisfy any withholding obligations. The Committee may permit shares to be used to satisfy required tax withholding, and such shares shall be valued at the fair market value as of the settlement date of the applicable Grant.

4. Section 162(m). Notwithstanding any other provision of the Plan or the terms of any Grant or Award issued hereunder, Grants of Restricted Stock or Restricted Share Units under this Article VI are not intended to be or meet the requirements for “qualified performance based compensation” under Section 162(m) of the Code or Treasury Regulation § 1.162-27(e).

ARTICLE VII

STOCK APPRECIATION RIGHTS

1. Stock Appreciation Rights.

(a) General Requirements. The Committee may grant stock appreciation rights (“SARs”) to a Grantee separately or in tandem with any Option (for all or a portion of the applicable Option). Tandem SARs may be granted either at the time the Option is granted or at any time thereafter while the Option remains outstanding; provided, however, that, in the case of an Incentive Stock Option, SARs may be granted only at the time of the Grant of the Incentive Stock Option. The Committee shall establish the base amount of the SAR at the time the SAR is granted. The base amount of each SAR shall be equal to the per share Exercise Price of the related Option or, if there is no related Option, the Fair Market Value of a share of Company Stock as of the date of Grant of the SAR (“Base Amount”). The Committee may not modify the applicable Base Amount of the SAR after the date of Grant.

(b) Tandem SARs. In the case of tandem SARs, the number of SARs granted to a Grantee that shall be exercisable during a specified period shall not exceed the number of shares of Company Stock that the Grantee may purchase upon the exercise of the related Option during such period. Upon the exercise of an Option, the SARs relating to the Company Stock covered by such Option shall terminate. Upon the exercise of SARs, the related Option shall terminate to the extent of an equal number of shares of Company Stock.

(c) Exercisability. An SAR shall be exercisable during the period specified by the Committee in the Grant Instrument and shall be subject to such vesting and other restrictions as may be specified in the Grant Instrument. SARs may only be exercised while the Grantee is employed by the Company or during the applicable period after termination of employment as described in Article IV, Section 3(e). A tandem SAR shall be exercisable only during the period when the Option to which it is related is also exercisable.

(d) Value of SARs. When a Grantee exercises SARs, the Grantee shall receive in settlement of such SARs an amount equal to the “spread value” for the number of SARs exercised, payable in cash. The “spread value” for an SAR is the amount representing the difference by which the Fair Market Value of the underlying Company Stock on the date of exercise of the SAR exceeds the base amount of the SAR as described in Subsection (a).

(e) Form of Payment. For purposes of calculating the amount of cash to be received, shares of Company Stock shall be valued at their Fair Market Value on the date of exercise of the SAR and cash shall be distributed, net of applicable withholding taxes.

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ARTICLE VIII

PERFORMANCE UNITS

1. Performance Units.

(a) General Requirements. The Committee may grant performance units (“Performance Units”) to an Employee. Each Performance Unit shall represent the right of the Grantee to receive an amount based on the value of the Performance Unit, if performance goals established by the Committee are met. A Performance Unit shall be based on the Fair Market Value of a share of Company Stock or on such other measurement base as the Committee deems appropriate. The Committee shall determine the number of Performance Units to be granted and the requirements applicable to such Units, subject to the limitations contained in Article IX.

(b) Performance Period and Performance Goals. When Performance Units are granted, the Committee shall establish the Performance Period during which performance shall be measured, Performance Goals applicable to the Units and such other conditions of the Grant as the Committee deems appropriate. Performance Goals may relate to the financial performance of the Company or its operating units, the performance of Company Stock, individual performance, or such other criteria as the Committee deems appropriate.

(c) Payment with respect to Performance Units. At the end of each Performance Period, the Committee shall determine to what extent the Performance Goals and other conditions of the Performance Units are met and the amount, if any, to be paid with respect to the Performance Units. Payments with respect to Performance Units shall be made in cash, in Company Stock, or in a combination of the two, as determined by the Committee after the end of the relevant Performance Period but not later than two and one-half months after the end of such Performance Period subject to any deferral election that may be made or applied to the Grant pursuant to subsection (e) below and further subject to the limitations set forth in Section 3 of Article XIII of this Plan with respect to a Grant of Performance Units that is subject to Section 409A of the Code.

(d) Requirement of Employment or Service. If the Grantee ceases to be employed by, or provide service to, the Company (as defined in Article IV, Section 3(e)) during a Performance Period, or if other conditions established by the Committee are not met, the Grantee’s Performance Units shall be forfeited. The Committee may, however, provide in the Grant Instrument for complete or partial exceptions to this requirement if an Employee’s employment ends on account of Retirement, termination without Cause, death or Disability or due to a Change of Control, as it deems appropriate subject to the limitations set forth in Section 3 of Article XIII of this Plan.

(e) Deferrals of Performance Units. The Committee may provide in the Grant Instrument for the automatic deferral of the payment of Performance Units at the end of the Performance Period or permit a Grantee to elect deferral by filing a written election with the Committee in accordance with such procedures as the Committee may from time to time specify subject to the limitations set forth in Section 3 of Article XIII of this Plan.

(f) Designation as Qualified Performance-Based Compensation. The Committee may determine that Performance Units granted to a Grantee shall be considered “qualified performance-based compensation” under Section 162(m) of the Code. The provisions of this subsection (e) shall apply to Grants of Performance Units that are to be considered “qualified performance-based compensation” under Section 162(m) of the Code.

(i) Performance Goals. When Performance Units that are to be considered “qualified performance-based compensation” are Granted, the Committee shall establish in writing (A) the objective Performance Goals that must be met in order for amounts to be paid under the Performance Units, (B) the Performance Period during which the performance goals must be met, (C) the threshold, target and maximum amounts that may be paid if the Performance Goals are met, and (D) any other conditions, including without limitation provisions relating to

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death, disability, other termination of employment or Change of Control, that the Committee deems appropriate and consistent with the Plan and Section 162(m) of the Code. The performance goals may relate to the Employee’s business unit or the performance of the Company and its subsidiaries as a whole, or any combination of the foregoing.

(ii) Establishment of Goals. The Committee shall establish the Performance Goals in writing either before the beginning of the Performance Period or during a period ending no later than the earlier of (A) 90 days after the beginning of the Performance Period or (B) the date on which 25% of the Performance Period has been completed, or such other date as may be required or permitted under applicable regulations under Section 162(m) of the Code. The performance goals shall satisfy the requirements for “qualified performance-based compensation,” including the requirement that the achievement of the goals be substantially uncertain at the time they are established and that the goals be established in such a way that a third party with knowledge of the relevant facts could determine whether and to what extent the performance goals have been met. The Committee shall not have discretion to increase the amount of compensation that is payable upon achievement of the designated performance goals.

(iii) Maximum Payment. The number of Performance Units granted and paid in shares shall not exceed the limit specified under Article IX(1)(a). If Performance Units are paid in cash, the maximum amount that may be paid to an Employee with respect to a Performance Period is $4,000,000.

(iv) Announcement of Grants. The Committee shall certify and announce the results for each Performance Period to all Grantees immediately following the announcement of the Company’s financial results for the Performance Period. If and to the extent that the Committee does not so certify that the performance goals have been met, the grants of Performance Units for the Performance Period shall be forfeited.

ARTICLE IX

AUTHORIZED SHARES

1. Shares Subject to the Plan.

(a) Shares Reserved for Grants and Awards. The aggregate number of common shares of NU, par value $5.00, (“Company Stock”) that may be subject to Grants of Options, or transferred on account of other Grants or Awards under the Plan may not exceed 4.5 million shares. The shares may be authorized but unissued shares of Company Stock or reacquired shares of Company Stock, including shares purchased by the Company on the open market for purposes of the Plan. If and to the extent (i) Options or SARs granted under the Plan terminate, expire, or are canceled, forfeited, exchanged or surrendered without having been exercised (other than for reasons of the Exercise Price of the Option being less than the current Fair Market Value thereof), or (ii) any shares of Restricted Stock, RSUs or Performance Units are forfeited, or (iii) Company Stock, including RSUs, are used by the Participant to pay withholding taxes or as payment for the Exercise Price of the Grant, then the shares not made the subject of Grants and Awards, and the shares subject to such terminated, expired, canceled, forfeited, exchanged or surrendered Grants and Awards shall again be available for purposes of the Plan in addition to the number of shares of Company Stock otherwise available for Grants and Awards. No Participant under the Plan may receive aggregate Grants and Awards in excess of one million shares over the term of the Plan.

(b) Adjustments. If there is any change in the number or kind of shares of Company Stock outstanding (i) by reason of a stock dividend, spinoff, recapitalization, stock split, or combination or exchange of shares, (ii) by reason of a merger, reorganization or consolidation in which NU is the surviving entity, (iii) by reason of a reclassification or change in par value, or (iv) by reason of any other extraordinary or unusual event affecting the outstanding Company Stock as a class without NU’s receipt of consideration, or (v) otherwise in the event of an equity restructuring within the meaning of Statement of Financial Accounting Standards No. 123 (revised 2004),

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other than (A) any distribution of securities or other property by the Company to shareholders in a spin-off or split-off that does not qualify as a tax-free spin-off or split-up under Section 355 of the Code (or any successor provision of the Code) or (B) any cash dividend (other than an extraordinary cash dividend or distribution), then the maximum number of shares of Company Stock available for Grants, the number of shares covered by outstanding Grants, the kind of shares issued under the Plan, and the price per share or the applicable market value of such Grants, including the per share exercise price of Options and Stock Appreciation Rights, shall be appropriately adjusted by the Committee to reflect any increase or decrease in the number of, or change in the kind or value of, issued shares of Company Stock to preclude, to the extent practicable, the enlargement or dilution of rights and benefits under such Grants; provided, however, that any fractional shares resulting from such adjustment shall be eliminated and, provided further, that any substitution of a new stock right or assumption of an outstanding stock right pursuant to a corporate transaction shall comply with the requirements of Section 1.409A-1(b)(5)(v)(D) of the Treasury Regulations and any adjustment of a stock right to reflect a stock split or stock dividend shall comply with the requirements of Section 1.409A-1(b)(5)(v)(H) of the Treasury Regulations. Any increase to the number or kind of shares of Company Stock outstanding under this Article IX(1)(b) occurring on or after May 9, 2007 shall result in the adjustment in the 4.5 million shares authorized under Article IX(1)(a). No such adjustment shall be required to reflect the events described in clauses (x) and (y) above, or any other change in capitalization that does not constitute an equity restructuring; however, such adjustment may be made if the Committee determines that such adjustment is appropriate; provided, however, that any such adjustment shall comply with the requirements of Section 1.409A-1(b)(5)(v) of the Treasury Regulations. Any adjustments determined by the Committee shall be final, binding and conclusive.

(c) Minimum Vesting Requirement. Grants of Restricted Stock or RSUs made pursuant to the Plan shall vest ratably no sooner than the first business day of each of the three years following the calendar year of the Grant. Grants of Options shall vest no sooner than the first business day of the year following the calendar year of the Grant. The Committee may, in its discretion, determine such other vesting schedule as it deems appropriate, except that any such other vesting schedule must fulfill at least the applicable minimum requirements set forth in the prior two sentences. The Committee may provide in the Grant Instrument for complete or partial exceptions to these requirements as it deems appropriate in the case of a Participant whose service with the Company ends for reason of Retirement, Death, or Disability, or in the case of a Grant to a Non-Employee Trustee or a newly-hired Employee, or upon a Change of Control of NU subject to the limitations set forth in Section 3 of Article XIII of this Plan.

ARTICLE X

OPERATING RULES

1. Withholding of Taxes. All Grants under the Plan shall be subject to applicable federal (including FICA), state and local tax withholding requirements. The Company shall have the right to deduct from all Grants paid in cash, or from other wages paid to the Grantee, any federal, state or local taxes required by law to be withheld with respect to such Grants. In the case of Options and other Grants paid in Company Stock, the Company may require the Grantee or other person receiving such shares to pay to the Company the amount of any such taxes that the Company is required to withhold with respect to such Grants, or the Company may deduct from other wages paid by the Company the amount of any withholding taxes due with respect to such Grants. If the Committee so permits, a Grantee may elect to satisfy the Company’s income tax withholding obligation with respect to an Option, SAR, Restricted Stock, Restricted Share Units or Performance Units that are paid in Company Stock, by having shares withheld up to an amount that does not exceed the Grantee’s minimum applicable withholding tax rate for federal (including FICA), state and local tax liabilities. The election must be in a form and manner prescribed by the Committee.

2. Transferability of Grants.

(a) Nontransferability of Grants. Except as provided below, only the Grantee may exercise rights under a Grant during the Grantee’s lifetime. A Grantee may not transfer those rights except by will or by the laws of

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descent and distribution or, with respect to Grants other than Incentive Stock Options, if permitted in any specific case by the Committee, pursuant to a domestic relations order (as defined under the Code or Title I of the Employee Retirement Income Security Act of 1974, as amended, or the regulations thereunder). When a Grantee dies, the personal representative or other person entitled to succeed to the rights of the Grantee (“Successor Grantee”) may exercise such rights. A Successor Grantee must furnish proof satisfactory to the Company of his or her right to receive the Grant under the Grantee’s will or under the applicable laws of descent and distribution.

(b) Transfer of Nonqualified Stock Options. Notwithstanding the foregoing, the Committee may provide, in a Grant Instrument, that a Grantee may transfer Nonqualified Stock Options to family members, one or more trusts for the benefit of family members, or one or more partnerships of which family members are the only partners, according to such terms as the Committee may determine; provided that the Grantee receives no consideration for the transfer of an Option and the transferred Option shall continue to be subject to the same terms and conditions as were applicable to the Option immediately before the transfer.

3. Requirements for Issuance or Transfer of Shares. No Company Stock shall be issued or transferred in connection with any Grant hereunder unless and until all legal requirements applicable to the issuance or transfer of such Company Stock have been complied with to the satisfaction of the Committee. The Committee shall have the right to condition any Grant made to any Grantee hereunder on such Grantee’s undertaking in writing to comply with such restrictions on his or her subsequent disposition of such shares of Company Stock as the Committee shall deem necessary or advisable as a result of any applicable law, regulation or official interpretation thereof, and certificates representing such shares may be legended to reflect any such restrictions. Certificates representing shares of Company Stock issued or transferred under the Plan will be subject to such stop-transfer orders and other restrictions as may be required by applicable laws, regulations and interpretations, including any requirement that a legend be placed thereon.

4. Funding of the Plan. This Plan shall be unfunded. The Company shall not be required to establish any special or separate fund or to make any other segregation of assets to assure the payment of any Grants under this Plan. In no event shall interest be paid or accrued on any Grant, including unpaid installments of Grants.

5. Rights of Participants. Nothing in this Plan shall entitle any Employee or Non-Employee Trustee or other person to any claim or right to be granted a Grant under this Plan except as provided in Article V. Neither this Plan nor any action taken hereunder shall be construed as giving any individual any rights to be retained by or in the employ of the Company or any other employment rights, nor shall they interfere in any way with the right of the Company, a subsidiary or an affiliate to terminate the employment of any Employee at any time.

6. Headings. Section headings are for reference only. In the event of a conflict between a title and the content of a Section, the content of the Section shall control.

7. Effective Date of the Plan. Subject to approval by NU’s shareholders, if required, the Plan as amended and restated, is effective on January 1, 2009.

8. Definition of Company. “Company” means NU and any Affiliate which is authorized by the Board to adopt the Plan and cover its eligible employees and whose designation as such has become effective upon acceptance of such status by the board of directors of the Affiliate. An Affiliate may revoke its acceptance of such designation at any time, but until such acceptance has been revoked, all the provisions of the Plan, including the authority of the Board and the Committee, and amendments thereto shall apply to the eligible employees of the Affiliate. In the event the designation is revoked by the board of directors of an Affiliate, the Plan shall be deemed terminated only with respect to such Affiliate. For the purposes hereof, “Affiliate” means each direct and indirect affiliated company that directly or through one or more intermediaries, controls, is controlled by, or is under common control with NU.

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ARTICLE XI

CHANGE OF CONTROL OF NU

1. Change of Control of NU.

As used herein, a “Change of Control” shall mean a change in ownership or control effected through any one or more of the following:

(a) When any “person,” as such term is used in Sections 13(d) and 14(d) of the Securities Exchange Act of 1934 (the “Exchange Act”), other than the Company, its affiliates, or any Company or NU employee benefit plan (including any trustee of such plan acting as trustee), is or becomes the “beneficial owner” (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of securities of NU representing more than 20% of the combined voting power of either (i) the then outstanding common shares of NU (the “Outstanding Common Shares”) or (ii) the then outstanding voting securities of NU entitled to vote generally in the election of directors (the “Voting Securities”); or

(b) Individuals who, as of the beginning of any twenty-four month period, constitute the Trustees (the “Incumbent Trustees”) cease for any reason to constitute at least a majority of the Trustees or cease to be able to exercise the powers of the majority of the Trustees, provided that any individual becoming a trustee subsequent to the beginning of such period whose election or nomination for election by the Company’s stockholders was approved by a vote of at least a majority of the trustees then comprising the Incumbent Trustees shall be considered as though such individual were a member of the Incumbent Trustees, but excluding, for this purpose, any such individual whose initial assumption of office is in connection with an actual or threatened election contest relating to the election of the Trustees of NU (as such terms are used in Rule 14a-11 of Regulation 14A promulgated under the Exchange Act); or

(c) Consummation by NU of a reorganization, merger or consolidation (a “Business Combination”), in each case, with respect to which all or substantially all of the individuals and entities who were the respective beneficial owners of the Outstanding Common Shares and Voting Securities immediately prior to such Business Combination do not, following consummation of all transactions intended to constitute part of such Business Combination, beneficially own, directly or indirectly, more than 75% of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation, business trust or other entity resulting from or being the surviving entity in such Business Combination in substantially the same proportion as their ownership immediately prior to such Business Combination of the Outstanding Common Shares and Voting Securities, as the case may be; or

(d) Consummation of a complete liquidation or dissolution of NU or sale or other disposition of all or substantially all of the assets of NU other than to a corporation, business trust or other entity with respect to which, following consummation of all transactions intended to constitute part of such sale or disposition, more than 75% of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors, as the case may be, is then owned beneficially, directly or indirectly, by all or substantially all of the individuals and entities who were the beneficial owners, respectively, of the Outstanding Common Shares and Voting Securities immediately prior to such sale or disposition in substantially the same proportion as their ownership of the Outstanding Common Shares and Voting Securities, as the case may be, immediately prior to such sale or disposition.

2. Consequences of a Change of Control.

(a) Notice. Upon a Change of Control, the Company shall provide each Grantee with outstanding Grants written notice of such Change of Control.

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(b) Assumption of Grants. Upon a Change of Control where the Company is not the surviving corporation (or survives only as a subsidiary of another corporation), unless the Committee determines otherwise, all outstanding Options and SARs that are not exercised and all outstanding restricted shares, restricted share units and Performance Units that are denominated in shares of Company Stock shall be assumed by, or replaced with comparable options, rights or entitlements by, the surviving corporation, subject to compliance with Section 1.409A-1(b)(5)(v) of the Treasury Regulations.

(c) Other Alternatives. Notwithstanding the foregoing, subject to subsection (d) below and compliance with Section 1.409A-1(b)(5)(v) of the Treasury Regulations, in the event of a Change of Control, the Committee may provide in annual program documents that, notwithstanding any deferral election or deferral provision, take any of the following actions: (i) eliminate all risk of forfeiture remaining on any Options, SARs, restricted shares, restricted share units and Performance Units outstanding at the time of a Change of Control; (ii) require that Grantees surrender their outstanding Options, SARs, restricted shares, restricted share units and Performance Units that are denominated in shares of Company Stock in exchange for a payment by the Company, in cash or Company Stock as determined by the Committee, in an amount equal to the restricted shares, restricted share units or Performance Units (based on the then Fair Market Value of shares of Company Stock) (except that a distribution of any award that is a 409A Award may only be made, other than on Termination, upon a change of control that qualifies as a “change in control” under Section 1.409A -3(i)(5) of the Treasury Regulations), or with respect to unexercised Options or SARs, in the amount by which the then Fair Market Value of the shares of Company Stock subject to the Grantee’s unexercised Options and SARs exceeds the Exercise Price of the Options or the base amount of the SARs, as applicable, or (iii) after giving Grantees an opportunity to exercise their outstanding Options and SARs, terminate any or all unexercised Options and SARs at such time as the Committee deems appropriate. Such surrender or termination shall take place as of the date of the Change of Control or such other date as the Committee may specify.

(d) Committee. The Committee making the determinations under this Article XI, Section 2(d) following a Change of Control must comprise the same members as those on the Committee immediately before the Change of Control. If the Committee members do not meet this requirement, the automatic provisions of Subsections (a) and (b) shall apply, and the Committee shall not have discretion to vary them.

(e) Limitations. Notwithstanding anything in the Plan to the contrary, in the event of a Change of Control, the Committee shall not have the right to take any actions described in the Plan (including without limitation actions described in Subsection (c) above) that would make the Change of Control ineligible for pooling of interests accounting treatment or that would make the Change of Control ineligible for desired tax treatment if, in the absence of such right, the Change of Control would qualify for such treatment and the Company intends to use such treatment with respect to the Change of Control.

ARTICLE XII

AMENDMENT AND TERMINATION

1. Amendment and Termination of the Plan.

(a) Amendment. Subject to the limitations set forth in Section 3 of Article XIII of this Plan, the Board or the Committee may amend or terminate the Plan at any time; provided, however, that neither the Board nor the Committee shall amend the Plan without shareholder approval if such approval is required by Sections 162(m) or 422 of the Code.

(b) Termination of the Plan. The Plan shall terminate on the day preceding the tenth anniversary of its effective date, unless the Plan is terminated earlier by the Board or the Committee in accordance with Subsection (a) above, or is extended by the Board or the Committee with the approval of the shareholders.

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(c) Termination and Amendment of Outstanding Grants. A termination or amendment of the Plan that occurs after a Grant is made shall not materially impair the rights of a Grantee unless the Grantee consents, unless the Committee acts under Article XI, Section 2(c), or unless the amendment or termination is required under statute, regulation, other law, or rule of a governing or administrative body having the effect of a statute or regulation or unless such an amendment is necessary to bring a Grant into compliance with, or obtain an exemption from, the requirements of Section 409A of the Code. The termination of the Plan shall not impair the power and authority of the Committee with respect to an outstanding Grant.

(d) Governing Document. The Plan shall be the controlling document. No other statements, representations, explanatory materials or examples, oral or written, may amend the Plan in any manner. The Plan shall be binding upon and enforceable against the Company and its successors and assigns.

ARTICLE XIII

MISCELLANEOUS

1. Grants in Connection with Corporate Transactions and Otherwise. Nothing contained in this Plan shall be construed to (a) limit the right of the Committee to make Grants under this Plan in connection with the acquisition, by purchase, lease, merger, consolidation or otherwise, of the business or assets of any corporation, firm or association, including Grants to employees thereof who become Employees of the Company, or for other proper corporate purposes, or (b) limit the right of the Company to grant stock options or make other awards outside of this Plan. Without limiting the foregoing, the Committee may make a Grant to an employee of another corporation who becomes an Employee by reason of a corporate merger, consolidation, acquisition of stock or property, reorganization or liquidation involving the Company or any of its subsidiaries in substitution for a stock option or restricted stock grant made by such corporation. The terms and conditions of the substitute grants may vary from the terms and conditions required by the Plan and from those of the substituted stock incentives. The Committee shall prescribe the provisions of the substitute grants.

2. Compliance with Law. The Plan, the exercise of Options and SARs and the obligations of the Company to issue or transfer shares of Company Stock under Grants shall be subject to all applicable laws and to approvals by any governmental or regulatory agency as may be required. With respect to persons subject to section 16 of the Exchange Act, it is the intent of the Company that the Plan and all transactions under the Plan comply with all applicable provisions of Rule 16b-3 or its successors under the Exchange Act. In addition, it is the intent of the Company that the Plan and applicable Grants under the Plan comply with the applicable provisions of sections 162(m) and 422 of the Code, and any other applicable law or regulation having the effect of law. To the extent that any legal requirement of section 16 of the Exchange Act or section 162(m) or 422 of the Code as set forth in the Plan ceases to be required under section 16 of the Exchange Act or section 162(m) or 422 of the Code, that Plan provision shall cease to apply. Anything in this Plan to the contrary notwithstanding, the terms of this Plan shall be interpreted and applied in a manner consistent with the requirements of Section 409A of the Code and the Treasury Regulations thereunder and the Company shall have no right to make any payment under this Plan except to the extent permitted under Section 409A of the Code. It is intended that payments made under this Plan on or before the 15th day of the third month following the end of the Participant’s first taxable year in which the right to the payment is no longer subject to a substantial risk of forfeiture shall be exempt from compliance with Section 409A of the Code pursuant to the exception for short-term deferrals set forth in Section 1.409A-1(b)(4) of the Treasury Regulations. The Company shall have no obligation, however, to reimburse a Participant for any tax penalty or interest payable or provide a gross-up payment in connection with any tax liability of a Participant under Section 409A of the Code except that this provision shall not apply in the event of the Company’s negligence or willful disregard in interpreting the application of Section 409A of the Code to the Plan which negligence or willful disregard causes the Participant to become subject to a tax penalty or interest payable under Section 409A of the Code, in which case the Company will reimburse the Participant on an after-tax basis for any such tax penalty or interest not later than the last day of the Participant’s taxable year next following the Participant’s taxable year in which the Participant remits the applicable taxes and interest. To

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the extent permitted by applicable law, the Committee may revoke any Grant if it is contrary to law or modify a Grant to bring it into compliance with any valid and mandatory government regulation. The Committee may also adopt rules regarding the withholding of taxes on payments to Grantees. The Committee may, in its sole discretion, agree to limit its authority under this Section.

3. Deferred Compensation.

(a) 409A Awards. Anything in this Plan to the contrary notwithstanding, the following rules shall apply to 409A Awards and shall constitute further restrictions on terms of Awards and Grants set forth elsewhere in this Plan:

(i) The Committee may permit a Participant to elect to defer a Grant or Award, or any payment under a Grant or Award, in 2005 or thereafter, only if such election is either made before the beginning of the fiscal year for which the Grant or Award is granted or complies with an exception set forth in the Treasury Regulations under Section 409A of the Code or the transition rules set forth in Q&A 19(c) of IRS Notice 2005-1 as extended by the Treasury Regulations and IRS Notices 2006-79 and 2007-86 (collectively, the “Transition Rules”).

(ii) The Committee may, in its discretion, for the period beginning January 1, 2005 through December 31, 2008, require or permit on an elective basis (one or more times) a change in the distribution terms applicable to 409A Awards (and Non-409A Awards that qualify for the short-term deferral exemption under Section 409A) in accordance with, and to the fullest extent permitted by, the Transition Rules.

(iii) The Committee shall have no authority to accelerate distributions relating to 409A Awards in excess of the authority permitted under Section 1.409A-3(j) of the Treasury Regulations.

(iv) Any distribution of a 409A Award triggered by a Participant’s termination of employment and intended to qualify under Section 409A(a)(2)(A)(i) of the Code shall be made only at the time that the Participant has had a Termination (or at such earlier time, after a termination of employment, that there occurs another event triggering a distribution under the Plan or the applicable Grant Instrument in compliance with Section 409A).

(v) Any distribution of a 409A Award triggered by a Participant’s Termination shall be delayed for six months following the date of such Termination if such Participant is a Specified Employee on such date. In the event of any such delay in the distribution date, the 409A Award will be paid at the beginning of the seventh month following the Participant’s Termination. In the event of the Participant’s death during such six-month period, payment will be made in the payroll period next following the payroll period in which the Participant’s death occurs.

Any payment due within such six-month period will be adjusted to reflect the deferred payment date by multiplying the payment by the product of the interest discount rate used for financial accounting purposes to compute the present value liability of the Supplemental Executive Retirement Plan for Officers of Northeast Utilities System Companies for the plan year immediately preceding the date of the Specified Employee’s Termination, multiplied by a fraction, the numerator of which is the number of days by which such payment was delayed and the denominator of which is 365.

(vi) In the case of any distribution of a 409A Award, if the timing of such distribution is not otherwise specified in the Plan or a Grant Instrument, the distribution shall be made on or after the date at which the settlement of the Award is specified to occur and on or before the 75th day following the date at which the settlement of the Award is specified to occur, determined in the sole discretion of the Committee, except as otherwise provided in Subsection (v) above.

(vii) No amendment or termination of the Plan or a Grant pursuant to Article XII shall be effective with respect to 409A Awards except insofar as it complies with the requirements of Section 409A of the Code

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and the Treasury Regulations thereunder or the Transition Rules, including without limitation, the requirements set forth in Treasury Regulations Section 1.409A-2(b) governing subsequent changes in time and form of payment and Section 1.409A-3(j)(4)(ix) governing plan terminations.

(b) Grandfathered Grants. Any Grant that was both granted and vested before 2005 and which otherwise might constitute a deferral of compensation under Section 409A is intended to be “grandfathered” under Section 409A. No amendment or change to the Plan or other change (including an exercise of discretion) with respect to such a grandfathered Grant after October 3, 2004, shall be effective if such change would constitute a “material modification” within the meaning of the Treasury Regulations under Section 409A, except in the case of a Grant that is specifically modified to become compliant as a 409A Award or compliant with an exemption under Section 409A.

(c) Distributions Upon Vesting. In the case of any Grant providing for a distribution upon the lapse of a risk of forfeiture, if the timing of such distribution is not otherwise specified in the Plan or a Grant Instrument, the distribution shall be made on or after January 1 and on or before March 15 of the year following the year in which the risk of forfeiture lapsed.

(d) Scope and Application of this Provision. For purposes of this Section 3 and Section 2 above, references to a term or event (including any authority or right of the Company or a Participant) being “permitted” under or in “compliance” with Section 409A and the Treasury Regulations thereunder or the Transition Rules mean that the term or event will not cause the Participant to be deemed to be in constructive receipt of compensation relating to the 409A Award prior to the distribution of cash, shares or other property or to be liable for payment of interest or a tax penalty under Section 409A.

4. Clawback. Upon written demand of the Company, an Employee will reimburse or forfeit all or a portion of any Award or Grant paid to the Employee under the Plan where: (a) payment of the Award or Grant was predicated on the achievement of certain financial results that were subsequently the subject of a substantial restatement of the financial statements of the Company, (b) in the judgment of the Board the Employee engaged in fraud or misconduct that caused or partially caused the need for the substantial restatement, and (c) a lower payment would have been made to the Employee based on the restated financial results. In the event the Employee fails to make prompt reimbursement of any such Award or Grant previously paid or delivered, the Company may, to the extent permitted by applicable law, deduct the amount required to be reimbursed from the Grantee’s compensation otherwise due from the Company; provided, however, that the Company will not seek to recover upon Awards or Grants paid more than three years prior to the date the applicable restatement is disclosed.

5. Governing Law. The validity, construction, interpretation and effect of the Plan and Grant Instruments issued under the Plan shall exclusively be governed by and determined in accordance with the law of the State of Connecticut.

6. Disclaimer of Liability. The Declaration of Trust of NU provides that no shareholder of NU shall be held to any liability whatever for the payment of any sum of money, or for damages or otherwise under any contract, obligation or undertaking made, entered into or issued by the Board or by any officer, agent or representative elected or appointed by the Board, and no such contract, obligation or undertaking shall be enforceable against the Board or any of them in their or his or her individual capacities or capacity and all such contracts, obligations and undertakings shall be enforceable only against the Board as such, and every person or entity, having any claim or demand arising out of any such contract, obligation or undertaking shall look only to the trust estate for the payment or satisfaction thereof.

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ARTICLE XIV

DEFINITIONS

When used herein, each of the following terms shall have the corresponding meaning set forth below unless a different meaning is plainly required by the context in which a term is used:

14.1 “Award” is an annual incentive award made to an Employee as provided in Article III.

14.2 “Cause” is described in Article IV(3)(e)(ii)(A).

14.3 “Change of Control” is described in Article XI(1).

14.4 “Code” is the Internal Revenue Code of 1986, as amended from time to time, and any successor thereto.

14.5 “Committee” is described in Article II(1).

14.6 “Company Stock” or “Stock” is Northeast Utilities common shares, as described in Article IX(1)(a).

14.7 “Company” or “NU” is described in Article X.

14.8 “Disability” is described in Article IV(3)(e)(ii)(B).

14.9 “Exchange Act” is the Securities Exchange Act of 1934, as amended from time to time, and any successor thereto.

14.10 “Exercise Price” is described in Article IV(3)(b)(ii).

14.11 “409A Award” is an Award or Grant that constitutes a deferral of compensation subject to Code Section 409A and the Treasury Regulations thereunder. “Non-409A Award” is an Award or Grant other than a 409A Award (including Awards and Grants exempt under the short-term deferral exception set forth in Treasury Regulation Section 1.409A-1(b)(4) and Awards and Grants that vested before 2005 and therefore are “grandfathered” under Section 409A). Although the Committee retains authority under the Plan to grant Options and Stock Appreciation Rights on terms that will cause those Grants to be 409A Awards, Options and Stock Appreciation Rights are intended to be Non-409A Awards unless otherwise expressly specified by the Committee.

14.12 “Fair Market Value” is, as of any given date, the value of Company Stock, as provided in Article IV(3)(b)(iii), or as otherwise determined by the Committee.

14.13 “Grant” is described in Article IV(1).

14.14 “Grantee” is the individual to whom a Grant is made, as provided in Article IV, Section 2(b).

14.15 “Grant Instrument” is described in Article IV(1).

14.16 “Stock Option” is described in Article IV(3)(b).

14.17 “Nonqualified Stock Option” is described in Article IV(3)(b).

14.18 “Option” is an Incentive Stock Option or a Nonqualified Stock Option, as described in Article IV(3)(b).

14.19 “Participant” is any eligible individual to whom an Award or Grant is made.

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14.20 “Performance Goals” means the objectives for the Company or any subsidiary or affiliate or any unit thereof or any individual that may be established by the Committee for a Performance Period with respect to any performance-based Awards or Grants contingently awarded under the Plan. The Performance Goals for Awards or Grants that are intended to constitute “performance-based” compensation within the meaning of Section 162(m) (or any amended or successor provision) of the Code shall be based on one or more of the following criteria, either individually, alternatively or in any combination, and subject to such modifications or variations as specified by the Committee, applied to either the Company as a whole or to a business unit or subsidiary entity thereof, either individually, alternatively or in any combination, and measured over a period of time including any portion of a year, annually or cumulatively over a period of years, on an absolute basis or relative to a pre-established target, to previous years’ results or to a designated comparison group, in each case as specified by the Committee: cash flow; cash flow from operations; earnings (including, but not limited to, earnings before interest, taxes, depreciation and amortization or operating earnings); earnings per share, diluted or basic; earnings per share from continuing operations; net asset turnover; inventory turnover; capital expenditures; debt; debt reduction; credit rating; working capital; return on investment; return on sales; net or gross sales; market share; economic value added; cost of capital; change in assets; expense reduction levels; unit volume; productivity; delivery performance; service levels; safety record; stock price; return on equity; total shareholder return; return on capital; return on assets or net assets; revenue; income or net income; operating income or net operating income; operating profit or net operating profit; gross margin, operating margin or profit margin; and completion of acquisitions, divestitures, business expansion, product diversification, new or expanded market penetration and other non-financial operating and management performance objectives, or other strategic business criteria consisting of one or more objectives based on satisfaction of specified revenue goals, geographic business expansion goals or cost targets.

With respect to awards that are intended to qualify as performance-based compensation within the meaning of Section 162(m) and to the extent consistent with Section 162(m) of the Code and the regulations promulgated thereunder, the Committee may, unless otherwise determined by the Committee at the time the Performance Goals are established, adjust the Performance Goals to exclude the effect of any of the following events that occur during a Performance Period: the impairment of tangible or intangible assets; litigation or claim judgments or settlements; changes in tax law, accounting principles or other such laws or provisions affecting reported results; business combinations, reorganizations and/or restructuring programs that have been approved by the Board; reductions in force and early retirement incentives; and any extraordinary, unusual, infrequent or non-recurring items separately identified in the financial statements and/or notes thereto in accordance with generally accepted accounting principles. Notwithstanding the foregoing and with respect to awards that are not intended to qualify as performance-based compensation within the meaning of Section 162(m) of the Code, the Committee may, in its discretion, adjust Performance Goals as it considers necessary or appropriate.

14.21 “Performance Period” is the period selected by the Committee during which the performance of the Company or any subsidiary, affiliate or unit thereof or any individual is measured for the purpose of determining the extent to which an Award or Grant subject to Performance Goals or time vesting has been earned.

14.22 “Performance Unit” is described in Article VIII(1)(a).

14.23 “Plan” is this Northeast Utilities Incentive Plan, as amended from time to time.

14.24 “Qualified Performance-Based Compensation” is described in Article VIII(1)(e).

14.25 “Restriction Period” is described in Article VI(1)(a) and (2)(a).

14.26 “Restricted Stock” is a Grant described in Article VI.

14.27 “Restricted Share Units” or “RSUs” is a Grant described in Article VI.

14.28 “Retired” or “Retirement” is described in Article IV(3)(e)(ii)(D).

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14.29 “Specified Employee” is a Vice President or more senior officer of the Company at any time during a calendar year in which case such employee shall be considered a Specified Employee for the 12-month period beginning on the first day of the fourth month immediately following the end of such calendar year.

14.30 “Stock Appreciation Right” or “SAR” is a right granted pursuant to Article VII.

14.31 “Termination” is a termination of employment with the Company and any affiliate of the Company in all capacities, including as a common law employee and independent contractor. Whether a Participant has had a Termination shall be determined by the Committee on the basis of all relevant facts and circumstances with reference to Treasury Regulations Section 1.409A-1(h) regarding a “separation from service” and the default provisions set forth in Regulations Sections 1.409A-1(h)(1)(ii) and 1.409A-1(n).

14.32 “Termination on Account of Change of Control” of a Participant shall mean a Termination during the period beginning on the earlier of (a) approval by the shareholders of NU of a Change of Control or (b) consummation of a Change of Control and, in either case, ending on the second anniversary of the consummation of the transaction that constitutes the Change of Control (or if such period started on shareholder approval and after such shareholder approval the Board abandoned the transaction, on the date the Board abandoned the transaction) either:

(i) initiated by the Company for any reason other than the Participant’s (A) Disability, (B) death, (C) retirement on or after attaining age 65, or (D) Cause, or

(ii) initiated by the Participant upon written notice to the Company provided within 90 days of the initial existence of any of the following circumstances unless such circumstances are corrected within 30 days after the Company’s receipt of such notice (A) upon any significant reduction by the Company of the authority, duties or responsibilities of the Participant, (B) any material reduction of the Participant’s base compensation as in effect immediately prior to the Change of Control, (C) the assignment to the Participant of duties which are materially inconsistent with the duties of the Participant’s position with the Company or those of his or her supervisor, or (D) if the Participant is transferred, without the Participant’s written consent, to a location that is more than 50 miles from the Participant’s principal place of business immediately preceding the Change of Control.

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APPENDIX B

2011 ANNUAL REPORT

September 20, 2012

DEAR FELLOW SHAREHOLDERS:

On April 10, 2012, the new Northeast Utilities (NU) was formed, and we are well on our way to building a bigger, stronger and better company. We are now the largest utility in New England, with a stock market value of $12 billion, 3.5 million customers, over 9,000 employees and a strong legacy of operational excellence and leadership in the industry. Our success has been grounded in decades of delivering superior results to our shareholders, and it’s this proven success that makes us very optimistic about the future of the new NU.

Our financial performance has been noted by the marketplace. Since the merger was announced, NU’s share price has increased dramatically and the dividend has increased by nearly 34 percent. And as we move ahead, we expect to continue strong earnings and dividend increases resulting in a superior total return to shareholders.

Furthermore, with an improved balance sheet and strong cash flows, the combined company is creating immediate and long-term shareholder value. This improved financial condition has been recognized by major rating agencies and has resulted in an upgrade to NU’s credit rating. NU is now among the highest rated companies in the industry with only one company having a higher rating. Furthermore, our sharp focus on operational and capital discipline is expected to help us maintain these strong ratings and provide the superior earnings growth that is so important to all of our investors.

As NU begins a new corporate chapter, we continue to invest in our energy distribution and transmission businesses to continue to provide great service to our customers. Work is well underway to further upgrade, strengthen and modernize our energy delivery systems throughout Connecticut, Massachusetts and New Hampshire. We have also worked aggressively to improve our emergency preparedness and response efforts. Throughout our service territory, particularly in Connecticut, we have expanded our tree-trimming program and are making significant investments in the resiliency of our electric distribution system to enhance reliability for customers.

More broadly, our successful record of delivering innovative electric transmission solutions to address the energy concerns challenging our region continues. Our key transmission projects – the New England East-West Solution (NEEWS) and the Northern Pass project, a 180-mile, high-voltage transmission line that will bring 1,200 megawatts of low-carbon power from Canada to southern New Hampshire – together represent a $2.4 billion investment. We remain confident that the need for further transmission infrastructure and our best-in-class ability to design, site and build that infrastructure will contribute to future success for NU.

Guided by a strong and diverse Board of Trustees and leadership team, we believe that NU is on a solid growth trajectory and well positioned to continue to deliver shareholder and customer value in the years ahead.

Sincerely,

Charles W. Shivery	Thomas J. May
Chairman of the Board	President and Chief Executive Officer

TABLE OF CONTENTS

	Page
Northeast Utilities		B-1
Northeast Utilities Common Share and Dividend Information		B-2
Five-Year Cumulative Performance Graph		B-2
Glossary of Terms		B-3
Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995		B-6
Company Report on Internal Controls over Financial Reporting		B-7
Report of Independent Registered Public Accounting Firm		B-8
Management’s Discussion and Analysis of Financial Condition and Results of Operations		B-9
Quantitative and Qualitative Disclosures about Market Risk		B-46
Financial Statements and Supplementary Data
Consolidated Balance Sheets		B-48
Consolidated Statements of Income		B-50
Consolidated Statements of Comprehensive Income		B-51
Consolidated Statements of Common Shareholders’ Equity		B-52
Consolidated Statements of Cash Flows		B-53
Combined Notes to Financial Statements		B-54
Selected Consolidated Financial Data (Unaudited)		B-126
Northeast Utilities Trustees		B-127
Northeast Utilities Executive Officers		B-128
Shareholder Information		B-129

i

NORTHEAST UTILITIES

The sections of this Annual Report listed below have been excerpted from the Northeast Utilities Combined Annual Report on Form 10-K filed with the SEC on February 24, 2012:

	Page
Management’s Discussion and Analysis		B-9
Quantitative and Qualitative Disclosures about Market Risk		B-46
Financial Statements and Supplementary Data		B-48
Selected Consolidated Financial Data (Unaudited)		B-126

References in these sections to “NU,” the “Company,” “we,” “us” and “our” refer to Northeast Utilities and its consolidated subsidiaries for 2011, and do not include any information about NSTAR LLC or its subsidiaries, including NSTAR Electric Company and NSTAR Gas Company.

Please refer to the Glossary of Terms for definitions of defined terms and abbreviations used in this 2011 Annual Report.

Northeast Utilities, or “NU,” headquartered in Boston, Massachusetts and Hartford, Connecticut, is a Massachusetts voluntary association and a public utility holding company registered with the Federal Energy Regulatory Commission (FERC) under the Public Utility Holding Company Act of 2005. NU is engaged primarily in the energy delivery business, providing franchised retail electric service to approximately 3 million customers in Connecticut, New Hampshire and Massachusetts through four wholly-owned subsidiaries, The Connecticut Light and Power Company, NSTAR Electric Company, Public Service Company of New Hampshire and Western Massachusetts Electric Company, and franchised retail natural gas service to approximately 500,000 residential, commercial and industrial customers in Connecticut and Massachusetts through two wholly-owned indirect subsidiaries, NSTAR Gas Company and Yankee Gas Services Company. NU provides energy service to a total of 525 cities and towns in Connecticut, Massachusetts and New Hampshire.

Merger with NSTAR

On April 10, 2012, NU and NSTAR completed their merger. Pursuant to the terms and conditions of the Agreement and Plan of Merger, as amended (the “Merger Agreement”) NSTAR merged into NSTAR LLC, a wholly-owned subsidiary of NU. Consequently, the financial results of NSTAR LLC and its subsidiaries, including NSTAR Electric Company and NSTAR Gas Company, are not included in this Annual Report, which contains information about NU through the year ended December 31, 2011.

The transaction was structured as a merger of equals in a tax-free exchange of shares. Pursuant to the Merger Agreement, NU issued to NSTAR shareholders 1.312 NU common shares for each issued and outstanding NSTAR common share. As a result, NU had approximately 314 million shares outstanding as of April 30, 2012, compared with approximately 178 million shares outstanding as of March 31, 2012.

The final merger approvals were issued on April 2, 2012 by the PURA and on April 4, 2012 by the DPU. Both state regulatory approvals contained a number of conditions that were primarily the result of settlement agreements with state officials that had intervened in the merger approval processes.

General

NU’s subsidiaries are regulated in virtually all aspects of their business by various federal agencies, including the SEC, the FERC, and various state and/or local regulatory authorities with jurisdiction over the industry and the service areas in which each company operates.

The principal executive office of NU is located at One Federal Street, Building 111-4, Springfield, Massachusetts 01105, telephone number (413) 785-5871. The dual headquarters of NU are located at 800 Boylston Street, Boston, Massachusetts 02199 and 56 Prospect Street, Hartford, Connecticut 06103, telephone number (860) 665-5000.

B-1

NORTHEAST UTILITIES COMMON SHARE AND DIVIDEND INFORMATION

The common shares of Northeast Utilities are listed on the New York Stock Exchange. The ticker symbol is “NU,” although it is frequently presented as “Noeast Util” and/or “NE Util” in various financial publications. The high and low sales prices for the past two years, by quarter, are shown below:

	High		Low		Dividend
2011
First Quarter	$	35.13	$	31.19	$	0.275
Second Quarter		36.47		33.31		0.275
Third Quarter		35.87		30.02		0.275
Fourth Quarter		36.40		30.80		0.275
2010
First Quarter	$	28.00	$	24.68	$	0.25625
Second Quarter		28.21		24.83		0.25625
Third Quarter		30.25		25.24		0.25625
Fourth Quarter		32.21		29.51		0.25625

As of September 4, 2012, there were 51,958 holders of record and 313,842,387 common shares outstanding.

FIVE-YEAR CUMULATIVE PERFORMANCE GRAPH

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GLOSSARY OF TERMS

The following is a glossary of abbreviations or acronyms that are found in this report.

CURRENT OR FORMER NU COMPANIES, SEGMENTS OR INVESTMENTS:
Boulos	E.S. Boulos Company
CL&P	The Connecticut Light and Power Company
HWP	HWP Company, formerly the Holyoke Water Power Company
NGS	Northeast Generation Services Company and subsidiaries
NPT	Northern Pass Transmission LLC, a jointly owned limited liability company, held by NUTV and NSTAR Transmission Ventures, Inc. on a 75 percent and 25 percent basis, respectively
NUTV	NU Transmission Ventures, Inc.
*NU or the Company	Northeast Utilities and subsidiaries
NU Enterprises	NU Enterprises, Inc., the parent company of Select Energy, NGS, NGS Mechanical, Select Energy Contracting, Inc. and Boulos
NUSCO	Northeast Utilities Service Company
NU parent and other companies	NU parent and other companies is comprised of NU parent, NUSCO and other subsidiaries, including HWP, RRR (a real estate subsidiary), and the non-energy-related subsidiaries of Yankee (Yankee Energy Services Company, and Yankee Energy Financial Services Company)
PSNH	Public Service Company of New Hampshire
Regulated companies	NU’s Regulated companies, comprised of the electric distribution and transmission segments of CL&P, PSNH and WMECO, the generation activities of PSNH and WMECO, Yankee Gas, a natural gas local distribution company, and NPT
RRR	The Rocky River Realty Company
Select Energy	Select Energy, Inc.
WMECO	Western Massachusetts Electric Company
Yankee	Yankee Energy System, Inc.
Yankee Gas	Yankee Gas Services Company
REGULATORS:
DEEP	Connecticut Department of Energy and Environmental Protection
DOE	U.S. Department of Energy
DPU	Massachusetts Department of Public Utilities
DPUC	Connecticut Department of Public Utility Control
EPA	U.S. Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
MA DEP	Massachusetts Department of Environmental Protection
NHPUC	New Hampshire Public Utilities Commission
PURA	Connecticut Public Utility Regulatory Authority (formerly DPUC)
SEC	Securities and Exchange Commission
OTHER:
2010 Healthcare Act	Patient Protection and Affordable Care Act
AOCI	Accumulated Other Comprehensive Income/(Loss)
AFUDC	Allowance For Funds Used During Construction
AMI	Advanced metering infrastructure
ARO	Asset Retirement Obligation
C&LM	Conservation and Load Management
CERCLA	The federal Comprehensive Environmental Response, Compensation and Liability Act of 1980

* Does not include NSTAR LLC or its subsidiaries, including NSTAR Electric Company and NSTAR Gas Company.

B-3

CfD	Contract for Differences
CO2	Carbon dioxide
CTA	Competitive Transition Assessment
CWIP	Construction work in progress
CYAPC	Connecticut Yankee Atomic Power Company
DOER	Massachusetts Department of Energy Resources
EIA	Energy Independence Act
EPS	Earnings Per Share
ERISA	Employee Retirement Income Security Act of 1974
ES	Default Energy Service
ESOP	Employee Stock Ownership Plan
ESPP	Employee Stock Purchase Plan
Fitch	Fitch Ratings
FMCC	Federally Mandated Congestion Charge
FTR	Financial Transmission Rights
GAAP	Accounting principles generally accepted in the United States of America
GSC	Generation Service Charge
GSRP	Greater Springfield Reliability Project
GWh	Giga-watt Hours
HG&E	Holyoke Gas and Electric, a municipal department of the town of Holyoke, MA
HQ	Hydro-Québec, a corporation wholly owned by the Québec government, including its divisions that produce, transmit and distribute electricity in Québec, Canada
HVDC	High voltage direct current
Hydro Renewable Energy	H.Q. Hydro Renewable Energy, Inc., a wholly owned subsidiary of Hydro-Québec
IPP	Independent Power Producers
ISO-NE	ISO New England, Inc., the New England Independent System Operator
ISO-NE Tariff	ISO-NE FERC Transmission, Markets and Services Tariff
KV	Kilovolt
kWh	Kilowatt-Hours
LNG	Liquefied natural gas
LOC	Letter of Credit
LRS	Supplier of last resort service
MGP	Manufactured Gas Plant
Millstone	Millstone Nuclear Generating station, made up of Millstone 1, Millstone 2, and Millstone 3. All three units were sold in March 2001.
Money Pool	Northeast Utilities Money Pool
Moody’s	Moody’s Investors Services, Inc.
MW	Megawatt
MWh	Megawatt-Hours
MYAPC	Maine Yankee Atomic Power Company
NEEWS	New England East-West Solution
NOx	Nitrogen oxide
Northern Pass	The high voltage direct current transmission line project from Canada into New Hampshire
NPDES	National Pollutant Discharge Elimination System
NU supplemental benefit trust	The NU Trust Under Supplemental Executive Retirement Plan

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OCI	Other Comprehensive Income
PBO	Projected Benefit Obligation
PBOP	Postretirement Benefits Other Than Pension
PBOP Plan	Postretirement Benefits Other Than Pension Plan that provides certain retiree health care benefits, primarily medical and dental, and life insurance benefits
PCRBs	Pollution Control Revenue Bonds
Pension Plan	Single uniform noncontributory defined benefit retirement plan
PGA	Purchased Gas Adjustment
PPA	Pension Protection Act
RECs	Renewable Energy Certificates
Regulatory ROE	The average cost of capital method for calculating the return on equity related to the distribution and generation business segment excluding the wholesale transmission segment
RNS	Regional Network Service
ROE	Return on Equity
RPS	Renewable Portfolio Standards
RRB	Rate Reduction Bond or Rate Reduction Certificate
RSUs	Restricted share units
S&P	Standard & Poor’s Financial Services LLC
SBC	Systems Benefits Charge
SCRC	Stranded Cost Recovery Charge
SERP	Supplemental Executive Retirement Plan
SO2	Sulfur dioxide
SS	Standard service
TCAM	Transmission Cost Adjustment Mechanism
TSA	Transmission Service Agreement
UI	The United Illuminating Company
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

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SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES

LITIGATION REFORM ACT OF 1995

References in this Annual Report to “NU,” “we,” “our,” and “us” refer to Northeast Utilities and its consolidated subsidiaries for the year ended 2011. The references do not include NSTAR LLC or its subsidiaries, including NSTAR Electric Company and NSTAR Gas Company.

From time to time we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, assumptions of future events, 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 may 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:

• actions or inaction by 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;

• changes in weather patterns;

• changes in laws, regulations or regulatory policy;

• changes in levels and 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;

• actions of rating agencies;

• the outcome of our merger with NSTAR; 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 management to predict all of such factors, nor can it 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 Risk Factors in this Annual Report. This Annual Report also describes material contingencies and critical accounting policies in the accompanying Management’s Discussion and Analysis and Combined Notes to Consolidated Financial Statements. We encourage you to review these items.

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COMPANY REPORT ON INTERNAL CONTROLS OVER FINANCIAL REPORTING

Management is responsible for the preparation, integrity, and fair presentation of the accompanying consolidated financial statements of Northeast Utilities and subsidiaries (NU or the Company) and of other sections of this annual report. NU’s internal controls over financial reporting were audited by Deloitte & Touche LLP.

Management is responsible for establishing and maintaining adequate internal controls over financial reporting. The Company’s internal control framework and processes have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. There are inherent limitations of internal controls over financial reporting that could allow material misstatements due to error or fraud to occur and not be prevented or detected on a timely basis by employees during the normal course of business. Additionally, internal controls over financial reporting may become inadequate in the future due to changes in the business environment.

Under the supervision and with the participation of the principal executive officer and principal financial officer, NU conducted an evaluation of the effectiveness of internal controls over financial reporting based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation under the framework in COSO, management concluded that internal controls over financial reporting were effective as of December 31, 2011.

Charles W. Shivery

Chairman of the Board, President and Chief Executive Officer

David R. McHale

Executive Vice President and Chief Financial Officer

February 24, 2012

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Trustees and Shareholders of Northeast Utilities:

We have audited the accompanying consolidated balance sheets of Northeast Utilities and subsidiaries (the “Company”) as of December 31, 2011 and 2010 and the related consolidated statements of income, comprehensive income, common shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2011. Our audits also included the financial statement schedules listed in the Index at Item 15 of Part IV. We also have audited the Company’s internal control over financial reporting as of December 31, 2011 based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these financial statements and financial statement schedules, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Company Report on Internal Controls over Financial Reporting. Our responsibility is to express an opinion on these financial statements and financial statement schedules and an opinion on the Company’s internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Northeast Utilities and subsidiaries as of December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

/s/ Deloitte & Touche LLP

Hartford, Connecticut

February 24, 2012

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Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with our consolidated financial statements and related combined notes included in this Annual Report. References in this Management’s Discussion and Analysis to “NU,” the “Company,” “we,” “us” and “our” refer to Northeast Utilities and its consolidated subsidiaries for 2011, but does not include NSTAR LLC or its subsidiaries, including NSTAR Electric Company and NSTAR Gas Company. All per share amounts are reported on a diluted basis.

Refer to the Glossary of Terms included in this Annual Report for abbreviations and acronyms used throughout this Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The only common equity securities that are publicly traded are common shares of NU. The earnings and EPS of each business discussed below do not represent a direct legal interest in the assets and liabilities allocated to such business but rather represent a direct interest in our assets and liabilities as a whole. EPS by business is a financial measure not recognized under GAAP that is calculated by dividing the Net Income Attributable to Controlling Interests of each business by the weighted average diluted NU common shares outstanding for the period. We use this non-GAAP financial measure to evaluate earnings results and to provide details of earnings results and guidance by business. We believe that this measurement is useful to investors to evaluate the actual and projected financial performance and contribution of our businesses. This non-GAAP financial measure should not be considered as an alternative to our consolidated diluted EPS determined in accordance with GAAP as an indicator of operating performance.

The discussion below does not include NSTAR LLC or its subsidiaries, but includes non-GAAP financial measures referencing our 2011 earnings and EPS excluding expenses related to NU’s merger with NSTAR and a non-recurring charge at CL&P for the establishment of a reserve to provide bill credits to its residential customers and donations to charitable organizations, as well as our 2010 earnings and EPS excluding merger expenses incurred in 2010 and certain non-recurring benefits from the settlement of tax issues. We use these non-GAAP financial measures to more fully compare and explain the 2011, 2010 and 2009 results without including the impact of these non-recurring items. Due to the nature and significance of these items on Net Income Attributable to Controlling Interests, management believes that this non-GAAP presentation is more representative of our performance and provides additional and useful information to readers of this report in analyzing historical and future performance. These non-GAAP financial measures should not be considered as alternatives to reported Net Income Attributable to Controlling Interests or EPS determined in accordance with GAAP as indicators of operating performance.

Reconciliations of the above non-GAAP financial measures to the most directly comparable GAAP measures of consolidated diluted EPS and Net Income Attributable to Controlling Interests are included under “Financial Condition and Business Analysis — Overview — Consolidated” and “Financial Condition and Business Analysis — Future Outlook” in Management’s Discussion and Analysis, herein. All forward-looking information for 2012 and thereafter provided in this Management’s Discussion and Analysis excludes the impacts of the merger with NSTAR, unless otherwise indicated.

Financial Condition and Business Analysis

Pending Merger with NSTAR:

On October 18, 2010, NU and NSTAR announced that each company’s Board of Trustees unanimously approved a merger agreement (the “agreement”), under which NSTAR will become a direct wholly owned subsidiary of NU. On October 14, 2011, NU and NSTAR extended the termination date of the agreement, as defined therein, from October 16, 2011 to April 16, 2012. The transaction is structured as a merger of equals in a tax-free exchange of shares. Under the terms of the agreement, NSTAR shareholders will receive 1.312 NU common shares for each NSTAR common share that they own (the “exchange ratio”). Following the merger, NU will provide electric and natural gas energy delivery service to approximately 3.5 million electric and natural gas customers through six regulated electric and natural gas utilities in Connecticut, Massachusetts and New Hampshire. On March 4, 2011, NU shareholders

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approved the agreement, approved an increase in the number of NU common shares authorized for issuance by 155 million common shares to 380 million common shares and fixed the number of trustees at 14. NSTAR shareholders approved the agreement on March 4, 2011.

Subject to the conditions in the agreement, our first quarterly dividend per common share paid after the closing of the merger will be increased to an amount that is at least equal, after adjusting for the exchange ratio, to NSTAR’s last quarterly dividend paid prior to the closing.

Completion of the merger is subject to various customary conditions, including, among others, receipt of all required regulatory approvals. NU and NSTAR are awaiting approvals from PURA and the DPU. PURA is scheduled to issue a final decision on April 2, 2012. On February 15, 2012, NU and NSTAR reached comprehensive merger-related settlement agreements with both the Massachusetts Attorney General and the Massachusetts Department of Energy Resources agreeing to certain conditions with respect to the merger, which are subject to DPU approval and have been requested by the parties to be approved on April 4, 2012. If both PURA and the DPU issue acceptable decisions by such dates, we expect the merger will be consummated by April 16, 2012. For further information regarding regulatory approvals on the pending merger, see “Regulatory Developments and Rate Matters — Regulatory Approvals for Pending Merger with NSTAR,” in this Management’s Discussion and Analysis.

Executive Summary

The following items in this executive summary are explained in more detail in this Annual Report:

Results:

• We earned $394.7 million, or $2.22 per share, in 2011, compared with $387.9 million, or $2.19 per share, in 2010. Excluding merger-related costs of $11.3 million, or $0.06 per share, and a non-recurring charge at CL&P of $17.9 million, or $0.10 per share, we earned $423.9 million, or $2.38 per share, in 2011. The non-recurring charge at CL&P relates to the establishment of a reserve to provide bill credits to its residential customers and donations to charitable organizations (“storm fund reserve”). Improved results in 2011 were due primarily to the impact of electric distribution rate case decisions that were effective July 1, 2010 for CL&P and PSNH and February 1, 2011 for WMECO and the impact of a higher level of investment in transmission infrastructure.

• Our Regulated companies earned $420.4 million, or $2.36 per share, in 2011, including the $17.9 million CL&P storm fund reserve, compared with $384 million, or $2.16 per share, in 2010.

• The distribution segment of our Regulated companies earned $220.8 million, or $1.24 per share, in 2011, including the $17.9 million CL&P storm fund reserve, compared with $206.2 million, or $1.16 per share, in 2010. The transmission segment of our Regulated companies earned $199.6 million, or $1.12 per share, in 2011, compared with $177.8 million, or $1.00 per share, in 2010.

• NU parent and other companies recorded net expenses of $25.7 million, or $0.14 per share, in 2011, compared with earnings of $3.9 million, or $0.03 per share, in 2010. In 2011, excluding merger-related costs of $11.3 million, or $0.06 per share, NU parent and other companies recorded net expenses of $14.4 million, or $0.08 per share. In 2010, results included a non-recurring benefit of $15.7 million, or $0.09 per share, associated with the settlement of tax issues and a charge of $9.4 million, or $0.06 per share, associated with merger-related costs.

2011 Major Storm Items:

• On August 28, 2011, Tropical Storm Irene caused extensive damage to our distribution system resulting in incremental restoration costs of $135.6 million, $123.8 million of which were incurred by CL&P. Approximately 800,000 of our 1.9 million electric distribution customers were without power at the peak of the outages. CL&P capitalized $18.2 million of the restoration costs and deferred $105.6 million for future recovery.

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• On October 29, 2011, an unprecedented storm inundated our service territory with heavy snow causing significant damage to our distribution and transmission systems resulting in incremental restoration costs of $218.5 million, $22.6 million of which were capitalized and $195.9 million were deferred for future recovery. Approximately 1.2 million of our electric distribution customers were without power at the peak of the outages. This was the largest storm in CL&P’s and WMECO’s history and third largest in PSNH’s history in terms of customer outages. CL&P’s portion of incremental restoration costs was $174.6 million, of which $16.9 million was capitalized and $157.7 million was deferred for future recovery.

• The storms met the regulatory criteria for cost deferral and as a result, except for the CL&P storm fund reserve, they had no material impact on our results of operations. We believe our response to the storm damage was prudent and therefore we believe it is probable that CL&P, PSNH and WMECO will be allowed to recover these storm costs. Each operating company will seek recovery of its estimated deferred storm costs through its applicable regulatory recovery process.

• CL&P recorded a storm fund reserve of $30 million ($17.9 million after-tax) to provide bill credits to its residential customers who remained without power after noon on Saturday, November 5, 2011 as a result of the October snowstorm, and to provide donations to certain Connecticut charitable organizations. CL&P will not seek to recover this amount in its rates.

• A number of governmental inquiries have been initiated in Connecticut, New Hampshire and Massachusetts to review the response of utilities and other entities to Tropical Storm Irene and the October snowstorm. Certain reviews were completed while other inquiries are expected to be completed in the second quarter of 2012.

Strategy, Legislative, Regulatory and Other Items:

• On June 29, 2011, the DPUC (now PURA) issued a final decision in the Yankee Gas rate proceeding that was amended on September 28, 2011. The decision resulted in essentially no changes to distribution rates for 2011 and an increase of approximately $7 million in Yankee Gas’ annual revenues beginning July 1, 2012.

• On September 30, 2011, several parties filed a joint complaint with the FERC alleging that the base ROE used in calculating formula rates for transmission service under the ISO-NE Open Access Transmission Tariff by New England transmission owners, including CL&P, PSNH and WMECO, is unjust and unreasonable, and seeking an order to reduce the rate from 11.14 percent to 9.2 percent. On October 20, 2011, the New England transmission owners filed their response seeking dismissal of the complaint on the basis that the complainants failed to demonstrate that the existing base ROE is unjust and unreasonable and provided testimony and analysis demonstrating that the 11.14 percent base ROE remains just and reasonable. The FERC has not yet issued an order in this proceeding.

• On September 13, 2011, CL&P and WMECO received the required permit from U.S. Army Corps of Engineers allowing them to commence full construction of GSRP. The $718 million project is expected to be placed in service in late 2013. As of December 31, 2011, GSRP was approximately 50 percent complete.

• In September 2011, the Clean Air Project was placed in service at PSNH’s Merrimack Station. By November 2011, both of the Merrimack Station’s coal-fired units were integrated with the scrubber, which is reducing emissions from the units. Finalization of project activities, including water discharge enhancements, is expected in mid-2012. We expect the project will cost approximately $422 million.

• Yankee Gas’ WWL project was completed and placed in service in November 2011. Project costs totaled approximately $54 million, $3.6 million below the previous estimate of $57.6 million.

• On December 23, 2011, CL&P filed a siting application with the Connecticut Siting Council to build the 40-mile, $218 million Connecticut section of the IRP. In early 2012, National Grid is expected to file siting applications with regulators in Massachusetts and Rhode Island to build its sections of the IRP. We expect to receive approvals from all three states in late 2013 and to place the IRP in service by late 2015.

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Liquidity:

• Cash and cash equivalents totaled $6.6 million as of December 31, 2011, compared with $23.4 million as of December 31, 2010, while cash capital expenditures totaled $1.1 billion in 2011, compared with $954.5 million in 2010.

• On February 14, 2012, our Board of Trustees declared a quarterly common dividend of $0.29375 per share, payable on March 30, 2012 to shareholders of record as of March 1, 2012, which equates to $1.175 per share on an annualized basis. Assuming our pending merger with NSTAR closes in 2012 after NSTAR pays its March 30, 2012 dividend of $0.45 per share, the terms of the merger agreement would require NU’s first quarterly dividend paid after the merger to be at least $0.343 per share, or at least $1.372 per share on an annualized basis.

• Cash flows provided by operating activities in 2011 totaled $901.1 million, compared with $832.6 million in 2010 (amounts are net of RRB payments). The improved cash flows in 2011 were due primarily to the impact of the recent electric distribution rate case decisions and 2011 income tax refunds, as compared to 2010 income tax payments, partially offset by a Pension Plan contribution and cash disbursements associated with major storm costs. On a stand-alone basis, 2012 cash flows provided by operating activities, net of RRB payments, are expected to be lower than in 2011 due primarily to approximately $50 million more in Pension Plan contributions than in 2011 and approximately $27 million in bill credits provided to CL&P residential customers in February 2012.

• In 2011, we issued $260 million of new long-term debt consisting of $160 million by PSNH and $100 million by WMECO. Additionally, CL&P remarketed $62 million of tax-exempt secured PCRBs in April 2011 and refinanced $245.5 million of PCRBs in October 2011. PSNH refinanced $119.8 million of PCRBs in May 2011. In April 2012, NU parent has a debt maturity of $263 million, which we expect will be refinanced. In addition to remarketing the CL&P $62 million PCRBs, we expect to issue $150 million of long-term debt comprised of $100 million by WMECO and $50 million by Yankee Gas in the second half of 2012.

Overview

Consolidated: A summary of our earnings by business, which also reconciles the non-GAAP financial measures of consolidated non-GAAP earnings and EPS, as well as EPS by business, to the most directly comparable GAAP measures of consolidated Net Income Attributable to Controlling Interests and diluted EPS, for 2011, 2010 and 2009 is as follows:

	For the Years Ended December 31,
	2011						2010						2009
(Millions of Dollars, except per share amounts)	Amount			Per Share			Amount			Per Share			Amount		Per Share
Net Income Attributable to Controlling Interests (GAAP)	$	394.7		$	2.22		$	387.9		$	2.19		$	330.0	$	1.91
Regulated Companies	$	438.3		$	2.46		$	384.0		$	2.16		$	323.5	$	1.87
NU Parent and Other Companies		(14.4	)		(0.08	)		(2.4	)		(0.00	)		6.5		0.04
Non-GAAP Earnings		423.9			2.38			381.6			2.16			330.0		1.91
Non-Recurring Tax Settlements		—			—			15.7			0.09			—		—
Merger-Related Costs		(11.3	)		(0.06	)		(9.4	)		(0.06	)		—		—
Storm Fund Reserve		(17.9	)		(0.10	)		—			—			—		—
Net Income Attributable to Controlling Interests (GAAP)	$	394.7		$	2.22		$	387.9		$	2.19		$	330.0	$	1.91

Improved results in 2011 were due primarily to the impact of electric distribution rate case decisions that were effective July 1, 2010 for CL&P and PSNH and February 1, 2011 for WMECO, the impact of a higher level

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of investment in transmission infrastructure, colder than normal weather in the first quarter of 2011, continued cost management efforts, and the absence of a net charge of approximately $3 million, or approximately $0.02 per share, taken in the first quarter of 2010 associated with the enactment of the 2010 Healthcare Act. These benefits were partially offset by a decline in NU parent and other companies’ results, a second quarter 2011 refund to transmission wholesale customers, as compared to a recovery from those customers in 2010, lower retail electric sales in 2011, compared to 2010, as well as higher Pension and PBOP costs, depreciation, property taxes and the storm fund reserve.

Regulated Companies: Our Regulated companies consist of the electric distribution and transmission segments, with the Yankee Gas natural gas distribution segment and PSNH and WMECO generation activities included in the distribution segment. A summary of our Regulated companies’ earnings by segment for 2011, 2010 and 2009 is as follows:

	For the Years Ended December 31,
(Millions of Dollars)	2011			2010		2009
CL&P Transmission	$	151.9		$	143.9	$	136.8
PSNH Transmission		24.1			20.7		18.0
WMECO Transmission		22.8			13.0		9.5
NPT		0.8			0.2		—
Total Transmission		199.6			177.8		164.3
CL&P Distribution		110.6			94.1		74.0
PSNH Distribution		76.2			69.3		47.5
WMECO Distribution		20.2			10.1		16.7
Yankee Gas		31.7			32.7		21.0
Total Distribution		238.7			206.2		159.2
Subtotal — Regulated Companies’ Earnings Before Non-Recurring Charge	$	438.3		$	384.0	$	323.5
Storm Fund Reserve (1)	$	(17.9	)	$	—	$	—
Net Income — Regulated Companies	$	420.4		$	384.0	$	323.5

(1) Attributable to the CL&P distribution segment.

The increased 2011 transmission segment earnings as compared to 2010 were due primarily to a higher level of investment in transmission infrastructure, and a higher proportion of equity funding to support the transmission investments, partially offset by a 2011 refund to transmission wholesale customers, as compared to a recovery from those customers in 2010, primarily impacting CL&P. The increased 2010 transmission segment earnings as compared to 2009 reflect a higher level of investment in transmission infrastructure. Our transmission rate base totaled $2.96 billion at the end of 2011, compared with $2.76 billion at the end of 2010.

CL&P’s 2011 distribution segment earnings, excluding the $17.9 million storm fund reserve, were $16.5 million higher than 2010 due primarily to the impact of the 2010 distribution rate case decision that was effective July 1, 2010 and included an incremental rate increase effective July 1, 2011, lower uncollectibles expense and lower income taxes. Partially offsetting these favorable items were higher Pension and PBOP costs, a 1.5 percent decrease in retail electric sales and higher depreciation and property taxes. CL&P’s distribution segment regulatory ROE was 9.4 percent in 2011, as compared to 7.9 percent in 2010.

PSNH’s 2011 distribution segment earnings were $6.9 million higher than 2010 due primarily to higher revenues as a result of the permanent distribution rate increase effective July 1, 2010, and higher generation-related earnings, partially offset by the absence of the 2010 favorable impact of the distribution rate case settlement, which allowed for the recovery of certain actual expenses retroactive to August 1, 2009, higher

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property taxes and a 0.4 percent decrease in retail electric sales. PSNH’s distribution segment regulatory ROE was 9.7 percent in 2011, as compared to 10.2 percent in 2010.

WMECO’s 2011 distribution segment earnings were $10.1 million higher than 2010 due primarily to the impact of the distribution rate case decision effective February 1, 2011 and lower operations and maintenance costs, partially offset by a $5.3 million pre-tax charge to establish a reserve related to a wholesale billing adjustment, and higher depreciation and amortization. WMECO’s distribution segment regulatory ROE was 9 percent in 2011, as compared to 4.6 percent in 2010.

Yankee Gas’ 2011 earnings were $1 million lower than 2010 due primarily to higher pension and PBOP costs, the absence of a 2010 benefit related to the settlement of various tax matters, and higher depreciation and property taxes. These unfavorable impacts were partially offset by higher revenues resulting from an 8 percent increase in total firm natural gas sales, and lower uncollectibles expense. Yankee Gas’ regulatory ROE was 9.3 percent in 2011, as compared to 8.6 percent in 2010.

On August 28, 2011, Tropical Storm Irene caused extensive damage to our distribution system resulting in incremental restoration costs of $135.6 million. Approximately 800,000 of our 1.9 million electric distribution customers were without power at the peak of the outages.

On October 29, 2011, an unprecedented storm inundated our service territory with heavy snow causing significant damage to our distribution and transmission systems resulting in incremental restoration costs of $218.5 million. Approximately 1.2 million of our electric distribution customers were without power at the peak of the outages, with 810,000 of those customers in Connecticut, 237,000 in New Hampshire, and 140,000 in Massachusetts. In terms of customer outages, this was the most severe storm in CL&P’s history, surpassing Tropical Storm Irene; the third most severe in PSNH’s history, following a December 2008 ice storm and a February 2010 winter storm; and the most severe in WMECO’s history.

Estimated incremental restoration costs related to the storms are summarized in the table below and consist of costs that are deferred for future recovery and costs that are capitalized:

	For the Year Ended December 31, 2011
(Millions of Dollars)	Deferred for Future Recovery		Capitalized		Total Incremental Costs
Tropical Storm Irene:
CL&P	$	105.6	$	18.2	$	123.8
PSNH		7.0		1.1		8.1
WMECO		3.2		0.5		3.7
Total Tropical Storm Irene		115.8		19.8		135.6
October Snowstorm:
CL&P		157.7		16.9		174.6
PSNH		14.7		2.2		16.9
WMECO		23.5		3.5		27.0
Total October Snowstorm		195.9		22.6		218.5
Total Storm Costs	$	311.7	$	42.4	$	354.1

The storms met the regulatory criteria for cost deferral in Connecticut, New Hampshire and Massachusetts and as a result, except for the CL&P storm fund reserve, the storm costs had no material impact on the results of operations of CL&P, PSNH or WMECO. We believe our response to the storm damage was prudent and therefore we believe it is probable that CL&P, PSNH and WMECO will be allowed to recover these costs. Each operating company will seek recovery of its costs through its applicable regulatory recovery process. For further information regarding various reviews on storm response and preparedness, see “Regulatory Developments and Rate Matters — 2011 Major Storms,” in this Management’s Discussion and Analysis.

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CL&P recorded a pre-tax charge for a storm fund reserve of $30 million, in the fourth quarter of 2011, to provide bill credits to its residential customers who remained without power after noon on Saturday, November 5, 2011 as a result of the October snowstorm, and to provide contributions to certain Connecticut charitable organizations. Approximately $27 million of the storm fund reserve was used to provide a one-time credit on the February 2012 bills of approximately 192,000 CL&P customers and approximately $3 million was paid to charitable organizations in December 2011. CL&P will not seek to recover this non-recurring amount in its rates, which is approximately $17.9 million after-tax, or $0.10 per share.

For the distribution segment of our Regulated companies, a summary of changes in CL&P, PSNH and WMECO retail electric GWh sales, as well as total sales and percentage changes, and Yankee Gas firm natural gas sales and percentage changes in million cubic feet for 2011, as compared to the same period in 2010, on an actual and weather normalized basis (using a 30-year average), is as follows:

	For the Year Ended December 31, 2011 Compared to 2010
	CL&P						PSNH						WMECO						Total Electric
Electric	Percentage Decrease			Weather Normalized Percentage Decrease			Percentage Increase/ (Decrease)			Weather Normalized Percentage Increase/ (Decrease)			Percentage Decrease			Weather Normalized Percentage Decrease			Sales (GWh)			Percentage Decrease			Weather Normalized Percentage Decrease
Residential		(1.0	)%		—	%		(1.1	)%		(0.8	)%		(0.6	)%		—	%		14,766	14,913		(1.0	)%		(0.2	)%
Commercial		(2.0	)%		(0.8	)%		0.2	%		1.1	%		(1.5	)%		(0.5	)%		14,301	14,506		(1.4	)%		(0.3	)%
Industrial		(2.2	)%		(1.2	)%		(0.2	)%		1.4	%		(0.9	)%		(0.1	)%		4,418	4,481		(1.4	)%		(0.2	)%
Other		(0.8	)%		(0.8	)%		(4.3	)%		(4.3	)%		(0.6	)%		(0.6	)%		327	330		(1.0	)%		(1.0	)%
Total		(1.5	)%		(0.5	)%		(0.4	)%		0.4	%		(1.0	)%		(0.2	)%		33,812	34,230		(1.2	)%		(0.3	)%

	For the Year Ended December 31, 2011 Compared to  2010
Firm Natural Gas	Sales (million cubic feet) (1)			Percentage     Increase			Weather Normalized Percentage Increase/     (Decrease)
Residential		13,508	13,403		0.8	%		(3.2	)%
Commercial		17,175	15,137		13.5	%		9.8	%
Industrial		16,197	14,866		8.9	%		8.0	%
Total		46,880	43,406		8.0	%		5.1	%
Total, Net of Special Contracts (2)		38,197	35,038		9.0	%		5.4	%

(1) The 2010 sales volumes for commercial customers have been adjusted to conform to current year presentation.

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

Actual retail electric sales for all three electric companies were lower in 2011 compared to 2010 due primarily to milder weather in the summer of 2011, compared to warmer than normal weather in the summer of 2010. In 2011, cooling degree days in Connecticut and western Massachusetts were 20.9 percent lower than 2010, and in New Hampshire, cooling degree days were 23.7 percent lower than 2010. For WMECO, the fluctuations in retail electric sales no longer impact earnings as the DPU approved a sales decoupling plan effective February 1, 2011. Under this decoupling plan, WMECO now has an established level of baseline distribution delivery service revenues of $125.6 million that it is able to recover, which effectively breaks the relationship between kWhs consumed by customers and revenues recognized.

On a weather-normalized basis, total retail electric sales decreased slightly in 2011, as compared to 2010. We believe the weather-normalized commercial sales for CL&P and WMECO decreased in 2011, compared to 2010, due to the slow economic recovery in these service areas. PSNH commercial sales increased in 2011 due to one

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large self-generating customer who experienced multiple generation outages and relied on PSNH for energy. Industrial sales for both CL&P and WMECO decreased in 2011, compared to 2010, due in part to weak manufacturing activity in Connecticut and western Massachusetts. Our commercial and industrial electric sales continue to be negatively impacted by distributed generation and conservation programs.

Our firm natural gas sales are subject to many of the same influences as our retail electric sales, but have benefitted from migration of interruptible customers switching to firm service rates and the addition of gas-fired distributed generation in Yankee Gas’ service territory. Actual firm natural gas sales in 2011 were 8 percent higher than 2010. Colder weather, especially in the first quarter of 2011, was a contributing factor to the higher sales. Heating degree days for 2011 in Connecticut were 6.4 percent higher than 2010. On a weather normalized basis, actual firm natural gas sales in 2011 were 5.1 percent higher than 2010.

Our expense related to uncollectible receivable balances (our uncollectibles expense) is influenced by the economic conditions of our region. Fluctuations in our uncollectibles expense are mitigated from an earnings perspective because a portion of the total uncollectibles expense for each of the electric distribution companies is recovered through each company’s energy supply rate and recovered through its tariffs. Additionally, for CL&P and Yankee Gas, write-offs of uncollectible receivable balances attributable to qualified customers under financial or medical duress (hardship customers) are fully recovered through their respective tariffs. For 2011, our total pre-tax uncollectibles expense that impacts earnings was $11.7 million, as compared to $23.4 million in 2010. The improvement in 2011 uncollectibles expense was due in part to continued enhanced accounts receivable collection efforts and credit monitoring.

NU Parent and Other Companies: NU parent and other companies (which includes our competitive businesses held by NU Enterprises) recorded net expenses of $25.7 million, or $0.14 per share, in 2011, compared with earnings of $3.9 million, or $0.03 per share, in 2010. In 2011, excluding merger-related costs of $11.3 million, or $0.06 per share, NU parent and other companies recorded net expenses of $14.4 million, or $0.08 per share. In 2010, results included a non-recurring benefit of $15.7 million, or $0.09 per share, associated with the settlement of tax issues and a charge of $9.4 million, or $0.06 per share, associated with merger-related costs.

Future Outlook

We are not providing stand-alone EPS guidance in 2012 due to our pending merger with NSTAR. However, we expect that a number of key factors will negatively impact earnings in 2012 as compared with 2011. They include higher untracked Pension expense, which is expected to increase after-tax expense by approximately $15 million, higher reliability-related spending by CL&P, and a higher effective tax rate for CL&P’s transmission and distribution segments. We expect those factors to be partially offset by an expected increase in transmission rate base of more than $200 million by the end of 2012, lower NU parent interest costs, and the positive impact of distribution rate increases that were effective July 1, 2011 for CL&P and are expected to be effective on July 1, 2012 for Yankee Gas and PSNH.

Liquidity

Consolidated: Cash and cash equivalents totaled $6.6 million as of December 31, 2011, compared with $23.4 million as of December 31, 2010.

In 2011, our subsidiaries issued a total of $260 million in new long-term debt, excluding the refinancing of CL&P’s and PSNH’s PCRBs described below. On September 13, 2011, PSNH issued $160 million of first mortgage bonds that will mature on September 1, 2021 carrying a coupon rate of 3.20 percent. The net proceeds were used to repay short-term borrowings previously incurred in the ordinary course of business and for general working capital purposes. On September 16, 2011, WMECO issued $100 million of unsecured senior notes that will mature on September 15, 2021 carrying a coupon rate of 3.50 percent. The net proceeds were used to repay short-term borrowings previously incurred due largely in part to construction costs.

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On April 1, 2011, CL&P remarketed $62 million of tax-exempt secured PCRBs that were subject to mandatory tender. The PCRBs, which mature on May 1, 2031, carry a coupon rate of 1.25 percent and have a mandatory tender on April 1, 2012, at which time CL&P expects to remarket the bonds.

On May 26, 2011, PSNH issued $122 million of first mortgage bonds with a coupon rate of 4.05 percent and a maturity date of June 1, 2021, and used the proceeds to redeem $119.8 million of tax-exempt 1992 Series D and 1993 Series E PCRBs, each with a maturity date of May 1, 2021 and a coupon rate of 6 percent. The refinancing is expected to reduce PSNH’s interest costs by approximately $2.2 million in 2012.

On October 24, 2011, CL&P issued $120.5 million of PCRBs carrying a coupon of 4.375 percent that will mature on September 1, 2028, and $125 million of PCRBs carrying a coupon of 1.25 percent that mature on September 1, 2028 and are subject to mandatory tender on September 3, 2013. The proceeds of these issuances were used to refund $245.5 million of PCRBs that carried a coupon of 5.85 percent and had a maturity date of September 1, 2028. The refinancing is expected to reduce CL&P’s interest costs by approximately $7.5 million in 2012.

In 2012, in addition to remarketing the CL&P $62 million PCRBs, NU parent has a debt maturity on April 1, 2012 of $263 million, which we expect will be refinanced, and Yankee Gas has an annual sinking fund requirement of $4.3 million. Also in 2012, we expect to issue $150 million of long-term debt comprised of $100 million by WMECO and $50 million by Yankee Gas in the second half of 2012.

On November 30, 2011, the FERC granted authorization to allow CL&P to incur total short-term borrowings up to a maximum of $450 million effective January 1, 2012 through December 31, 2013. In anticipation of increasing its short-term debt availability, on February 15, 2012, CL&P filed an application with the FERC requesting authorization to increase CL&P’s total short-term borrowing capacity from a maximum of $450 million to a maximum of $600 million.

Cash flows provided by operating activities in 2011 totaled $901.1 million, compared with operating cash flows of $832.6 million in 2010 and $745 million in 2009 (all amounts are net of RRB payments, which are included in financing activities on the accompanying consolidated statements of cash flows). The improved cash flows were due primarily to the impact of the CL&P and PSNH 2010 distribution rate case decisions that were effective July 1, 2010 (the CL&P July 1, 2010 rate increase was deferred from customer bills until January 1, 2011), the WMECO distribution rate case decision that was effective February 1, 2011, and income tax refunds of $76.6 million in 2011 largely attributable to accelerated depreciation tax benefits, compared to income tax payments of $84.5 million in 2010. Offsetting these benefits was a contribution of $143.6 million made into our Pension Plan in 2011, compared to $45 million in 2010, and approximately $157 million of cash disbursements made in 2011 associated with Tropical Storm Irene and the October snowstorm. The increase in operating cash flows from 2009 to 2010 was due primarily to the absence in 2010 of costs incurred at PSNH and WMECO related to the major ice storm in December 2008 that were paid in the first quarter of 2009, a decrease in Fuel, Materials and Supplies attributable to a $31.8 million reduction in coal inventory levels at the PSNH generation business as ordered by the NHPUC, and increases in amortization on regulatory deferrals primarily attributable to 2009 activity within PSNH’s ES and CL&P’s CTA tracking mechanisms where such costs exceeded revenues resulting in an unfavorable cash flow impact in 2009. Offsetting these favorable cash flow impacts was a $45 million contribution made into our Pension Plan in September 2010.

On a stand-alone basis, 2012 cash flows provided by operating activities, net of RRB payments, are expected to be lower than in 2011 due primarily to approximately $50 million more in Pension Plan contributions than in 2011 and approximately $27 million in bill credits provided to CL&P residential customers in February 2012. In 2012, cash payments for Tropical Storm Irene and the October storm costs are estimated to be approximately $160 million, as compared to 2011 payments of approximately $157 million.

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A summary of the current credit ratings and outlooks by Moody’s, S&P and Fitch for senior unsecured debt of NU parent and WMECO and senior secured debt of CL&P and PSNH is as follows:

	Moody’s		S&P		Fitch
	Current	Outlook	Current	Outlook	Current	Outlook
NU Parent	Baa2	Stable	BBB	Watch-Positive	BBB	Watch-Positive
CL&P	A2	Stable	A-	Watch-Positive	A-	Positive
PSNH	A3	Stable	A-	Watch-Positive	A-	Stable
WMECO	Baa2	Stable	BBB+	Watch-Positive	BBB+	Stable

On April 18, 2011, Fitch raised PSNH’s senior secured rating to “A-” from “BBB+” to better reflect the firm’s notching policy for senior secured debt. On the same day, Fitch raised its outlook on CL&P to “positive” from “stable” in part to reflect improved cash flow metrics. On May 16, 2011, S&P raised all of its corporate credit ratings and debt ratings on NU and its regulated utilities by one notch due primarily to improved financial metrics at the companies. S&P maintained its Watch-Positive outlook pending consummation of NU’s merger with NSTAR. On July 14, 2011, Fitch affirmed its existing ratings and outlooks of NU parent, CL&P, PSNH and WMECO. There were no changes to Moody’s ratings or outlooks for NU or its subsidiaries in 2011.

We paid common dividends of $194.6 million in 2011, compared with $180.5 million in 2010 and $162.4 million in 2009. This reflects an increase of approximately 7.3 percent in our common dividend beginning in the first quarter of 2011. On February 14, 2012, our Board of Trustees declared a quarterly common dividend of $0.29375 per share, payable on March 30, 2012 to shareholders of record as of March 1, 2012, which equates to $1.175 per share on an annualized basis. The dividend represented an increase of 6.8 percent over the $0.275 per share quarterly dividend paid in 2011. Assuming our pending merger with NSTAR closes in 2012 after NSTAR pays its March 30, 2012 dividend of $0.45 per share, the terms of the merger agreement would require NU’s first quarterly dividend paid after the merger to be at least $0.343 per share, or at least $1.372 per share on an annualized basis.

Our ability to pay common dividends is subject to approval by our Board of Trustees and our future earnings and cash flow requirements and may be limited by state statute, the leverage restrictions in our revolving credit agreement and the ability of our subsidiaries to pay common dividends to NU parent. The Federal Power Act limits the payment of dividends by CL&P, PSNH and WMECO to their respective retained earnings balances unless a higher amount is approved by FERC; PSNH is required to reserve an additional amount of retained earnings under its FERC hydroelectric license conditions. In addition, relevant state statutes may impose additional limitations on the payment of dividends by the Regulated companies. CL&P, PSNH, WMECO and Yankee Gas also are parties to a revolving credit agreement that imposes leverage restrictions. The merger agreement requires that our first quarterly dividend per common share paid after the closing of the merger be increased to an amount that is at least equal, after adjusting for the exchange ratio, to NSTAR’s last quarterly dividend paid prior to the closing. We do not expect the restrictions will prevent NU from meeting its obligations under the merger agreement.

In 2011, CL&P, PSNH, WMECO, and Yankee Gas paid $243.2 million, $58.8 million, $26.3 million, and $38.2 million, respectively, in common dividends to NU parent. In 2011, NU parent made equity contributions to CL&P, PSNH, WMECO, and Yankee Gas of $6.7 million, $120 million, $91.8 million, and $8.5 million, respectively.

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Cash capital expenditures included on the accompanying consolidated statements of cash flows and described in this “Liquidity” section do not include amounts incurred on capital projects but not yet paid, cost of removal, AFUDC related to equity funds, and the capitalized portions of pension and PBOP expense or income. A summary of our cash capital expenditures by company for the years ended December 31, 2011, 2010, and 2009 is as follows:

	For the Years Ended December 31,
(Millions of Dollars)	2011		2010		2009
CL&P	$	424.9	$	380.3	$	435.7
PSNH		241.8		296.3		266.4
WMECO		238.0		115.2		105.4
Yankee Gas		98.2		82.5		54.8
NPT		24.9		7.5		—
Other		48.9		72.7		45.8
Total	$	1,076.7	$	954.5	$	908.1

The increase in our cash capital expenditures was the result of higher transmission segment cash capital expenditures of $150.6 million, primarily at WMECO and NPT, as well as higher capital expenditures at Yankee Gas related to the WWL Project.

Proceeds from Sale of Assets in 2011 of $46.8 million included on the accompanying consolidated statement of cash flows related to the sale of certain CL&P transmission assets. For further information, see “Business Development and Capital Expenditures — Transmission Segment — Other” in this Management’s Discussion and Analysis.

As of December 31, 2011, NU parent had $17.9 million of LOCs issued for the benefit of certain subsidiaries (including $4 million for CL&P and $5.4 million for PSNH) and $256 million of short-term borrowings outstanding under its $500 million unsecured revolving credit facility. The weighted-average interest rate on these short-term borrowings as of December 31, 2011 was 2.2 percent, based on a variable rate plus an applicable margin based on NU parent’s credit ratings. NU parent had $226.1 million of borrowing availability on this facility as of December 31, 2011.

CL&P, PSNH, WMECO, and Yankee Gas are parties to a joint unsecured revolving credit facility in a nominal aggregate amount of $400 million. As of December 31, 2011, CL&P and Yankee Gas had short-term borrowings outstanding under this facility of $31 million and $30 million, respectively, leaving $339 million of aggregate borrowing capacity available. The weighted-average interest rate on these short-term borrowings as of December 31, 2011 was 3.1 percent (4.03 percent for CL&P), which is based on a variable rate plus an applicable margin based on CL&P and Yankee Gas’ respective credit ratings.

We will continue to monitor availability of our credit facilities to assure that we have an adequate borrowing capacity.

Our credit facilities and indentures require that NU parent and certain of its subsidiaries, including CL&P, PSNH and WMECO, comply with certain financial and non-financial covenants as are customarily included in such agreements, including a consolidated debt to total capitalization ratio. As of December 31, 2011, all such companies were in compliance with these covenants. Refer to Note 8, “Short-Term Debt,” and Note 9, “Long-Term Debt,” to our consolidated financial statements included in this Annual Report for further discussion of material terms and conditions of these agreements.

Business Development and Capital Expenditures

Consolidated: Our consolidated capital expenditures, including amounts incurred but not paid, cost of removal, AFUDC, and the capitalized portions of pension and PBOP expense or income (all of which are

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non-cash factors), totaled $1.2 billion in 2011, $1 billion in 2010, and $969.2 million in 2009. These amounts included $51.9 million in 2011, $68.7 million in 2010, and $52.7 million in 2009 related to our corporate service companies, NUSCO and RRR.

Regulated Companies: Capital expenditures for the Regulated companies totaled $1.2 billion ($467.2 million for CL&P, $291.7 million for PSNH, and $290.3 million for WMECO) in 2011.

Transmission Segment: Transmission segment capital expenditures increased by $198.5 million in 2011, as compared with 2010, due primarily to increases at WMECO related to the construction of GSRP. A summary of transmission segment capital expenditures by company in 2011, 2010 and 2009 is as follows:

	For the Years Ended December 31,
(Millions of Dollars)	2011		2010		2009
CL&P	$	128.6	$	107.2	$	163.0
PSNH		68.1		49.1		59.4
WMECO		236.8		95.2		67.7
NPT		25.9		9.4		1.7
Totals	$	459.4	$	260.9	$	291.8

NEEWS: GSRP, a project that involves the construction of 115 KV and 345 KV overhead lines from Ludlow, Massachusetts to Bloomfield, Connecticut, is the first, largest and most complicated project within the NEEWS family of projects. On September 13, 2011, CL&P and WMECO received the required permit from U.S. Army Corps of Engineers allowing them to commence full construction on GSRP. The $718 million project is expected to be placed in service in late 2013. As of December 31, 2011, the project was approximately 50 percent complete.

The Interstate Reliability Project, which includes CL&P’s construction of an approximately 40-mile, 345 KV overhead line from Lebanon, Connecticut to the Connecticut-Rhode Island border in Thompson, Connecticut where it will connect to transmission enhancements being constructed by National Grid, is our second major NEEWS project. In August 2010, ISO-NE reaffirmed the need for the Interstate Reliability Project, which we expect to place in service in late 2015 at a cost of $218 million. On December 23, 2011, CL&P filed a siting application with the Connecticut Siting Council to build the Connecticut section of the Interstate Reliability Project. In early 2012, National Grid is expected to file siting applications with regulators in Massachusetts and Rhode Island to build its sections of the project. The late 2015 expected in-service date assumes that all siting application approvals will be received from all three states in late 2013 with construction commencing in late 2013 or early 2014.

The Central Connecticut Reliability Project, which involves construction of a $301 million new 345 KV overhead line from Bloomfield, Connecticut to Watertown, Connecticut, is the third major part of NEEWS. In March 2011, ISO-NE announced that it would review the Central Connecticut Reliability Project along with other central Connecticut projects as part of a study known as the Greater Hartford Central Connecticut Study. We expect ISO-NE to issue preliminary need results and transmission solutions in 2013.

Included as part of NEEWS are costs for associated reliability related projects, all of which have received siting approval and most of which are under construction. These projects began going into service in 2010 and will continue to go into service through 2013.

Through December 31, 2011, CL&P and WMECO had capitalized $132.6 million and $334.7 million, respectively, in costs associated with NEEWS, of which $33.9 million and $197.8 million, respectively, were capitalized in 2011. The total expected cost of NU’s share of NEEWS is approximately $1.3 billion, of which $646 million and $616 million relate to CL&P and WMECO, respectively.

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On May 27, 2011, the FERC issued an order accepting CL&P’s and WMECO’s filing requesting changes to the ISO-NE Tariff in order to include 100 percent of the NEEWS CWIP in regional rate base effective June 1, 2011. As a result of this order, CL&P and WMECO ceased accruing AFUDC on NEEWS CWIP as of June 1, 2011, and NU’s local customers will receive appropriate credits for the return on CWIP they have paid.

Northern Pass: On October 4, 2010, NPT and Hydro Renewable Energy, a subsidiary of HQ, entered into a TSA in connection with the Northern Pass transmission project, which will be constructed by NPT. Northern Pass is a planned HVDC transmission line from the Québec-New Hampshire border to Franklin, New Hampshire and an associated alternating current radial transmission line between Franklin and Deerfield, New Hampshire. Northern Pass will interconnect at the Québec-New Hampshire border with a planned HQ HVDC transmission line.

Under the terms of the TSA, which was accepted by the FERC without modification in February 2011, NPT will sell to HQ affiliate Hydro Renewable Energy 1,200 MW of firm electric transmission rights over the Northern Pass for a 40-year term and charge cost-based rates. The projected cost-of-service calculation includes an ROE of 12.56 percent through the construction phase of the project, and during commercial operation, an ROE equal to the ISO-NE regional rates base ROE (currently 11.14 percent) plus 1.42 percent. The TSA rates will be based on a capital structure for NPT of 50 percent debt and 50 percent equity. During the development and the construction phases under the TSA, NPT will be recording non-cash AFUDC earnings.

In October 2010, NPT filed the Northern Pass project design with ISO-NE for technical approval and filed a presidential permit application with the DOE, which seeks permission to construct and maintain facilities that cross the U.S.-Canada border in New Hampshire and connect to HQ TransÉnergie’s facilities in Québec. The DOE held seven meetings in New Hampshire in mid-March 2011 seeking public comment. In response to concerns raised at these meetings, NPT revised its application to request additional time during the public comment period to allow NPT to review alternative routes. On June 15, 2011, the DOE extended the scoping comment period for at least forty-five days after NPT files an alternative route with the DOE. Certain environmental studies will need to be completed in order to obtain DOE permits. We expect construction to begin in 2014 and the project to be completed in the fourth quarter of 2016.

On February 8, 2012, the New Hampshire legislature passed a bill that could potentially prohibit the use of eminent domain for the development of any “non-reliability” electric transmission projects, such as Northern Pass. The bill is currently awaiting action by the New Hampshire Governor. We are reviewing the potential impact of the bill on NPT, should it be enacted, including its effect on the project’s route, cost and schedule. We believe that NPT will be able to acquire the necessary rights along an acceptable route, which would make it feasible to construct the project even if the bill is enacted. Given the ultimate design needs of the project, along with siting and permit requirements, which will vary depending upon the route ultimately selected, there is a possibility for further delay in commencement of construction.

We currently estimate that NU’s 75 percent share of the costs of the Northern Pass transmission project will be approximately $830 million and NSTAR’s 25 percent share of the costs of the Northern Pass transmission project will be approximately $280 million, for a combined total expected cost of approximately $1.1 billion (including capitalized AFUDC). Through December 31, 2011, we capitalized $37 million in costs associated with NPT.

Other: On May 31, 2011, CL&P and the Connecticut Transmission Municipal Electric Energy Cooperative (CTMEEC), a non-profit municipal joint action transmission entity formed by several Connecticut municipal electric utilities, completed the sale by CL&P to CTMEEC of a segment of high voltage transmission lines built by CL&P in the town of Wallingford, Connecticut. The assets were sold at their net book value of $42.5 million, plus reimbursement of closing costs. CL&P is operating and maintaining the lines under an operations and maintenance agreement with CTMEEC. The transaction did not include the transfer of land or equipment not related to electric transmission service. The transaction did not impact our five-year capital plan and is already reflected in CL&P’s transmission rate base forecasts.

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Distribution Segment: A summary of distribution segment capital expenditures by company for 2011, 2010 and 2009 is as follows:

	For the Years Ended December 31,
(Millions of Dollars)	2011		2010		2009
CL&P:
Basic Business	$	166.6	$	126.2	$	104.6
Aging Infrastructure		112.3		104.0		104.1
Load Growth		59.6		75.2		74.3
Total CL&P		338.5		305.4		283.0
PSNH:
Basic Business		47.7		41.2		55.5
Aging Infrastructure		25.3		19.5		17.8
Load Growth		25.8		23.1		25.5
Total PSNH		98.8		83.8		98.8
WMECO:
Basic Business		24.2		17.5		21.5
Aging Infrastructure		11.5		10.5		12.2
Load Growth		6.1		5.1		4.0
Total WMECO		41.8		33.1		37.7
Total — Electric Distribution (excluding Generation)		479.1		422.3		419.5
Yankee Gas		102.8		94.6		59.6
Other		1.0		2.0		0.6
Total Distribution		582.9		518.9		479.7
PSNH Generation:
Clean Air Project		101.1		149.7		119.3
Other		23.7		27.4		25.7
Total PSNH Generation		124.8		177.1		145.0
WMECO Generation		11.7		10.1		—
Total Distribution Segment	$	719.4	$	706.1	$	624.7

For the electric distribution business, basic business includes the relocation of plant, the purchase of meters, tools, vehicles, and information technology. Aging infrastructure relates to the planned replacement of overhead lines, plant substations, transformer replacements, and underground cable replacement. Load growth includes requests for new business and capacity additions on distribution lines and substation overloads.

The Clean Air Project is a wet scrubber project that PSNH constructed and placed in service at its Merrimack Station in September 2011, the cost of which will be recovered through PSNH’s ES rates under New Hampshire law. By November 2011, both of Merrimack Station’s coal-fired units were integrated with the scrubber, which is reducing emissions from the units. We expect finalization of project activities, including water discharge enhancements, in mid-2012 at a cost of approximately $422 million.

On August 12, 2009, the DPU authorized WMECO to install up to 6 MW of solar energy generation in its service territory at an estimated cost of $41 million by the end of 2012. In October 2010, WMECO completed development of a 1.8 MW solar generation facility on a site in Pittsfield, Massachusetts. The full cost of this project was $9.4 million. In December 2011, WMECO completed development of a 2.3 MW solar generation facility on a 12-acre brownfield site in Springfield, Massachusetts. The full cost of the Springfield project was $11.4 million. WMECO is continuing its evaluation of sites suitable for development of the remaining 1.9 MW of the authorized 6 MW of capacity.

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Yankee Gas’ WWL Project, a 16-mile natural gas pipeline between Waterbury and Wallingford, Connecticut and the increase of vaporization output of its LNG plant, was placed in service in November 2011. Project costs totaled approximately $54 million, $3.6 million below the previous estimate of $57.6 million. Pursuant to the June 29, 2011 rate case decision, the WWL Project was included in Yankee Gas’ rate base upon entering service. Projected Capital Expenditures and Rate Base Estimates: Excluding the impacts of the pending merger with NSTAR, a summary of the projected capital expenditures for the Regulated companies’ electric transmission segment and their distribution segment (including generation) by company for 2012 through 2016, including our corporate service companies’ capital expenditures on behalf of the Regulated companies, is as follows:

	Year
(Millions of Dollars)	2012		2013		2014		2015		2016		2012-2016 Total
CL&P Transmission	$	174	$	108	$	255	$	245	$	55	$	837
PSNH Transmission		66		125		142		94		41		468
WMECO Transmission		193		132		111		73		1		510
NPT		40		22		178		238		334		812
Subtotal Transmission	$	473	$	387	$	686	$	650	$	431	$	2,627
CL&P Distribution:
Basic Business	$	129	$	121	$	113	$	114	$	112	$	589
Aging Infrastructure		119		101		88		90		92		490
Load Growth		67		63		73		67		72		342
Total CL&P Distribution		315		285		274		271		276		1,421
PSNH Distribution:
Basic Business		52		49		49		50		48		248
Aging Infrastructure		29		24		28		26		25		132
Load Growth		31		37		33		40		39		180
Total PSNH Distribution		112		110		110		116		112		560
WMECO Distribution:
Basic Business		17		16		18		18		19		88
Aging Infrastructure		15		16		16		16		16		79
Load Growth		7		7		6		6		6		32
Total WMECO Distribution		39		39		40		40		41		199
Subtotal Electric Distribution	$	466	$	434	$	424	$	427	$	429	$	2,180
PSNH Generation:
Clean Air Project	$	21	$	2	$	—	$	—	$	—	$	23
Other		13		26		29		34		34		136
Total PSNH Generation		34		28		29		34		34		159
CL&P Generation		11		23		11		—		—		45
WMECO Generation		19		10		10		10		—		49
Subtotal Generation	$	64	$	61	$	50	$	44	$	34	$	253
Yankee Gas Distribution:
Basic Business	$	26	$	27	$	28	$	29	$	30	$	140
Aging Infrastructure		48		50		50		52		53		253
Load Growth		20		46		47		35		23		171
Total Yankee Gas Distribution	$	94	$	123	$	125	$	116	$	106	$	564
Corporate Service Companies	$	44	$	52	$	36	$	30	$	29	$	191
Total	$	1,141	$	1,057	$	1,321	$	1,267	$	1,029	$	5,815

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Actual capital expenditures could vary from the projected amounts for the companies and periods above. Economic conditions in the northeast could impact the timing of our major capital expenditures. Most of these capital expenditure projections, including those for NPT, assume timely regulatory approval, which in most cases requires extensive review. The amounts above assume that we receive favorable responses from regulators to our proposed capital program and that our major transmission initiatives, some of which have not yet been filed with regulators, are approved in a timely manner. Delays in or denials of those approvals could reduce the levels of expenditures and associated rate base.

Based on the 2011 actual and 2012 through 2016 projected capital expenditures, the 2011 actual and 2012 through 2016 projected transmission, distribution and generation rate base as of December 31 of each year are as follows:

	Year
	2011		2012		2013		2014		2015		2016
(Millions of Dollars)
CL&P Transmission	$	2,100	$	2,149	$	2,091	$	2,211	$	2,424	$	2,450
PSNH Transmission		390		407		524		654		707		721
WMECO Transmission		467		615		722		747		853		814
NPT		—		—		—		—		—		804
Total Transmission		2,957		3,171		3,337		3,612		3,984		4,789
CL&P Distribution		2,603		2,726		2,826		2,932		3,019		3,114
PSNH Distribution		836		888		959		1,008		1,065		1,108
WMECO Distribution		423		434		442		446		451		455
Total Electric Distribution		3,862		4,048		4,227		4,386		4,535		4,677
CL&P Generation		—		9		29		35		31		28
PSNH Generation		759		726		683		673		663		652
WMECO Generation		18		31		37		43		48		43
Total Generation		777		766		749		751		742		723
Yankee Gas Distribution		754		771		812		866		987		1,042
Total	$	8,350	$	8,756	$	9,125	$	9,615	$	10,248	$	11,231

Transmission Rate Matters and FERC Regulatory Issues

CL&P, PSNH and WMECO and most other New England utilities, generation owners and marketers are parties to a series of agreements that provide for coordinated planning and operation of the region’s generation and transmission facilities and the rules by which these parties participate in the wholesale markets and acquire transmission services. Under these arrangements, ISO-NE, a non-profit corporation whose board of directors and staff are independent from all market participants, serves as the regional transmission organization for New England. ISO-NE works to ensure the reliability of the New England transmission system, administers the independent system operator tariff, subject to FERC approval, oversees the efficient and competitive functioning of the regional wholesale power market and determines the portion of the costs of our major transmission facilities that are regionalized throughout New England.

Transmission — Wholesale Rates: Our transmission rates recover our total transmission revenue requirements, ensuring that we recover all regional and local revenue requirements for providing transmission service. These rates provide for annual reconciliations to actual costs. The difference between billed and actual costs is deferred for future recovery from, or refund to, customers. As of December 31, 2011, we were in a total net overrecovery position of $31.4 million, which will be refunded to customers in June 2012. Of this amount, the transmission segments of CL&P, PSNH and WMECO were in an overrecovery position of $18.6 million, $1.7 million and $11.1 million, respectively.

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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 the 50 basis points for joining the 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. On June 28, 2011, FERC denied a motion by several New England states to reconsider the financial incentives FERC had granted the vast majority of NEEWS investments in 2008. Those incentives include an incremental 125-basis points to FERC’s base New England transmission ROE, cash recovery of earnings and interest on NEEWS investments while the projects are under construction, and recovery of prudently incurred costs on projects that are abandoned.

FERC Base ROE Complaint: 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 New England transmission owners, including CL&P, PSNH and WMECO, is unjust and unreasonable. The complainants asserted that the current 11.14 percent rate, which became effective in 2006, is excessive due to changes in the capital markets and are seeking an order to reduce the rate to 9.2 percent, effective September 30, 2011.

On October 20, 2011, the New England transmission owners responded to the complaint, asking FERC to dismiss the complaint on the basis that the complainants failed to carry their burden of proof under Section 206 of the Federal Power Act to demonstrate that the existing base ROE is unjust and unreasonable. The New England transmission owners included testimony and analysis reflecting a base ROE of 11.2 percent using FERC’s methodology and precedents, which they believe demonstrates that the current base ROE of 11.14 percent remains just and reasonable.

As of December 31, 2011, CL&P, PSNH, and WMECO had approximately $1.5 billion of aggregate shareholder equity invested in their transmission facilities. As a result, each 10 basis point change in the authorized base ROE would change annual consolidated earnings by an approximate $1.5 million.

Although additional testimony was submitted by the complainants and the New England transmission owners in November and December 2011, the FERC has not yet issued an order in this proceeding and we cannot predict when this proceeding will be concluded, the outcome of this proceeding, or its impact on our financial position, results of operations or cash flows.

Legislative Matters

2010 and 2011 Connecticut Legislation: In May 2010, the Connecticut Legislature approved a state budget for the 2011 fiscal year, which called for the assessment of an Economic Transition Charge to electric utility customers and the issuance by the state of Connecticut of up to $760 million of economic recovery revenue bonds that would be repaid over eight years through additional charges on electric utility customer bills. On September 29, 2010, the PURA approved a financing order for the bonds, but due primarily to legal challenges the bonds were never issued. On June 21, 2011, Governor Malloy signed legislation approving the state budget for the 2012 fiscal year that revoked the authorization for the state to issue the economic recovery revenue bonds. As a result of this change in legislation, as of July 1, 2011 CL&P customer bills do not include the charge associated with the economic recovery revenue bonds of approximately $0.0038 per kWh.

On July 1, 2011, Governor Malloy signed legislation that consolidated oversight of state energy and environmental activities into the DEEP. Effective July 1, 2011, the DPUC was replaced by PURA, which is part of the DEEP. The five commissioners of the DPUC were replaced by three directors of PURA. PURA regulates Connecticut utility rates and terms of service and oversees certain safety standards of the state’s utilities, but various policy responsibilities, including the state’s Integrated Resource Plan, have been assumed by a separate

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division within DEEP. The legislation also authorized the state’s electric distribution companies, including CL&P, to build up to 10 MW of renewable generation, and authorized DEEP to study the potential for increased natural gas usage in Connecticut, including usage as a transportation fuel.

2011 New Hampshire Legislation: On March 30, 2011, the New Hampshire House of Representatives approved House Bill 648, which would preclude companies constructing non-reliability projects, such as Northern Pass, from using eminent domain to acquire property for construction of such projects. On June 2, 2011, the New Hampshire Senate voted to send House Bill 648 back to the Senate Judiciary Committee for further study. On December 8, 2011, the Senate Judiciary Committee endorsed a number of changes to the state’s eminent domain legislation, but those changes did not include a ban on using eminent domain for non-reliability projects. On February 8, 2012, the New Hampshire legislature passed a bill that could potentially prohibit the use of eminent domain for development of any “non-reliability” electric transmission projects, such as Northern Pass. The bill is currently awaiting action by the New Hampshire Governor. For further information regarding the impacts to NPT, see “Business Development and Capital Expenditures — Transmission Segment — Northern Pass” in this Management’s Discussion and Analysis.

Regulatory Developments and Rate Matters

Regulatory Approvals for Pending Merger with NSTAR:

Federal: On February 10, 2012, the applicable Hart-Scott-Rodino waiting period expired. On December 21, 2011, the Federal Communications Commission extended its approval until July 7, 2012. On July 6, 2011, FERC issued its approval of the merger. On December 20, 2011, the Nuclear Regulatory Commission issued two orders approving the indirect transfer of control of the operating licenses for Yankee Nuclear Power Station and Haddam Neck Plant held by YAEC and CYAPC, which will be effected upon the merger of NU and NSTAR.

Massachusetts: On November 24, 2010, NU and NSTAR filed a joint petition requesting the DPU’s approval of our pending merger. On March 10, 2011, the DPU issued an order that modified the standard of review to be applied in the review of mergers involving Massachusetts utilities from a “no net harm” standard to a “net benefits” standard, meaning that the companies must demonstrate that the pending transaction provides benefits that outweigh the costs. NU and NSTAR filed supplemental testimony and a net benefit analysis with the DPU on April 8, 2011, estimating post-transaction net savings of approximately $780 million in the first 10 years following the closing of the merger and other customer benefits. An effective date for the merger of October 1, 2011 was used in the development of the net benefit study that was filed with the DPU. Evidentiary hearings began July 6, 2011 and concluded on July 28, 2011. Briefs in the case were filed with the DPU in September and October 2011.

On July 15, 2011, the DOER filed a motion to stay the proceedings. On July 21, 2011, NU and NSTAR filed a response objecting to this motion. The DPU originally scheduled oral arguments for November 4, 2011 regarding the motion, which were further postponed during the fourth quarter of 2011 while NU, NSTAR and other parties made attempts to narrow and discuss the issues presented by the motion to stay. On January 6, 2012, oral arguments on the motion to stay were conducted. On February 15, 2012, NU and NSTAR reached comprehensive merger-related settlement agreements with both the Massachusetts Attorney General and the DOER. The first settlement agreement was reached with both the Attorney General and the DOER and covers a variety of rate-making and rate design issues, including a distribution rate freeze until 2016 for WMECO, NSTAR Electric Company and NSTAR Gas Company. The second settlement agreement was reached with the DOER and covers a variety of matters impacting the advancement of Massachusetts clean energy goals established by the Green Communities Act and Global Warming Solutions Act. Pursuant to the terms and provisions of the settlement agreements, all parties agree that the proposed merger between NU and NSTAR is consistent with the public interest and should be approved by the DPU. However, the settlement agreements allow the Attorney General and DOER to terminate their respective agreements for any reason at any time prior to approval by the DPU. All parties to the settlement agreements have requested that the DPU approve the merger on April 4, 2012.

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Connecticut: In December 2010, the Connecticut Office of Consumer Counsel, supported by the Connecticut Attorney General, petitioned the DPUC (now PURA) to reconsider its earlier view from November 2010 that it lacked jurisdiction. On June 1, 2011, the PURA issued a decision stating that it lacked jurisdiction over the merger. On June 30, 2011, the Office of Consumer Counsel filed an appeal of the PURA’s final decision. NRG Energy, Inc. (NRG) and the New England Power Generators Association (NEPGA) filed similar appeals in July 2011 and filed petitions with the Connecticut Superior Court in July 2011, each requesting a declaratory ruling that the PURA has jurisdiction over the merger. On January 18, 2012, the PURA issued a final decision in which it revised its earlier declaratory ruling of June 1, 2011 that concluded it did not have jurisdiction to review the pending merger between NU and NSTAR. The final decision ruled that NU and NSTAR must now seek approval from PURA pursuant to Connecticut state law prior to completing the merger. As a result, on January 19, 2012, NU and NSTAR filed with PURA an application for approval of the merger. PURA is scheduled to issue a final decision on April 2, 2012.

If both the DPU and PURA issue acceptable decisions by such dates, we expect the merger will be consummated by April 16, 2012.

New Hampshire: On April 5, 2011, the NHPUC issued an order concluding that it does not have jurisdiction over the merger.

Maine: On May 10, 2011, the Maine Public Utilities Commission approved the merger, subject to FERC approval, which was received on July 6, 2011.

Federal:

EPA Air Toxic Standard: On December 16, 2011, the EPA issued the Mercury and Air Toxic Standards, a rule that establishes emission limits for hazardous air pollutants, including mercury and arsenic, from new and existing coal- and oil-fired electric generating units. The standards are the first to implement a nationwide emissions standard for hazardous air pollutants across all electric generating units, providing utility companies up to five years to meet the requirements. PSNH owns and operates approximately 1,000 MW of fossil fuel electric generating units, subject to these standards, including the Merrimack, Newington and Schiller stations. We believe the Clean Air Project at our Merrimack Station, along with existing equipment, enables that facility to meet at least the minimum requirements in the standards. A review of the potential impact of this rule on PSNH’s other generating units is not yet complete. However, PSNH believes that the work it has undertaken in recent years to comply with New Hampshire state regulations, including the Clean Air Project, will allow it to meet the new EPA Mercury and Air Toxic Standards without significant additional investment.

EPA Proposed NPDES Permit: PSNH maintains a NPDES permit consistent with requirements of the Clean Water Act for Merrimack Station. In 1997, PSNH filed in a timely manner for a renewal of this permit. As a result, the existing permit was administratively continued. On September 29, 2011, the EPA issued a draft renewal NPDES permit for PSNH’s Merrimack Station for public review and comment. The proposed permit contains many significant conditions to future operation. The proposed permit would require PSNH to install a closed-cycle cooling system (including cooling towers) at the station. The EPA estimated that the net present value cost to install this system and operate it over a 20-year period would be approximately $112 million.

On October 27, 2011, the EPA extended the initial 60-day period for public review and comment on the draft permit for an additional 90 days until February 28, 2012. The EPA does not have a set deadline to consider comments and to issue a final permit. Given the complex and unprecedented nature of many of the requirements, extensive comments to the EPA on the draft permit are anticipated from within the utility industry as well as from various environmental groups. Merrimack Station is permitted to continue to operate under its present permit pending issuance of the final permit and subsequent resolution of matters appealed by PSNH and other parties. Due to the site specific characteristics of PSNH’s other fossil generating stations, we believe it is unlikely that they would have similar permit requirements imposed on them.

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2011 Major Storms:

On June 1, 2011, a series of severe thunderstorms with high winds, including tornadoes, struck portions of WMECO’s service territory. Approximately 17,000 WMECO electric distribution customers were without power. On June 9, 2011, another series of severe thunderstorms with high winds struck CL&P, PSNH and WMECO’s service territories, resulting in power outages for approximately 260,000 electric distribution customers, including 210,000 at CL&P.

On August 28, 2011, Tropical Storm Irene caused extensive damage to our distribution system. Approximately 800,000 of our 1.9 million electric distribution customers were without power at the peak of the outages, with approximately 670,000 of those customers in Connecticut.

On October 29, 2011, an unprecedented storm inundated our service territory with heavy snow causing significant damage to our distribution and transmission systems. Approximately 1.2 million of our electric distribution customers were without power at the peak of the outages, with 810,000 of those customers in Connecticut, 237,000 in New Hampshire, and 140,000 in Massachusetts. In terms of customer outages, this was the most severe storm in CL&P’s history, surpassing Tropical Storm Irene; the third most severe in PSNH’s history, following a December 2008 ice storm and a February 2010 wind storm; and the most severe in WMECO’s history.

CL&P recorded a pre-tax charge for a storm fund reserve of $30 million to provide bill credits to its residential customers who remained without power after noon on Saturday, November 5, 2011 as a result of the October snowstorm, and to provide contributions to certain Connecticut charitable organizations. CL&P will not seek to recover this amount in its rates.

The magnitude of the storms’ costs and damages met the criteria for cost deferral in Connecticut, New Hampshire, and Massachusetts and as a result, except for the CL&P storm fund reserve, the storms had no material impact on the results of operations of CL&P, PSNH and WMECO. We believe our response to all storms was prudent and therefore we believe it is probable that CL&P, PSNH and WMECO will be allowed to recover these storm costs. Each operating company will seek recovery of its estimated deferred storm costs through its applicable regulatory recovery process.

Officials in Connecticut, New Hampshire and Massachusetts have all initiated inquiries into their state’s utilities’ response to the October snowstorm, including CL&P, PSNH and WMECO. In addition, the PURA has included a review of the utilities’ responses during Tropical Storm Irene and hired a consultant for the purposes of conducting a management audit into the emergency response programs of CL&P. These inquiries are expected to be completed in the second quarter of 2012. Connecticut Governor Malloy appointed a panel to review the preparedness of numerous state entities, including the state’s utilities, in the event of a category 3 hurricane. This panel made its recommendations on January 9, 2012. Governor Malloy also hired Witt Associates to provide an independent assessment of the state’s and CL&P’s preparedness, response and restoration efforts during the October snowstorm. The Witt Associates’ Final Report was issued on December 1, 2011. Numerous committees of the Connecticut General Assembly also held hearings covering all aspects of storm response in the state. No official report is expected from these committees. We are currently evaluating several long-term initiatives to address the findings and recommendations of the panel and Witt Associates’ Final Report. We believe that, if adopted, the future costs associated with these new long-term initiatives will be recovered from customers.

Connecticut — CL&P:

AMI: On August 29, 2011, PURA issued a draft decision rejecting the full deployment of AMI meters to all of CL&P’s customers at that time. PURA instead indicated that CL&P should begin installing AMI meters at a more moderate pace once industry standards are developed and CL&P has selected a specific technology to install. On September 2, 2011, the Commissioner of DEEP filed a motion with PURA to suspend the proceeding

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while the Bureau of Energy and Technology Policy conducts a process to establish an AMI policy for Connecticut, in accordance with the state law. On September 8, 2011, PURA granted DEEP’s motion and suspended its proceedings. No further schedule is available at this time from either DEEP or PURA. As a result, CL&P has removed the projected AMI capital costs of approximately $257 million from its current five-year capital program.

Standard Service and Last Resort Service Rates: CL&P’s residential and small commercial customers who do not choose competitive suppliers are served under SS rates, and large commercial and industrial customers who do not choose competitive suppliers are served under LRS rates. CL&P is fully recovering from customers the costs of its SS and LRS services. Effective January 1, 2012, the PURA approved a decrease to CL&P’s total average SS rate of approximately 8 percent and an increase to CL&P’s total average LRS rate of approximately 10.6 percent. The energy supply portion of the total average SS rate decreased from 9.732 cents per kWh to 8.443 cents per kWh while the energy supply portion of the total average LRS rate increased from 7.202 cents per kWh to 8.605 cents per kWh.

CTA and SBC Reconciliation and Rates: On March 31, 2011, CL&P filed with the PURA its 2010 CTA and SBC reconciliation, which compared CTA and SBC revenues to revenue requirements. For the 12 months ended December 31, 2010, total CTA revenue requirements exceeded CTA revenues by $4.5 million. For the 12 months ended December 31, 2010, the SBC revenues exceeded SBC revenue requirements by $19.8 million. On October 12, 2011, PURA approved the 2010 CTA and SBC reconciliations as filed. The decision allowed a CTA rate, effective January 1, 2012, that would recover $26.1 million during 2012, and requires CL&P to provide updated actual and projected costs when it files its requested rate adjustments for January 1, 2012. The decision also allowed an SBC rate, effective January 1, 2012, that would collect $23.7 million during 2012.

On December 22, 2011, PURA approved new CTA and SBC rates, effective January 1, 2012, using updated information provided by CL&P. Based on that updated information, the CTA rate will decrease from 0.332 cents per kWh to 0.128 cents per kWh, and the SBC will increase from 0.037 cents per kWh to 0.143 cents per kWh.

FMCC Filing: On February 4, 2011, CL&P filed with the PURA its semi-annual filing, which reconciled actual FMCC revenues and charges and GSC revenues and expenses, for the period July 1, 2010 through December 31, 2010, and also included the previously filed revenues and expenses for the January 1, 2010 through June 30, 2010 period. The filing identified a total net overrecovery of $0.3 million, which includes the remaining uncollected or non-refunded portions from previous filings. A hearing was held during the second quarter of 2011 and on June 29, 2011, the PURA issued a final decision accepting CL&P’s calculations of GSC, bypassable FMCC and nonbypassable FMCC revenues and expenses for the period July 1, 2010 through December 31, 2010. On August 1, 2011, CL&P filed with the PURA its semi-annual FMCC filing for the period January 1, 2011 through June 30, 2011. The filing identified a total net overrecovery of $10.9 million for the period, which includes the remaining uncollected or non-refunded portions from previous filings. A hearing was held during the fourth quarter of 2011 and on December 28, 2011, the PURA issued a final decision accepting CL&P’s calculations of GSC, bypassable FMCC and nonbypassable FMCC actual revenues and expenses for the six months reviewed in the proceeding. On February 2, 2012, CL&P filed with the PURA its semi-annual FMCC filing for the period July 1, 2011 through December 31, 2011, and also included the previously filed revenues and expenses for the January 1, 2011 through June 30, 2011 period. The filing identified a total net overrecovery of $18.7 million, which includes the remaining uncollected or non-refunded portions from previous filings. PURA has not yet set a schedule to review this filing, but we do not expect the outcome of the PURA’s review to have a material adverse impact on CL&P’s financial position, results of operations or cash flows.

Procurement Fee Rate Proceedings: In prior years, CL&P submitted to the PURA its proposed methodology to calculate the variable incentive portion of its transition service procurement fee, which was effective for the years 2004, 2005 and 2006, and requested approval of the pre-tax $5.8 million 2004 incentive fee. CL&P has not recorded amounts related to the 2005 and 2006 procurement fee in earnings. CL&P recovered the $5.8 million pre-tax amount, which was recorded in 2005 earnings, through a CTA reconciliation process. On

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January 15, 2009, the PURA issued a final decision in this docket reversing its December 2005 draft decision and stated that CL&P was not eligible for the procurement incentive compensation for 2004. A $5.8 million pre-tax charge (approximately $3.5 million net of tax) was recorded in the 2008 earnings of CL&P, and an obligation to refund the $5.8 million to customers was established as of December 31, 2008. CL&P filed an appeal of this decision on February 26, 2009. On February 4, 2010, the Connecticut Superior Court reversed the PURA decision. The Court remanded the case back to the PURA for the correction of several specific errors. On February 22, 2010, the PURA appealed the Connecticut Superior Court’s February 4, 2010 decision to the Connecticut Appellate Court, which then transferred the appeal to the Connecticut Supreme Court. A decision is expected from the Connecticut Supreme Court in the second half of 2012.

Connecticut — Yankee Gas:

Distribution Rates: On June 29, 2011, PURA issued a final decision in the Yankee Gas rate proceeding that it amended on September 28, 2011. The final decision approved a regulatory ROE of 8.83 percent, based on a capital structure of 52.2 percent common equity and 47.8 percent debt, approved Yankee Gas’ WWL Project, and also allowed for an increase for bare steel and cast iron pipe annual replacement funding, as requested by Yankee Gas. The changes were effective July 20, 2011 and will have the effect of decreasing revenues by $0.2 million for the twelve months ending June 30, 2012 and increasing revenues by $6.9 million for the twelve months ending June 30, 2013.

New Hampshire:

Distribution Rates: In March 2011, PSNH filed with the NHPUC to collect certain exogenous costs, step increases, and storm costs, as permitted by its 2010 rate case settlement. These rate increases were offset by the scheduled termination, on June 30, 2011, of a rate recoupment charge, also from the 2010 rate case settlement. During the second quarter of 2011, the NHPUC issued rate orders approving net increases in revenue requirements effective July 1, 2011 to (1) recover exogenous costs, (2) implement a step increase program for capital additions and the reliability enhancement program, and (3) allow for the recovery of the 2010 windstorm costs. Together with the scheduled termination of the rate recoupment charge, the net impact of these rate changes was a $2.4 million decrease in rates effective July 1, 2011.

ES, SCRC, and TCAM Filings: During the second quarter of 2011, PSNH filed with the NHPUC requests for ES, SCRC and TCAM rates of 8.89 cents per kWh, 1.09 cents per kWh, and 1.189 cents per kWh, respectively, to be effective July 1, 2011. On June 28, 2011, the NHPUC issued orders approving the ES and SCRC rates as filed, and on June 29, 2011, the NHPUC issued an order approving the TCAM rate as filed.

On July 26, 2011, the NHPUC ordered PSNH to file a rate proposal that would mitigate the impact of customer migration expected to occur when the ES rate is higher than market prices. On January 26, 2012, the NHPUC rejected the PSNH proposal and ordered PSNH to file a new proposal no later than June 30, 2012, addressing certain issues raised by the NHPUC.

On November 22, 2011, the NHPUC opened a docket to place the Clean Air Project into ES rates, including conducting a prudence review and establishing temporary rates. Hearings are scheduled on temporary rates for March 12 and 13, 2012. Following hearings on temporary rates, it is expected that recovery of costs of the Clean Air Project will begin during the second quarter of 2012. No formal schedule for the comprehensive prudence review or for permanent rates has been established.

On December 30, 2011, the NHPUC issued an order establishing an ES rate of 8.31 cents per kWh, effective January 1, 2012, as opposed to the previous 8.89 cents per kWh.

In September 2011, PSNH filed a petition with the NHPUC requesting a change in its SCRC annual rate for the period January 1, 2012 through December 31, 2012. In mid-December 2011, PSNH filed updated values, which set the proposed SCRC rate at 1.23 cents per kWh. In late December 2011, the NHPUC approved the SCRC rate as filed.

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ES and SCRC Reconciliation: On an annual basis, PSNH files with the NHPUC an ES/SCRC cost reconciliation filing for the preceding year. On April 29, 2011, the NHPUC approved a settlement between PSNH and the NHPUC staff regarding PSNH’s 2009 ES/SCRC reconciliation filing. The settlement did not have a material impact on PSNH’s financial position, results of operations or cash flows. On May 2, 2011, PSNH filed its 2010 ES/SCRC reconciliation with the NHPUC, whose evaluation includes a prudence review of PSNH’s generation and power purchase activities. In November 2011, PSNH and the NHPUC staff reached a settlement regarding PSNH’s 2010 ES/SCRC reconciliation filing. The settlement did not have a material impact on PSNH’s financial position, results of operations or cash flows. The NHPUC held a hearing on the settlement in late November 2011, and issued an order approving the settlement on January 26, 2012.

As of December 31, 2011, PSNH had ES and SCRC regulatory assets of $17.3 million and $1.5 million, respectively, which are being recovered from customers in 2012.

Merrimack Clean Air Project: On July 7, 2009, the New Hampshire Site Evaluation Committee (NHSEC) determined that PSNH’s Clean Air Project was not subject to the NHSEC’s review as a “sizeable” addition to a power plant under state law. The NHSEC upheld its decision in an order dated January 15, 2010, denying requests for rehearing. This order was appealed to the New Hampshire Supreme Court on February 23, 2010. On July 21, 2011, the New Hampshire Supreme Court ruled that the appellants lacked standing to file their original action with the NHSEC, and that the NHSEC erred in entertaining the appellants’ filing. The Court vacated the NHSEC’s decision, confirming PSNH’s position that NHSEC approval was not necessary.

Massachusetts:

Basic Service Rates: In 2011, WMECO’s fixed basic service rates ranged from 6.993 cents per kWh to 6.998 cents per kWh for residential customers, 7.498 cents per kWh to 8.006 cents per kWh for small commercial and industrial customers, and 6.958 cents per kWh to 7.450 cents per kWh for medium and large commercial and industrial customers. Effective January 1, 2012, WMECO’s rates for all basic service customers increased to reflect the basic service solicitations conducted by WMECO in November 2011. WMECO’s fixed basic service rates for residential customers increased to 7.715 cents per kWh, fixed rates for small commercial and industrial customers increased to 8.238 cents per kWh and fixed rates for large commercial and industrial customers increased to 8.451 cents per kWh. The fixed price increased by 0.753 cents per kWh for street lighting customers to 6.403 cents per kWh.

Critical Accounting Policies

The preparation of financial statements in conformity with GAAP requires management to make estimates, assumptions and, at times, difficult, subjective or complex judgments. Changes in these estimates, assumptions and judgments, in and of themselves, could materially impact our financial position, results of operations or cash flows. Our management communicates to and discusses with our Audit Committee of the Board of Trustees significant matters relating to critical accounting policies. Our critical accounting policies are discussed below. See the combined notes to our consolidated financial statements for further information concerning the accounting policies, estimates and assumptions used in the preparation of our consolidated financial statements.

Regulatory Accounting: The accounting policies of the Regulated companies conform to GAAP applicable to rate-regulated enterprises and historically reflect the effects of the rate-making process.

The application of accounting guidance applicable to rate-regulated enterprises results in recording regulatory assets and liabilities. Regulatory assets represent the deferral of incurred costs that are probable of future recovery in customer rates. In some cases, we record regulatory assets before approval for recovery has been received from the applicable regulatory commission. We must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery. We base our conclusion on certain factors, including, but not limited to, regulatory precedent. Regulatory liabilities represent revenues received from customers to fund expected costs that have not yet been incurred or probable future refunds to customers.

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We use our best judgment when recording regulatory assets and liabilities; however, regulatory commissions can reach different conclusions about the recovery of costs, and those conclusions could have a material impact on our consolidated financial statements. We believe it is probable that the Regulated companies will recover the regulatory assets that have been recorded. If we determined that we could no longer apply the accounting guidance applicable to rate-regulated enterprises to our operations, or that we could not conclude that it is probable that costs would be recovered or reflected in future rates, the costs would be charged to earnings in the period in which the determination is made.

For further information, see Note 2, “Regulatory Accounting,” to the consolidated financial statements.

Unbilled Revenues: The determination of retail energy sales to residential, commercial and industrial customers is based on the reading of meters, which occurs regularly throughout the month. Billed revenues are based on these meter readings and the majority of recorded annual revenues is based on actual billings. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimates, and an estimated amount of unbilled revenues is recorded.

Unbilled revenues represent an estimate of electricity or natural gas delivered to customers but not yet billed. Unbilled revenues are included in Operating Revenues on the statement of income and are assets on the balance sheet that are reclassified to Accounts Receivable in the following month as customers are billed. Such estimates are subject to adjustment when actual meter readings become available, when there is a change in estimates and under other circumstances.

The Regulated companies estimate unbilled revenues monthly using the daily load cycle method. The daily load cycle method allocates billed sales to the current calendar month based on the daily load for each billing cycle. The billed sales are subtracted from total month load, net of delivery losses, to estimate unbilled sales. Unbilled revenues are estimated by first allocating sales to the respective customer classes and then applying an average rate by customer class to the estimate of unbilled sales. The estimate of unbilled revenues is sensitive to numerous factors, such as energy demands, weather and changes in the composition of customer classes that can significantly impact the amount of revenues recorded.

For further information, see Note 1L, “Summary of Significant Accounting Policies — Revenues,” to the consolidated financial statements.

Pension and PBOP: Our subsidiaries participate in a Pension Plan covering certain of our regular employees and in a PBOP Plan to provide certain health care benefits, primarily medical and dental, and life insurance benefits to retired employees. For each of these plans, the development of the benefit obligation, fair value of plan assets, funded status and net periodic benefit cost is based on several significant assumptions. We evaluate these assumptions at least annually and adjust them as necessary. Changes in these assumptions could have a material impact on our financial position, results of operations or cash flows.

Pre-tax net periodic pension expense (excluding SERP) for the Pension Plan was $127.7 million, $80.4 million and $39.7 million for the years ended December 31, 2011, 2010 and 2009, respectively. The pre-tax net PBOP Plan expense was $43.6 million, $41.6 million and $37.2 million for the years ended December 31, 2011, 2010 and 2009, respectively.

We develop key assumptions for purposes of measuring the plans’ liabilities as of December 31 and expenses for the subsequent year. These assumptions include the long-term rate of return on plan assets, discount rate, compensation/progression rate, and health care cost trend rates and are discussed below.

Long-Term Rate of Return on Plan Assets: In developing this assumption, we consider historical and expected returns and input from our actuaries and consultants. Our expected long-term rate of return on assets is based on assumptions regarding target asset allocations and corresponding expected rates of return for each asset

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class. We routinely review the actual asset allocations and periodically rebalance the investments to the targeted asset allocations when appropriate. We used an aggregate expected long-term rate of return assumption of 8.25 percent on Pension and PBOP Plan assets as of December 31, 2011.

Discount Rate: Payment obligations related to the Pension Plan and PBOP Plan are discounted at interest rates applicable to the timing of the plans’ cash flows. The discount rate that is utilized in determining the pension and PBOP obligations is based on a yield-curve approach. This approach is based on a population of bonds with an average rating of AA based on bond ratings by Moody’s, S&P and Fitch, and uses bonds with above median yields within that population. The discount rates determined on this basis are 5.03 percent for the Pension Plan and 4.84 percent for the PBOP Plan as of December 31, 2011 and 5.57 percent and 5.28 percent for the respective plans as of December 31, 2010.

Compensation/Progression Rate: This assumption reflects the expected long-term salary growth rate, which impacts the estimated benefits that pension plan participants receive in the future. We used a compensation/progression rate of 3.5 percent as of December 31, 2011 and 2010, which reflects our current expectation of future salary increases, including consideration of the levels of increases built into union contracts.

Actuarial Determination of Expense: Pension and PBOP expense are determined by our actuaries and consist of service cost and prior service cost, interest cost based on the discounting of the obligations, amortization of actuarial gains and losses and amortization of the net transition obligation, offset by the expected return on plan assets. Actuarial gains and losses represent differences between assumptions and actual information or updated assumptions.

We determine the expected return on plan assets by applying our assumed rate of return to a four-year rolling average fair values, which reduces year-to-year volatility. This calculation recognizes investment gains or losses over a four-year period from the years in which they occur. Investment gains or losses for this purpose are the difference between the calculated expected return and the actual return or loss based on the change in the fair value of assets during the year. As of December 31, 2011, investment losses that remain to be reflected in the calculation of plan assets over the next four years were $369 million and $5.8 million for the Pension Plan and PBOP Plan, respectively. As investment gains and losses are reflected in the average plan asset fair values, they are subject to amortization with other unrecognized actuarial gains or losses. The plans currently amortize unrecognized actuarial gains or losses as a component of pension and PBOP expense over the average future employee service period of approximately 10 and 9 years, respectively. As of December 31, 2011, the net unrecognized actuarial losses on the Pension and PBOP Plan liabilities, subject to amortization, were $819.3 million and $202.5 million, respectively.

Forecasted Expenses and Expected Contributions: Based upon the assumptions and methodologies discussed above, we estimate that forecasted expense for the Pension Plan and PBOP Plan will be $167.9 million and $44.7 million, respectively, in 2012. Pension and PBOP expense for subsequent years will depend on future investment performance, changes in future discount rates and other assumptions, and various other factors related to the populations participating in the plans. Pension and PBOP expense charged to earnings is net of the amounts capitalized.

We expect to continue our policy to contribute to the PBOP Plan at the amount of PBOP expense, excluding curtailments and special benefit amounts and adding contributions for the amounts received from the federal Medicare subsidy. NU’s policy is to annually fund the Pension Plan in an amount at least equal to what will satisfy the requirements of ERISA, as amended by the PPA, and the Internal Revenue Code. NU’s Pension Plan has historically been well funded, and a contribution was not required to be made from 1991 until the third quarter of 2010, when PSNH made a contribution to the plan of $45 million. NU made contributions totaling $143.6 million in 2011, $112.6 million of which were contributed by PSNH. Our Pension Plan funded ratio (the value of plan assets divided by the funding target in accordance with the requirements and guidelines of the PPA) was 80 percent as of January 1, 2011. We currently estimate that quarterly contributions aggregating to a total of $197.3 million will be made in 2012.

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Sensitivity Analysis: The following represents the hypothetical increase to the Pension Plan’s (excluding SERP) and PBOP Plan’s reported annual cost as a result of a change in the following assumptions by 50 basis points (in millions):

	As of December 31,
	Pension Plan Cost				Postretirement Plan Cost
Assumption Change	2011		2010		2011		2010
Lower long-term rate of return	$	10.3	$	10.7	$	1.3	$	1.2
Lower discount rate	$	14.2	$	13.4	$	2.3	$	2.2
Higher compensation increase	$	6.5	$	6.1	$	N/A		N/A

Pension Plan Contributions Discount Rate Sensitivity Analysis: Fluctuations in the average discount rate used to calculate expected Pension Plan contributions can have a significant impact on the amount of Pension Plan contributions estimated to be required. As of December 31, 2011, the average discount rate (segment rate) used to calculate funding target and to determine the expected Pension Plan contributions totaling $590 million for the period 2013 through 2016 was approximately 5.5 percent. If this discount rate was decreased by 50 basis points, all other items remaining constant, then the expected aggregate contributions would increase to approximately $710 million for the period 2013 through 2016. In addition, the market performance of existing plan assets, the valuation of the plan’s liabilities, and a variety of other factors would impact the Pension Plan contributions.

Health Care Cost: The health care cost trend assumption used to project increases in medical costs was 7 percent for determining 2011 PBOP Plan expense. For 2012 and 2013, the rate is 7 percent, subsequently decreasing one half percentage point per year to an ultimate rate of 5 percent in 2017. The effect of a hypothetical increase in the health care cost trend rate by one percentage point would be to have increased service and interest cost components of PBOP Plan expense by $1.2 million in 2011, with a $16.2 million impact on the postretirement benefit obligation.

See Note 10A, “Employee Benefits — Pension Benefits and Postretirement Benefits Other Than Pensions,” to the consolidated financial statements for more information.

Goodwill and Intangible Assets: We are required to test goodwill balances for impairment at least annually by applying a fair value-based test that requires us to use estimates and judgment. We have selected October 1^st of each year as the annual goodwill impairment testing date. Goodwill impairment is deemed to exist if the net book value of a reporting unit exceeds its estimated fair value and if the implied fair value of goodwill based on the estimated fair value of the reporting unit is less than the carrying amount of the goodwill. If goodwill were deemed to be impaired, it would be written down in the current period to the extent of the impairment.

We determine the discount rate using the capital asset pricing model methodology. This methodology uses a weighted average cost of capital in which the ROE is developed using risk-free rates, equity premiums and a beta representing Yankee Gas’ volatility relative to the overall market. The resulting discount rate is intended to be comparable to a rate that would be applied by a market participant. The discount rate may change from year to year as it is based on external market conditions.

We performed an impairment analysis as of October 1, 2011 for the Yankee Gas goodwill balance of $287.6 million. We determined that the fair value of Yankee Gas substantially exceeds its carrying value and no impairment exists. In performing the evaluation, we estimated the fair value of the Yankee Gas reporting unit and compared it to the carrying amount of the reporting unit, including goodwill. We estimated the fair value of Yankee Gas using a discounted cash flow methodology and two market approaches that analyze comparable companies or transactions. This evaluation requires the input of several critical assumptions, including future growth rates, cash flow projections, operating cost escalation rates, rates of return, a risk-adjusted discount rate, long-term earnings and merger multiples of comparable companies.

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Income Taxes: Income tax expense is estimated annually for each of the jurisdictions in which we operate. This process involves estimating current and deferred income tax expense or benefit and the impact of temporary differences resulting from differing treatment of items for financial reporting and income tax return reporting purposes. Such differences are the result of timing of the deduction for expenses, as well as any impact of permanent differences resulting from tax credits, non-tax deductible expenses, in addition to various other items, including items that directly impact our tax return as a result of a regulatory activity (flow-through items). The temporary differences and flow-through items result in deferred tax assets and liabilities that are included in the consolidated balance sheets. The income tax estimation process impacts all of our segments. We record income tax expense quarterly using an estimated annualized effective tax rate.

A reconciliation of expected tax expense at the statutory federal income tax rate to actual tax expense recorded is included in Note 11, “Income Taxes,” to the consolidated financial statements.

We also account for uncertainty in income taxes, which applies to all income tax positions previously filed in a tax return and income tax positions expected to be taken in a future tax return that have been reflected on our balance sheets. We follow generally accepted accounting principles to address the methodology to be used in recognizing, measuring and classifying the amounts associated with tax positions that are deemed to be uncertain, including related interest and penalties. The determination of whether a tax position meets the recognition threshold under this guidance is based on facts and circumstances available to us. Once a tax position meets the recognition threshold, the tax benefit is measured using a cumulative probability assessment. Assigning probabilities in measuring a recognized tax position and evaluating new information or events in subsequent periods requires significant judgment and could change previous conclusions used to measure the tax position estimate. New information or events may include tax examinations or appeals (including information gained from those examinations), developments in case law, settlements of tax positions, changes in tax law and regulations, rulings by taxing authorities and statute of limitation expirations. Such information or events may have a significant impact on our financial position, results of operations and cash flows.

Accounting for Environmental Reserves: Environmental reserves are accrued when assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated. Adjustments made to estimates of environmental liabilities could have a significant impact on earnings. We estimate these liabilities based on findings through various phases of the assessment, considering the most likely action plan from a variety of available options (ranging from no action to full site remediation and long-term monitoring), current site information from our site assessments, remediation estimates from third party engineering and remediation contractors, and our prior experience in remediating contaminated sites. Our estimates incorporate currently enacted state and federal environmental laws and regulations and data released by the EPA and other organizations. The estimates associated with each possible action plan are judgmental in nature partly because there are usually several different remediation options from which to choose. Our estimates are subject to revision in future periods based on actual costs or new information from other sources, including the level of contamination at the site recently enacted laws and regulations or a change in estimates due to certain economic factors.

For further information, see Note 12A, “Commitments and Contingencies — Environmental Matters,” to the consolidated financial statements and Other Matters below.

Fair Value Measurements: We follow fair value measurement guidance that defines fair value as the price that would be received for the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (an exit price). We have applied this guidance to the Company’s derivative contracts that are recorded at fair value, marketable securities held in NU’s supplemental benefit trust and WMECO’s spent nuclear fuel trust, our valuations of investments in our pension and PBOP plans, and nonrecurring fair value measurements of nonfinancial assets such as goodwill and AROs.

Changes in fair value of the regulated company derivative contracts are recorded as Regulatory assets or liabilities, as we expect to recover the costs of these contracts in rates. These valuations are sensitive to the prices of energy and energy related products in future years for which markets have not yet developed and assumptions are made.

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We use quoted market prices when available to determine fair values of financial instruments. If quoted market prices are not available, fair value is determined using quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments that are not active and model-derived valuations. When quoted prices in active markets for the same or similar instruments are not available, we value derivative contracts using models that incorporate both observable and unobservable inputs. Significant unobservable inputs utilized in the models include energy and energy-related product prices for future years for long-dated derivative contracts, future contract quantities under full requirements and supplemental sales contracts, and market volatilities. Discounted cash flow valuations incorporate estimates of premiums or discounts, reflecting risk adjusted profit that would be required by a market participant to arrive at an exit price, using available historical market transaction information. Valuations of derivative contracts also reflect our estimates of nonperformance risk, including credit risk.

For further information, see Item 7A, “Quantitative and Qualitative Disclosures about Market Risk,” included in this Annual Report for a sensitivity analysis of how changes in the prices of energy and energy related products would impact earnings.

For further information on derivative contracts and marketable securities, see Note 1J, “Summary of Significant Accounting Policies — Derivative Accounting,” Note 4, “Derivative Instruments,” and Note 5, “Marketable Securities,” to the consolidated financial statements.

Other Matters

Environmental Matter: HWP continues to investigate the potential need for additional remediation at a river site in Massachusetts containing tar deposits associated with an MGP site that HWP sold to HG&E, a municipal utility, in 1902. As of December 31, 2011, HWP had a $2.4 million reserve for estimated costs that HWP considers probable over the remaining life of the remediation term. Although a material increase to the reserve is not presently anticipated, management cannot reasonably estimate potential additional investigation or remediation costs because these costs would depend, among other things, on the nature, extent and timing of additional investigation and remediation that may be required by the MA DEP.

For further information, see Note 12A, “Commitments and Contingencies — Environmental Matters,” to the consolidated financial statements.

Accounting Standards Issued But Not Yet Adopted: For information regarding new accounting standards, see Note 1D, “Summary of Significant Accounting Policies — Accounting Standards Issued But Not Yet Adopted,” to the consolidated financial statements.

Contractual Obligations and Commercial Commitments: Information regarding our contractual obligations and commercial commitments as of December 31, 2011 is summarized annually through 2016 and thereafter as follows:

NU
(Millions of Dollars)	2012		2013		2014		2015		2016		Thereafter		Total
Long-term debt maturities (a)	$	329.3	$	430.0	$	275.0	$	150.0	$	15.4	$	3,449.6	$	4,649.3
Estimated interest payments on existing debt (b)		230.8		219.2		207.6		193.5		188.3		1,622.4		2,661.8
Capital leases (c)		3.0		2.6		2.2		2.2		2.0		9.5		21.5
Operating leases (d)		7.7		6.9		4.9		4.3		4.3		16.6		44.7
Funding of pension obligations (d) (h)		197.3		152.2		153.1		148.8		135.3		46.0		832.7
Funding of other postretirement benefit obligations (d)		44.7		28.3		25.5		23.8		21.0		18.6		161.9
Estimated future annual long-term contractual costs (e)		613.5		536.2		567.4		508.1		493.0		4,129.1		6,847.3
Other purchase commitments (d) (g)		1,965.5		—		—		—		—		—		1,965.5
Total (f) (i)	$	3,391.8	$	1,375.4	$	1,235.7	$	1,030.7	$	859.3	$	9,291.8	$	17,184.7

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CL&P
(Millions of Dollars)	2012		2013		2014		2015		2016		Thereafter		Total
Long-term debt maturities (a)	$	62.0	$	125.0	$	150.0	$	100.0	$	15.4	$	1,891.3	$	2,343.7
Estimated interest payments on existing debt (b)		126.2		126.2		126.2		116.5		114.0		1,168.3		1,777.4
Capital leases (c)		2.3		2.1		1.9		1.9		1.9		9.4		19.5
Operating leases (d)		3.2		2.8		2.6		2.6		2.6		12.0		25.8
Funding of other postretirement benefit obligations (d)		17.3		9.5		8.6		8.1		7.1		6.3		56.9
Estimated future annual long-term contractual costs (e)		282.6		324.0		362.2		352.1		349.5		2,577.1		4,247.5
Other purchase commitments (d) (g)		744.8		—		—		—		—		—		744.8
Total (f) (i)	$	1,238.4	$	589.6	$	651.5	$	581.2	$	490.5	$	5,664.4	$	9,215.6

(a) Long-term debt maturities exclude fees and interest due for spent nuclear fuel disposal costs, unamortized premiums and discounts, and net changes in fair value of hedged debt for NU.

(b) Estimated interest payments on fixed-rate debt are calculated by multiplying the coupon rate on the debt by its scheduled notional amount outstanding for the period of measurement. Estimated interest payments on floating-rate debt are calculated by multiplying the average of the 2011 floating-rate resets on the debt by its scheduled notional amount outstanding for the period of measurement. This same rate is then assumed for the remaining life of the debt. Interest payments on debt that have an interest rate swap in place are estimated using the effective cost of debt resulting from the swap rather than the underlying interest cost on the debt, subject to the fixed and floating methodologies.

(c) The capital lease obligations include imputed interest for NU and CL&P.

(d) Amounts are not included on our consolidated balance sheets.

(e) Other than the net mark-to-market changes on respective derivative contracts held by both the Regulated companies and NU Enterprises, these obligations are not included on our consolidated balance sheets.

(f) Does not include unrecognized tax benefits for NU and CL&P as of December 31, 2011, as we cannot make reasonable estimates of the periods or the potential amounts of cash settlement with the respective taxing authorities. Also does not include an NU contingent commitment of approximately $45 million to an energy investment fund, which would be invested under certain conditions, as we cannot make reasonable estimates of the periods or the investment contributions.

(g) Amount represents open purchase orders, excluding those obligations that are included in the capital leases, operating leases and estimated future annual long-term contractual costs. These payments are subject to change as certain purchase orders include estimates based on projected quantities of material and/or services that are provided on demand, the timing of which cannot be determined. Because payment timing cannot be determined, we include all open purchase order amounts in 2012.

(h) These amounts represent NU’s estimated minimum pension contributions to its qualified Pension Plan required under ERISA, as amended by the PPA, and the Internal Revenue Code. Contributions in 2013 through 2016 and thereafter will vary depending on many factors, including the performance of existing plan assets, valuation of the plan’s liabilities and long-term discount rates, and are subject to change.

(i) For NU, excludes other long-term liabilities, including a significant portion of the unrecognized tax benefits described above, deferred contractual obligations, environmental reserves, various injuries and damages reserves ($37.5 million), employee medical insurance reserves ($7.7 million), long-term disability insurance reserves ($11.9 million) and the ARO liability reserves as we cannot make reasonable estimates of the timing of payments. For CL&P, excludes unrecognized tax benefits described above, deferred contractual obligations, environmental reserves, various injuries and damages reserves ($26.1 million), employee medical insurance reserves ($2.4 million), long-term disability insurance reserves ($4 million) and the ARO liability reserves.

For further information regarding our contractual obligations and commercial commitments, see Note 8, “Short-Term Debt,” Note 9, “Long-Term Debt,” Note 10A, “Employee Benefits — Pension Benefits and

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Postretirement Benefits Other Than Pensions,” Note 12B, “Commitments and Contingencies — Long-Term Contractual Arrangements,” and Note 13, “Leases,” to the consolidated financial statements.

RRB amounts are non-recourse to us, have no required payments over the next five years and are not included in this table. The Regulated companies’ standard offer service contracts and default service contracts are also not included in this table.

Web Site: Additional financial information is available through our web site at www.nu.com.

RESULTS OF OPERATIONS — NORTHEAST UTILITIES AND SUBSIDIARIES

The following table provides the amounts and variances in operating revenues and expense line items for the consolidated statements of income for NU included in this Annual Report for the years ended December 31, 2011, 2010 and 2009:

Comparison of 2011 to 2010:

	Operating Revenues and Expenses For the Years Ended December 31,
(Millions of Dollars)	2011		2010		Increase/ (Decrease)			Percent
Operating Revenues	$	4,465.7	$	4,898.2	$	(432.5	)		(8.8	)%
Operating Expenses:
Fuel, Purchased and Net Interchange Power		1,580.7		1,985.6		(404.9	)		(20.4	)
Other Operating Expenses		1,026.2		958.4		67.8			7.1
Maintenance		271.8		210.3		61.5			29.2
Depreciation		302.2		300.7		1.5			0.5
Amortization of Regulatory Assets, Net		97.1		95.7		1.4			1.5
Amortization of Rate Reduction Bonds		69.9		232.9		(163.0	)		(70.0	)
Taxes Other Than Income Taxes		323.6		314.7		8.9			2.8
Total Operating Expenses		3,671.5		4,098.3		(426.8	)		(10.4	)
Operating Income	$	794.2	$	799.9	$	(5.7	)		(0.7	)%

Operating Revenues

	For the Years Ended December 31,
	2011		2010		Increase/ (Decrease)			Percent
Electric Distribution	$	3,343.1	$	3,802.0	$	(458.9	)		(12.1	)%
Natural Gas Distribution		430.8		434.3		(3.5	)		(0.8	)
Total Distribution		3,773.9		4,236.3		(462.4	)		(10.9	)
Transmission		635.4		625.6		9.8			1.6
Total Regulated Companies		4,409.3		4,861.9		(452.6	)		(9.3	)
Other and Eliminations		56.4		36.3		20.1			55.4
NU	$	4,465.7	$	4,898.2	$	(432.5	)		(8.8	)%

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A summary of our retail electric sales and firm natural gas sales were as follows:

	For the Years Ended December 31,
	2011		2010		Increase/ (Decrease)			Percent
Retail Electric Sales in GWh		33,812		34,230		(418	)		(1.2	)%
Firm Natural Gas Sales in Million Cubic Feet (1)		46,880		43,406		3,474			8.0	%
Firm Natural Gas Sales (Net of Special Contracts) in Million Cubic Feet		38,197		35,038		3,159			9.0	%

(1) The 2010 sales volumes for commercial customers have been adjusted to conform to current year presentation.

Our Operating Revenues decreased in 2011, as compared to 2010, due primarily to:

• Lower electric distribution revenues related to the portions that are included in regulatory commission approved tracking mechanisms that recover certain incurred costs and do not impact earnings. The tracked electric distribution revenues decreased due primarily to lower energy and supply-related costs ($365.3 million), lower CTA revenues and stranded cost recoveries ($175.3 million), lower wholesale revenues ($85.2 million) and lower retail other revenues ($37.9 million), partially offset by higher CL&P FMCC delivery-related revenues ($28.6 million), higher retail transmission revenues ($12.2 million) and higher other tracked revenues ($28.7 million). The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.

• The portion of electric distribution revenues that impacts earnings increased $135.5 million due primarily to the rate case decisions that were effective during 2011.

• Improved transmission segment revenues resulting from a higher level of investment in transmission infrastructure and the recovery of higher overall expenses, which are tracked and result in a related increase in revenues. The increase in expenses is directly related to the increase in transmission plant, including costs associated with higher property taxes, depreciation and operation and maintenance expenses. These were partially offset by a refund to transmission wholesale customers, compared to a recovery from those customers in 2010. The transmission rates provide for an annual reconciliation and recovery or refund of projected costs to actual costs. The difference between projected costs and actual costs are recovered from, or refunded to, customers each year.

Fuel, Purchased and Net Interchange Power

Fuel, Purchased and Net Interchange Power decreased in 2011, as compared to 2010, due primarily to the following:

(Millions of Dollars)	2011 Decrease as compared to 2010
Lower GSC supply costs and purchased power costs, partially offset by higher other costs at CL&P	$	(323.4	)
Lower energy prices, a slight increase in ES customer migration to third party suppliers and lower retail sales for PSNH’s remaining ES customers		(54.3	)
Lower basic/default service supply costs at WMECO		(11.7	)
Lower natural gas costs at Yankee Gas		(15.1	)
Other		(0.4	)
	$	(404.9	)

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Other Operating Expenses

Other Operating Expenses increased in 2011, as compared to 2010, due primarily to:

• Higher electric distribution expenses ($52.4 million) and higher natural gas expenses ($6.9 million), primarily related to CL&P’s establishment of a $30 million storm fund reserve to provide bill credits to its residential customers who remained without power after noon on Saturday, November 5, 2011, as a result of the October 2011 snowstorm and to provide contributions to certain Connecticut charitable organizations. In addition, there were higher pension costs and higher general and administrative expenses. Partially offsetting these increases were lower costs that are recovered through distribution tracking mechanisms that have no earnings impact ($11.8 million), such as retail transmission, reliability must run and customer service expenses. In addition, there were lower transmission segment expenses ($8.5 million).

• Higher NU parent and other companies expenses ($27.3 million) were due primarily to higher costs at NU’s unregulated electrical contracting business related to an increased level of work in 2011 ($19.6 million), partially offset by a decrease in costs related to NU’s pending merger with NSTAR ($2.1 million).

Maintenance

Maintenance increased in 2011, as compared to 2010, due primarily to the partial amortization in 2011 of the allowed regulatory deferral, which was recorded in maintenance expense in 2010, as a result of the June 30, 2010 CL&P rate case decision ($54.9 million) and higher boiler equipment and maintenance costs at PSNH’s generation business related to the absence in 2011 of insurance proceeds received in 2010 related to turbine damage, which reduced 2010 costs ($7.4 million).

Depreciation

Depreciation increased in 2011, as compared to 2010, due primarily to higher depreciation rates being used at PSNH and WMECO in 2011 as a result of distribution rate case decisions that were effective during 2011 and higher utility plant balances resulting from completed construction projects placed into service. Partially offsetting these increases was a lower depreciation rate being used at CL&P as a result of the distribution rate case decision that was effective July 1, 2010.

Amortization of Regulatory Assets, Net

Amortization of Regulatory Assets, Net, increased in 2011, as compared to 2010, due primarily to lower CTA transition costs ($197.7 million) partially offset by lower retail CTA revenue ($154.6 million) at CL&P, the absence in 2011 of the impact from the 2010 Healthcare Act related to income taxes ($26 million) and increases in ES amortization ($11.4 million) and TCAM amortization ($5.9 million) at PSNH. Partially offsetting these increases was lower amortization related to the previously deferred unrecovered stranded generation costs related to income taxes at CL&P ($38.2 million) and lower amortization of the SBC balance at CL&P ($29.7 million).

Amortization of Rate Reduction Bonds

Amortization of RRBs decreased in 2011, as compared to 2010, due to the maturity of CL&P’s RRBs in December 2010 and lower principal balances on the remaining PSNH and WMECO RRBs outstanding.

Taxes Other Than Income Taxes

The increase in Taxes Other Than Income Taxes in 2011, as compared to 2010, was due primarily to an increase in property taxes as a result of an increase in Property, Plant and Equipment related to our capital program and an increase in the tax rate, offset by a decrease in the Connecticut Gross Earnings Tax due primarily to lower transmission segment revenues and lower CTA revenues in 2011, as compared to 2010.

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Interest Expense

	For the Years Ended December 31,
(Millions of Dollars)	2011		2010			Increase/ (Decrease)			Percent
Interest on Long-Term Debt	$	231.6	$	231.1		$	0.5			0.2	%
Interest on RRBs		8.6		20.6			(12.0	)		(58.3	)
Other Interest		10.2		(14.4	)		24.6				(a)
	$	250.4	$	237.3		$	13.1			5.5	%

(a) Percent greater than 100 percent not shown since it is not meaningful.

Interest Expense increased in 2011, as compared to 2010, due primarily to higher Other Interest in 2011, as compared to 2010, due to the prior year inclusion of a tax-related benefit, partially offset by lower Interest on RRBs in 2011, as compared to 2010, resulting from the maturity of CL&P’s RRBs in December 2010 and lower principal balances on the remaining PSNH and WMECO RRBs outstanding.

Other Income, Net

	For the Years Ended December 31,
(Millions of Dollars)	2011		2010		Decrease			Percent
Other Income, Net	$	27.7	$	41.9	$	(14.2	)		(33.9	)%

Other Income, Net decreased in 2011, as compared to 2010, due primarily to net losses on the NU supplemental benefit trust in 2011, compared to net gains in 2010, and the 2011 classification of C&LM and EIA incentives; partially offset by higher AFUDC related to equity funds.

Income Tax Expense

	For the Years Ended December 31,
(Millions of Dollars)	2011		2010		Decrease			Percent
Income Tax Expense	$	171.0	$	210.4	$	(39.4	)		(18.7	)%

Income Tax Expense decreased in 2011, as compared to 2010, due primarily to the absence in 2011 of the impact from the 2010 Healthcare Act ($25.2 million), adjustments for prior years taxes including adjustments to reconcile estimated taxes accrued to actual amounts reflected in our filed tax returns (“return to provision adjustments”) ($16.3 million), lower items that directly impact our tax return as a result of regulatory actions (“flow-through” items) ($4.6 million) and lower pre-tax earnings ($2.1 million); partially offset by higher state income taxes ($9.6 million).

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Comparison of 2010 to 2009:

	Operating Revenues and Expenses For the Years Ended December 31,
(Millions of Dollars)	2010		2009		Increase/ (Decrease)			Percent
Operating Revenues	$	4,898.2	$	5,439.4	$	(541.2	)		(9.9	)%
Operating Expenses:
Fuel, Purchased and Net Interchange Power		1,985.6		2,629.6		(644.0	)		(24.5	)
Other Operating Expenses		958.4		1,001.2		(42.8	)		(4.3	)
Maintenance		210.3		234.2		(23.9	)		(10.2	)
Depreciation		300.7		309.6		(8.9	)		(2.9	)
Amortization of Regulatory Assets, Net		95.7		13.3		82.4			(a	)
Amortization of Rate Reduction Bonds		232.9		217.9		15.0			6.9
Taxes Other Than Income Taxes		314.7		282.2		32.5			11.5
Total Operating Expenses		4,098.3		4,688.0		(589.7	)		(12.6	)
Operating Income	$	799.9	$	751.4	$	48.5			6.5	%

(a) Percent greater than 100 percent not shown as it is not meaningful.

Operating Revenues

	For the Years Ended December 31,
(Millions of Dollars)	2010		2009		Increase/ (Decrease)			Percent
Electric Distribution	$	3,802.0	$	4,358.4	$	(556.4	)		(12.8	)%
Natural Gas Distribution		434.3		449.6		(15.3	)		(3.4	)
Total Distribution		4,236.3		4,808.0		(571.7	)		(11.9	)
Transmission		625.6		577.9		47.7			8.3
Total Regulated Companies		4,861.9		5,385.9		(524.0	)		(9.7	)
Other and Eliminations		36.3		53.5		(17.2	)		(32.1	)
NU	$	4,898.2	$	5,439.4	$	(541.2	)		(9.9	)%

A summary of our retail electric sales and firm natural gas sales were as follows:

	For the Years Ended December 31,
	2010		2009		Increase		Percent
Retail Electric Sales in GWh		34,230		33,645		585		1.7	%
Firm Natural Gas Sales in Million Cubic Feet (1)		43,406		42,605		801		1.9	%

(1) The sales volumes for commercial customers have been adjusted to conform to current year presentation.

Our Operating Revenues decreased in 2010, as compared to 2009, due primarily to:

• Lower electric distribution revenues related to the portions that are included in regulatory commission approved tracking mechanisms that recover certain incurred costs and do not impact earnings. The tracked electric distribution revenues decreased due primarily to lower GSC and supply-related FMCC charges ($574 million) and lower CL&P delivery-related FMCC ($39 million), partially offset by higher retail transmission revenues ($66 million) and higher transition cost recoveries ($48 million). The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.

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• The portion of electric distribution revenues that impacts earnings increased $40 million due primarily to a 1.7 percent increase in retail electric sales volume due to warmer than normal summer weather and PSNH’s rate changes that were effective July 1, 2010. A decrease in natural gas revenues was due primarily to lower cost of fuel, as fuel costs are fully recovered in revenues from sales to our customers, offset by an increase in sales volume. Firm natural gas sales increased 1.9 percent in 2010 compared to 2009.

• Improved transmission segment revenues resulting from a higher level of investment in transmission infrastructure and the return of higher overall expenses, which are tracked and result in a related increase in revenues. The increase in expenses is directly related to the increase in transmission plant, including costs associated with higher property taxes, depreciation and operation and maintenance expenses.

Fuel, Purchased and Net Interchange Power

Fuel, Purchased and Net Interchange Power decreased in 2010, as compared to 2009, due primarily to the following:

	2010
(Millions of Dollars)	Increase/(Decrease) as compared to 2009
Lower GSC supply costs and purchased power contract costs, partially offset by an increase in deferred fuel costs at CL&P	$	(437.4	)
Lower prices on purchased natural gas at Yankee Gas		(19.7	)
An increased level of ES customer migration to third party electric suppliers, partially offset by higher retail sales at PSNH		(157.4	)
Lower basic service supply costs at WMECO		(34.9	)
Increase in expenses due primarily to lower unregulated business wholesale contract mark-to-market gains and other loss		5.4
	$	(644.0	)

Other Operating Expenses

Other Operating Expenses decreased in 2010, as compared to 2009, due primarily to:

• Lower distribution and transmission segment expenses of $66 million were due primarily to lower costs that are recovered through distribution tracking mechanisms that have no earnings impact ($65 million), such as retail transmission, reliability must run and customer service expenses, and lower uncollectibles expense at Yankee Gas ($16 million), partially offset by higher electric distribution and natural gas expenses ($22 million and $3 million, respectively), including higher pension costs and storm restoration costs, and higher transmission segment expenses ($4 million).

• Higher NU parent and other companies expenses of $22 million due primarily to costs incurred in 2010 related to NU’s pending merger with NSTAR and higher pension and environmental costs.

Maintenance

Maintenance decreased in 2010, as compared to 2009, due primarily to the allowed regulatory deferral of approximately $32 million as a result of the June 30, 2010 CL&P rate case decision, of which $29.5 million was recognized as a deferral in maintenance expense, lower boiler and maintenance costs at PSNH’s generation business ($12 million), offset by higher distribution segment overhead line expenses ($13 million), higher distribution segment vegetation management costs ($2 million) and higher transmission segment routine station maintenance expenses ($2 million).

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Depreciation

Depreciation decreased in 2010, as compared to 2009, due primarily to a lower depreciation rate being used at CL&P as a result of the distribution rate case decision that was effective July 1, 2010, partially offset by higher utility plant balances resulting from completed construction projects placed into service.

Amortization of Regulatory Assets, Net

Amortization of Regulatory Assets, Net increased in 2010, as compared to 2009, due primarily to a higher recovery of CTA costs at CL&P ($39 million), higher PSNH amortization on the ES deferral and TCAM ($42 million and $11 million, respectively), and previously deferred unrecovered stranded generation costs at WMECO ($11 million), partially offset by the impact of the 2010 Healthcare Act related to the deferral of lost tax benefits that we believe are probable of recovery in future electric and natural gas distribution rates ($26 million).

Taxes Other Than Income Taxes

(Millions of Dollars)	2010 Increase as compared to 2009
Connecticut Gross Earnings Tax	$	8.9
Property Taxes		12.5
Use Taxes		10.4
Other		0.7
	$	32.5

The increase in Taxes Other Than Income Taxes was due primarily to an increase in property taxes as a result of an increase in Property, Plant and Equipment related to our capital programs. The Connecticut Gross Earnings Tax increased primarily as a result of an increase in the transmission segment revenues and an increase in distribution segment revenues primarily related to retail transmission and higher transition cost recoveries in 2010, as compared to 2009. The increase in use taxes was due primarily to the absence in 2010 of a Connecticut state use tax refund.

Interest Expense

	For the Years Ended December 31,
(Millions of Dollars)	2010			2009		Increase/ (Decrease)			Percent
Interest on Long-Term Debt	$	231.1		$	224.7	$	6.4			2.8	%
Interest on RRBs		20.6			36.5		(15.9	)		(43.6	)
Other Interest		(14.4	)		12.4		(26.8	)		(a	)
	$	237.3		$	273.6	$	(36.3	)		(13.3	)%

(a) Percent greater than 100 percent not shown as it is not meaningful.

Interest Expense decreased in 2010, as compared to 2009, due primarily to the settlement of various state tax matters in the fourth quarter of 2010, which resulted in a reduction in Other Interest and lower Interest on RRBs resulting from lower principal balances outstanding, offset by higher Interest on Long-Term Debt as a result of $145 million in new long-term debt issuances in the first half of 2010 and $400 million in 2009, $150 million of which was issued by PSNH in December 2009.

Other Income, Net

	For the Years Ended December 31,
(Millions of Dollars)	2010		2009		Increase		Percent
Other Income, Net	$	41.9	$	37.8	$	4.1		10.8	%

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Other Income, Net increased in 2010, as compared to 2009, due primarily to higher AFUDC related to equity funds ($7 million), higher C&LM and EIA incentives ($3 million and $2 million, respectively), offset with lower investment and interest income ($4 million and $2 million, respectively).

Income Tax Expense

	For the Years Ended December 31,
(Millions of Dollars)	2010		2009		Increase		Percent
Income Tax Expense	$	210.4	$	179.9	$	30.5		17.0	%

Income Tax Expense increased in 2010, as compared to 2009, due primarily to the impact of the 2010 Healthcare Act ($30 million) and higher pre-tax earnings ($10 million), partially offset by lower impacts related to flow-through items and other impacts ($5 million) and adjustments for prior years’ taxes including return to provision adjustments ($5 million).

Selected Consolidated Sales Statistics

	2011		2010			2009		2008		2007
Revenues: (Thousands)
Regulated Companies:
Residential	$	2,091,270	$	2,336,078		$	2,569,278	$	2,525,635	$	2,558,547
Commercial		1,201,091		1,303,841			1,462,786		1,607,224		1,735,923
Industrial		252,878		268,598			297,854		399,753		412,381
Wholesale		350,413		506,475			445,261		545,127		392,675
Streetlighting and Railroads		35,283		42,387			33,035		38,522		45,880
Miscellaneous and Eliminations		47,485		(29,878	)		128,118		24,673		84,043
Total Electric		3,978,420		4,427,501			4,936,332		5,140,934		5,229,449
Natural Gas		430,799		434,277			449,571		577,390		514,185
Total — Regulated Companies		4,409,219		4,861,778			5,385,903		5,718,324		5,743,634
Other and Eliminations		56,438		36,389			53,527		81,771		78,592
Total	$	4,465,657	$	4,898,167		$	5,439,430	$	5,800,095	$	5,822,226
Regulated Companies — Sales: (GWh)
Residential		14,766		14,913			14,412		14,509		15,051
Commercial		14,301		14,506			14,474		14,885		15,103
Industrial		4,418		4,481			4,423		5,149		5,635
Wholesale		1,020		3,423			4,183		3,576		3,855
Streetlighting and Railroads		327		330			336		340		353
Total		34,832		37,653			37,828		38,459		39,997
Regulated Companies — Customers: (Average)
Residential		1,710,342		1,704,197			1,696,756		1,700,207		1,697,073
Commercial		193,505		192,266			189,265		190,067		189,727
Industrial		7,083		7,150			7,207		7,342		7,291
Streetlighting, Railroads and Wholesale*		5,735		6,292			7,548		4,605		3,855
Total Electric		1,916,665		1,909,905			1,900,776		1,902,221		1,897,946
Natural Gas		207,753		205,885			206,438		204,834		202,743
Total		2,124,418		2,115,790			2,107,214		2,107,055		2,100,689

* Customer counts were redefined with the implementation of a new customer service system (C2) completed in October 2008.

Results of Operations for each of CL&P, PSNH and WMECO are omitted from this report but are set forth in the Annual Report on Form 10-K for 2011 filed on a combined basis with NU with the SEC on February 24, 2012. Such report is also available at the Investors section on www.nu.com.

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Quantitative and Qualitative Disclosures about Market Risk

Market Risk Information

Commodity Price Risk Management: Our Regulated companies enter into energy contracts to serve our customers and the economic impacts of those contracts are passed on to our customers. Accordingly, the Regulated companies have no exposure to loss of future earnings or fair values due to these market risk-sensitive instruments. The remaining unregulated wholesale portfolio held by Select Energy includes contracts that are market risk-sensitive, including a wholesale energy sales contract through 2013 with an agency comprised of municipalities with approximately 0.1 million remaining MWh of supply contract volumes, net of related sales volumes. Select Energy also has a non-derivative energy contract that expires in mid-2012 to purchase output from a generation facility, which is also exposed to market price volatility.

As Select Energy’s contract volumes are winding down, and as the wholesale energy sales contract is substantially hedged against price risks, we have limited exposure to commodity price risks. We have not entered into any energy contracts for trading purposes. For Select Energy’s wholesale energy portfolio derivatives, we utilize the sensitivity analysis methodology to disclose quantitative information for our commodity price risks. Sensitivity analysis provides a presentation of the potential loss of future pre-tax earnings and fair values from our market risk-sensitive contracts due to one or more hypothetical changes in commodity price components, or other similar price changes. A hypothetical 30 percent increase or decrease in forward energy, ancillary or capacity prices would not have a material impact on earnings.

The impact of a change in electricity prices on wholesale derivative transactions as of December 31, 2011 are not necessarily representative of the results that will be realized if such a change were to occur. Energy, capacity and ancillaries have different market volatilities. The method we use to determine the fair value of these contracts includes discounting expected future cash flows using a LIBOR swap curve. As such, the wholesale portfolio is also exposed to interest rate volatility. This exposure is not modeled in sensitivity analyses, and we do not believe that such exposure is material.

Other Risk Management Activities

We have implemented an Enterprise Risk Management methodology for identifying the principal risks of the Company. Enterprise Risk Management involves the application of a well-defined, enterprise-wide methodology that enables our Risk and Capital Committee, comprised of our senior officers, to oversee the identification, management and reporting of the principal risks of the business. Our management analyzes risks to determine materiality and other attributes such as likelihood and impact, velocity, and mitigation strategies. Management broadly considers our business model, the utility industry, the global economy and the current environment to identify risks.

However, there can be no assurances that the Enterprise Risk Management process will identify or manage every risk or event that could impact our financial position, results of operations or cash flows. The findings of this process are periodically discussed with our Board of Trustees.

Interest Rate Risk Management: We manage our interest rate risk exposure in accordance with our written policies and procedures by maintaining a mix of fixed and variable rate long-term debt. As of December 31, 2011, approximately 93 percent of our long-term debt, including fees and interest due for spent nuclear fuel disposal costs, was at a fixed interest rate. The remaining long-term debt is at variable interest rates and is subject to interest rate risk that could result in earnings volatility. Assuming a one percentage point increase in our variable interest rate, annual interest expense would have increased by a pre-tax amount of $3.3 million. In addition, as of December 31, 2011, we maintained a fixed-to-floating interest rate swap at NU parent associated with $263 million of its fixed-rate debt due on April 1, 2012.

Credit Risk Management: Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties pursuant to the terms of our contractual obligations. We serve a wide variety of

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customers and suppliers that include IPPs, industrial companies, gas and electric utilities, oil and gas producers, financial institutions, and other energy marketers. Margin accounts exist within this diverse group, and we realize interest receipts and payments related to balances outstanding in these margin accounts. This wide customer and supplier mix generates a need for a variety of contractual structures, products and terms that, in turn, require us to manage the portfolio of market risk inherent in those transactions in a manner consistent with the parameters established by our risk management process.

Our Regulated companies are subject to credit risk from certain long-term or high-volume supply contracts with energy marketing companies. Our Regulated companies manage the credit risk with these counterparties in accordance with established credit risk practices and monitor contracting risks, including credit risk. As of December 31, 2011, our Regulated companies neither held cash collateral nor deposited cash collateral with counterparties. NU parent provides standby LOCs for the benefit of its subsidiaries under its revolving credit agreement. PSNH posts such LOCs as collateral with counterparties and ISO-NE. For further information, see Note 12D, “Commitments and Contingencies — Guarantees and Indemnifications,” to the consolidated financial statements.

Select Energy has also established written credit policies with regard to its counterparties to minimize overall credit risk on all types of transactions. These policies require collateral under certain circumstances (including cash in advance, LOCs, and parent guarantees), and the use of standardized agreements, which allow for the netting of positive and negative exposures associated with a single counterparty in the event of default. This evaluation results in establishing credit limits prior to Select Energy entering into energy contracts. The appropriateness of these limits is subject to continuing review. Concentrations among these counterparties may impact Select Energy’s overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes to economic, regulatory or other conditions.

If the respective unsecured debt ratings of NU parent or PSNH were reduced to below investment grade by either Moody’s or S&P, certain of NU’s and PSNH’s contracts would require additional collateral in the form of cash or LOCs to be provided to counterparties and independent system operators. If such an event occurred as of December 31, 2011, NU and PSNH would have been required to provide additional cash or LOCs in an aggregate amount of $24.3 million and $4 million, respectively. NU and PSNH would have been and remain able to provide that collateral.

For further information on cash collateral deposited and posted with counterparties as well as any cash collateral netted against the fair value of the related derivative contracts, see Note 4, “Derivative Instruments,” to the consolidated financial statements.

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Consolidated Financial Statements

NORTHEAST UTILITIES AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	As of December 31,
(Thousands of Dollars)	2011		2010
ASSETS
Current Assets:
Cash and Cash Equivalents	$	6,559	$	23,395
Receivables, Net		488,002		523,644
Unbilled Revenues		175,207		208,834
Taxes Receivable		4,931		89,638
Fuel, Materials and Supplies		248,958		244,043
Regulatory Assets		255,144		238,699
Marketable Securities		70,970		78,306
Prepayments and Other Current Assets		107,701		100,441
Total Current Assets		1,357,472		1,507,000
Property, Plant and Equipment, Net		10,403,065		9,567,726
Deferred Debits and Other Assets:
Regulatory Assets		3,267,710		2,756,580
Goodwill		287,591		287,591
Marketable Securities		60,311		51,201
Derivative Assets		98,357		123,242
Other Long-Term Assets		172,560		179,261
Total Deferred Debits and Other Assets		3,886,529		3,397,875
Total Assets	$	15,647,066	$	14,472,601

The accompanying notes are an integral part of these consolidated financial statements.

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NORTHEAST UTILITIES AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	As of December 31,
(Thousands of Dollars)	2011			2010
LIABILITIES AND CAPITALIZATION
Current Liabilities:
Notes Payable to Banks	$	317,000		$	267,000
Long-Term Debt — Current Portion		331,582			66,286
Accounts Payable		633,282			417,285
Obligations to Third Party Suppliers		75,068			74,659
Accrued Taxes		69,592			107,067
Accrued Interest		69,198			74,740
Regulatory Liabilities		167,844			99,403
Derivative Liabilities		107,558			71,501
Other Current Liabilities		176,558			167,206
Total Current Liabilities		1,947,682			1,345,147
Rate Reduction Bonds		112,260			181,572
Deferred Credits and Other Liabilities:
Accumulated Deferred Income Taxes		1,868,316			1,636,750
Regulatory Liabilities		266,145			339,655
Derivative Liabilities		959,876			909,668
Accrued Pension, SERP and PBOP		1,326,037			1,050,614
Other Long-Term Liabilities		420,011			447,496
Total Deferred Credits and Other Liabilities		4,840,385			4,384,183
Capitalization:
Long-Term Debt		4,614,913			4,632,866
Noncontrolling Interest in Consolidated Subsidiary:
Preferred Stock Not Subject to Mandatory Redemption		116,200			116,200
Equity:
Common Shareholders’ Equity:
Common Shares		980,264			978,909
Capital Surplus, Paid In		1,797,884			1,777,592
Retained Earnings		1,651,875			1,452,777
Accumulated Other Comprehensive Loss		(70,686	)		(43,370	)
Treasury Stock		(346,667	)		(354,732	)
Common Shareholders’ Equity		4,012,670			3,811,176
Noncontrolling Interests		2,956			1,457
Total Equity		4,015,626			3,812,633
Total Capitalization		8,746,739			8,561,699
Commitments and Contingencies (Note 12)
Total Liabilities and Capitalization	$	15,647,066		$	14,472,601

The accompanying notes are an integral part of these consolidated financial statements.

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NORTHEAST UTILITIES AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

	For the Years Ended December 31,
(Thousands of Dollars, Except Share Information)	2011		2010			2009
Operating Revenues	$	4,465,657	$	4,898,167		$	5,439,430
Operating Expenses:
Fuel, Purchased and Net Interchange Power		1,580,683		1,985,634			2,629,619
Other Operating Expenses		1,026,192		958,417			1,001,190
Maintenance		271,779		210,283			234,173
Depreciation		302,192		300,737			309,618
Amortization of Regulatory Assets, Net		97,113		95,593			13,315
Amortization of Rate Reduction Bonds		69,912		232,871			217,941
Taxes Other Than Income Taxes		323,610		314,741			282,199
Total Operating Expenses		3,671,481		4,098,276			4,688,055
Operating Income		794,176		799,891			751,375
Interest Expense:
Interest on Long-Term Debt		231,630		231,089			224,712
Interest on Rate Reduction Bonds		8,611		20,573			36,524
Other Interest		10,184		(14,371	)		12,401
Interest Expense		250,425		237,291			273,637
Other Income, Net		27,715		41,916			37,801
Income Before Income Tax Expense		571,466		604,516			515,539
Income Tax Expense		170,953		210,409			179,947
Net Income		400,513		394,107			335,592
Net Income Attributable to Noncontrolling Interests		5,820		6,158			5,559
Net Income Attributable to Controlling Interests	$	394,693	$	387,949		$	330,033
Basic Earnings Per Common Share	$	2.22	$	2.20		$	1.91
Diluted Earnings Per Common Share	$	2.22	$	2.19		$	1.91
Weighted Average Common Shares Outstanding:
Basic		177,410,167		176,636,086			172,567,928
Diluted		177,804,568		176,885,387			172,717,246

The accompanying notes are an integral part of these consolidated financial statements.

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NORTHEAST UTILITIES AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	For the Years Ended December 31,
(Thousands of Dollars)	2011			2010			2009
Net Income	$	400,513		$	394,107		$	335,592
Other Comprehensive Income/(Loss), Net of Tax:
Qualified Cash Flow Hedging Instruments		(14,177	)		200			200
Changes in Unrealized Gains/(Losses) on Other Securities		506			402			(976	)
Change in Funded Status of Pension, SERP and PBOP Benefit Plans		(13,645	)		(505	)		(5,426	)
Other Comprehensive Income/(Loss), Net of Tax		(27,316	)		97			(6,202	)
Comprehensive Income Attributable to Noncontrolling Interests		(5,820	)		(6,158	)		(5,559	)
Comprehensive Income Attributable to Controlling Interests	$	367,377		$	388,046		$	323,831

The accompanying notes are an integral part of these consolidated financial statements.

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NORTHEAST UTILITIES AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS’ EQUITY

(Thousands of Dollars, Except Share Information)	Common Shares				Capital Surplus, Paid In			Deferred Contribution Plan			Retained Earnings			Accumulated Other Comprehensive Income/(Loss)			Treasury Stock			Total Common Shareholders’ Equity
	Shares		Amount
Balance as of January 1, 2009		155,834,361	$	881,061	$	1,475,006		$	(15,481	)	$	1,078,594		$	(37,265	)	$	(361,603	)	$	3,020,312
Adoption of Accounting Guidance for Other-Than-Temporary Impairments												728			(728	)					—
Net Income												335,592									335,592
Dividends on Common Shares — $0.95 Per Share												(162,812	)								(162,812	)
Issuance of Common Shares, $5 Par Value		19,242,939		96,215		293,502															389,717
Dividends on Preferred Stock												(5,559	)								(5,559	)
Allocation of Benefits — ESOP		542,724				(98	)		12,537												12,439
Change in Restricted Shares, Net						5,303															5,303
Tax Deduction for Stock Options Exercised and Employee Stock Purchase Plan Disqualifying Dispositions						913															913
Capital Stock Expenses, Net						(12,529	)														(12,529	)
Other Comprehensive Loss															(5,474	)					(5,474	)
Balance as of December 31, 2009		175,620,024		977,276		1,762,097			(2,944	)		1,246,543			(43,467	)		(361,603	)		3,577,902
Net Income												394,107									394,107
Dividends on Common Shares — $1.025 Per Share												(181,715	)								(181,715	)
Issuance of Common Shares, $5 Par Value		326,526		1,633		5,745															7,378
Dividends on Preferred Stock												(6,101	)								(6,101	)
Net Income Attributable to Noncontrolling Interests												(57	)								(57	)
Allocation of Benefits — ESOP		127,054				439			2,944												3,383
ESOP Benefits from Treasury Shares						3,856												(3,856	)		—
Change in Restricted Shares, Net						4,868															4,868
Change in Treasury Stock		374,477																10,727			10,727
Tax Deduction for Stock Options Exercised and Employee Stock Purchase Plan Disqualifying Dispositions						866															866
Capital Stock Expenses, Net						(279	)														(279	)
Other Comprehensive Income															97						97
Balance as of December 31, 2010		176,448,081		978,909		1,777,592			—			1,452,777			(43,370	)		(354,732	)		3,811,176
Net Income												400,513									400,513
Dividends on Common Shares — $1.10 Per Share												(195,595	)								(195,595	)
Issuance of Common Shares, $5 Par Value		271,030		1,355		4,496															5,851
Dividends on Preferred Stock												(5,559	)								(5,559	)
Net Income Attributable to Noncontrolling Interests												(261	)								(261	)
ESOP Benefits from Treasury Shares						7,048												(7,048	)		—
Change in Restricted Shares, Net						7,359															7,359
Change in Treasury Stock		439,581																15,113			15,113
Tax Deduction for Stock Options Exercised and Employee Stock Purchase Plan Disqualifying Dispositions						1,338															1,338
Capital Stock Expenses, Net						51															51
Other Comprehensive Loss															(27,316	)					(27,316	)
Balance as of December 31, 2011		177,158,692	$	980,264	$	1,797,884		$	—		$	1,651,875		$	(70,686	)	$	(346,667	)	$	4,012,670

The accompanying notes are an integral part of these consolidated financial statements.

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NORTHEAST UTILITIES AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	For the Years Ended December 31,
(Thousands of Dollars)	2011			2010			2009
Operating Activities:
Net Income	$	400,513		$	394,107		$	335,592
Adjustments to Reconcile Net Income to Net Cash Flows
Provided by Operating Activities:
Bad Debt Expense		16,420			31,352			53,947
Depreciation		302,192			300,737			309,618
Deferred Income Taxes		196,761			210,939			125,890
Pension and PBOP Expense		133,000			103,861			58,732
Pension and PBOP Contributions		(191,101	)		(90,633	)		(37,160	)
Regulatory (Under)/Over Recoveries, Net		(76,896	)		20,750			37,868
Amortization of Regulatory Assets, Net		97,113			95,593			13,315
Amortization of Rate Reduction Bonds		69,912			232,871			217,941
Derivative Assets and Liabilities		(35,441	)		(11,812	)		(18,798	)
Other		(29,751	)		(72,151	)		(26,003	)
Changes in Current Assets and Liabilities:
Receivables and Unbilled Revenues, Net		17,570			(51,285	)		91,081
Fuel, Materials and Supplies		(11,033	)		38,126			25,957
Taxes Receivable/Accrued		49,642			(82,103	)		16,194
Accounts Payable		18,916			(44,355	)		(208,180	)
Other Current Assets and Liabilities		12,569			17,466			(6,876	)
Net Cash Flows Provided by Operating Activities		970,386			1,093,463			989,118
Investing Activities:
Investments in Property, Plant and Equipment		(1,076,730	)		(954,472	)		(908,146	)
Proceeds from Sales of Marketable Securities		149,441			174,865			208,947
Purchases of Marketable Securities		(151,972	)		(177,204	)		(211,243	)
Proceeds from Sale of Assets		46,841			—			—
Other Investing Activities		13,833			(1,157	)		7,963
Net Cash Flows Used in Investing Activities		(1,018,587	)		(957,968	)		(902,479	)
Financing Activities:
Issuance of Common Shares		—			—			383,295
Cash Dividends on Common Shares		(194,555	)		(180,542	)		(162,381	)
Cash Dividends on Preferred Stock		(5,559	)		(5,559	)		(5,559	)
Increase/(Decrease) in Short-Term Debt		50,000			166,687			(518,584	)
Issuance of Long-Term Debt		627,500			145,000			462,000
Retirements of Long-Term Debt		(369,586	)		(4,286	)		(54,286	)
Retirements of Rate Reduction Bonds		(69,312	)		(260,864	)		(244,075	)
Other Financing Activities		(7,123	)		512			(9,913	)
Net Cash Flows Provided by/(Used in) Financing Activities		31,365			(139,052	)		(149,503	)
Net Decrease in Cash and Cash Equivalents		(16,836	)		(3,557	)		(62,864	)
Cash and Cash Equivalents — Beginning of Year		23,395			26,952			89,816
Cash and Cash Equivalents — End of Year	$	6,559		$	23,395		$	26,952

The accompanying notes are an integral part of these consolidated financial statements.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Refer to the Glossary of Terms included in this combined Annual Report for abbreviations and acronyms used throughout the combined notes to the consolidated financial statements.

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A. Pending Merger with NSTAR

On October 18, 2010, NU and NSTAR announced that each company’s Board of Trustees unanimously approved a merger agreement (the “agreement”), under which NSTAR will become a direct wholly owned subsidiary of NU. The transaction is structured as a merger of equals in a tax-free exchange of shares. Under the terms of the agreement, NSTAR shareholders will receive 1.312 NU common shares for each NSTAR common share that they own (the “exchange ratio”). Shareholders of both NU and NSTAR approved the pending merger at special meetings of shareholders held on March 4, 2011. Post-transaction, NU will provide electric and natural gas energy delivery service to approximately 3.5 million electric and natural gas customers through six regulated electric and natural gas utilities in Connecticut, Massachusetts and New Hampshire.

The exchange ratio was structured to result in a no premium merger based on the average closing share price of each company’s common shares for the 20 trading days preceding the announcement. Based on the number of NU common shares and NSTAR common shares estimated to be outstanding immediately prior to the closing of the merger, upon such closing, NU will be owned approximately 56 percent by NU shareholders and approximately 44 percent by former NSTAR shareholders. It is anticipated that NU will issue approximately 137 million common shares to the NSTAR shareholders as a result of the merger. Subject to the conditions in the agreement, NU’s first quarterly dividend per common share paid after the closing of the merger will be increased to an amount that is at least equal, after adjusting for the exchange ratio, to NSTAR’s last quarterly dividend paid prior to the closing.

At closing, NU will acquire NSTAR and, in accordance with accounting standards for business combinations, account for the transaction as an acquisition of NSTAR by NU.

Completion of the merger is subject to various customary conditions, including, among others, receipt of all required regulatory approvals. NU and NSTAR are awaiting approvals from PURA and the DPU. PURA is scheduled to issue a final decision on April 2, 2012.

On February 15, 2012, NU and NSTAR reached comprehensive merger-related settlement agreements with both the Massachusetts Attorney General and the DOER. The first settlement agreement covers a variety of rate-making and rate design issues, including a distribution rate freeze until 2016 for WMECO, NSTAR Electric Company and NSTAR Gas Company. The second settlement agreement covers a variety of matters impacting the advancement of Massachusetts clean energy goals established by the Green Communities Act and Global Warming Solutions Act. Pursuant to the terms and provisions of the settlement agreements, all parties agree that the proposed merger between NU and NSTAR is consistent with the public interest and should be approved by the DPU. However, the settlement agreements allow the Attorney General and DOER to terminate their respective agreements for any reason at any time prior to approval by the DPU. All parties to the settlement agreements have requested that the DPU approve the merger on April 4, 2012. Under the terms of the settlement agreements, WMECO would record a $3 million pre-tax charge in 2012 pending completion of the merger.

B. Presentation

The consolidated financial statements of NU, CL&P, PSNH and WMECO include the accounts of all their respective subsidiaries. Intercompany transactions have been eliminated in consolidation.

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The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

NU and a subsidiary of NSTAR have formed, on a 75 percent and 25 percent basis, respectively, a limited liability company, NPT, to construct, own and operate the Northern Pass transmission project. NPT and Hydro Renewable Energy entered into a TSA whereby NPT will sell to Hydro Renewable Energy electric transmission rights over the Northern Pass for a 40-year term at cost of service rates. NPT will be required to maintain a capital structure of 50 percent debt and 50 percent equity. NU determined, through its controlling financial interest in NPT, that it must consolidate NPT, as NU has the power to direct the activities of NPT, which most significantly impact its economic performance, including permitting and siting and operation and maintenance activities over the term of the TSA.

In accordance with accounting guidance on noncontrolling interests in consolidated financial statements, the Preferred Stock of CL&P, which is not owned by NU or its consolidated subsidiaries and is not subject to mandatory redemption, has been presented as a noncontrolling interest in CL&P in the accompanying consolidated financial statements of NU. The Preferred Stock of CL&P is considered to be temporary equity and has been classified between liabilities and permanent shareholders’ equity on the accompanying consolidated balance sheets of NU and CL&P due to a provision in CL&P’s certificate of incorporation that grants preferred stockholders the right to elect a majority of CL&P’s board of directors should certain conditions exist, such as if preferred dividends are in arrears for one year. For the years ended December 31, 2011, 2010 and 2009, there was no change in NU parent’s 100 percent ownership of the common equity of CL&P.

The Net Income reported in the accompanying consolidated statements of income and cash flows represents consolidated net income prior to apportionment to noncontrolling interests, which is represented by dividends on preferred stock of CL&P and NSTAR’s portion of the net income of NPT.

As of December 31, 2011, NU, CL&P, PSNH and WMECO have adjusted the presentation of Regulatory Assets and Liabilities to reflect the current portions, and related deferred tax amounts, as current assets and liabilities on the consolidated balance sheets. Amounts as of December 31, 2010 have been reclassified to conform to the December 31, 2011 presentation. For additional information, see Note 2, “Regulatory Accounting,” to the consolidated financial statements.

Certain other reclassifications of prior year data were made in the accompanying consolidated balance sheets for all companies presented and statements of cash flows for NU and PSNH. These reclassifications were made to conform to the current year’s presentation.

NU evaluates events and transactions that occur after the balance sheet date but before financial statements are issued and recognizes in the financial statements the effects of all subsequent events that provide additional evidence about conditions that existed as of the balance sheet date and discloses, but does not recognize, in the financial statements subsequent events that provide evidence about the conditions that arose after the balance sheet date but before the financial statements are issued. NU did not identify any such events that required recognition or disclosure under this guidance.

C. About NU, CL&P, PSNH and WMECO

Consolidated: NU is the parent company of CL&P, PSNH, WMECO, and other subsidiaries. NU was formed on July 1, 1966 when CL&P, WMECO and The Hartford Electric Light Company affiliated under the common ownership of NU. In 1992, PSNH became a subsidiary of NU. On March 1, 2000, natural gas became an integral part of NU’s Connecticut operations when NU’s merger with Yankee and its principal subsidiary, Yankee Gas, was completed. NU, CL&P, PSNH and WMECO are reporting companies under the Securities

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Exchange Act of 1934. NU is a public utility holding company under the Public Utility Holding Company Act of 2005. Arrangements among the regulated electric companies and other NU companies, outside agencies and other utilities covering interconnections, interchange of electric power and sales of utility property are subject to regulation by the FERC. The Regulated companies are subject to further regulation for rates, accounting and other matters by the FERC and/or applicable state regulatory commissions (the PURA for CL&P and Yankee Gas, the NHPUC as well as certain regulatory oversight by the Vermont Department of Public Service and the Maine Public Utilities Commission for PSNH, and the DPU for WMECO).

Regulated Companies: CL&P, PSNH and WMECO furnish franchised retail electric service in Connecticut, New Hampshire and Massachusetts, respectively. Yankee Gas owns and operates Connecticut’s largest natural gas distribution system. CL&P, PSNH and WMECO’s results include the operations of their respective distribution and transmission segments. PSNH and WMECO’s distribution results include the operations of their respective generation businesses. Yankee Gas’ results include the operations of its natural gas distribution segment. NPT was formed to construct, own and operate the Northern Pass line, a new HVDC transmission line from Québec to New Hampshire that will interconnect with a new HVDC transmission line being developed by a transmission subsidiary of HQ.

Other: As of December 31, 2011, NU Enterprises’ primary business consisted of Select Energy’s remaining energy wholesale marketing contracts and NGS’ operation and maintenance agreements as well as its subsidiary, Boulos, an electrical contractor based in Maine that NU Enterprises continues to own and manage. NUSCO, RRR, Renewable Properties, Inc. and Properties, Inc. provide support services to NU, including its regulated companies.

D. Accounting Standards Issued But Not Yet Adopted

In May 2011, the Financial Accounting Standards Board and the International Accounting Standards Board issued a final Accounting Standards Update on fair value measurement, effective January 1, 2012, that is not expected to have an impact on NU’s financial position, results of operations or cash flows, but will require additional financial statement disclosures related to fair value measurements.

In September 2011, the Financial Accounting Standards Board issued a final Accounting Standards Update on testing goodwill for impairment, effective January 1, 2012 with early adoption permitted. The standard provides the option to perform a qualitative assessment to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying value; if so, quantitative testing is required. The standard does not change existing guidance relating to when an entity should test goodwill for impairment or the methodology to be utilized in performing quantitative testing. The standard will not have an impact on NU’s financial position, results of operations or cash flows.

E. Cash and Cash Equivalents

Cash and cash equivalents include cash on hand and short-term cash investments that are highly liquid in nature and have original maturities of three months or less. At the end of each reporting period, any overdraft amounts are reclassified from Cash and Cash Equivalents to Accounts Payable on the accompanying consolidated balance sheets.

F. Provision for Uncollectible Accounts

NU, including CL&P, PSNH and WMECO, maintains a provision for uncollectible accounts to record receivables at an estimated net realizable value. This provision is determined based upon a variety of factors, including applying an estimated uncollectible account percentage to each receivable aging category, based upon historical collection and write-off experience and management’s assessment of collectibility from individual customers. Management reviews at least quarterly the collectibility of the receivables, and if circumstances

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change, collectibility estimates are adjusted accordingly. Receivable balances are written off against the provision for uncollectible accounts when the accounts are terminated and these balances are deemed to be uncollectible.

The provision for uncollectible accounts, which is included in Receivables, Net on the accompanying consolidated balance sheets, is as follows:

	As of December 31,
(Millions of Dollars)	2011		2010
NU	$	34.9	$	39.8
CL&P		14.8		17.2
PSNH		7.2		6.8
WMECO		4.6		6.0

The PURA allows CL&P and Yankee Gas to accelerate the recovery of uncollectible hardship accounts receivable outstanding for greater than 90 days. As a result of the January 2011 DPU rate case decision, WMECO is allowed to recover amounts associated with uncollectible hardship receivables in rates. As of December 31, 2011, CL&P, WMECO and Yankee Gas had uncollectible hardship accounts receivable reserves in the amount of $68.6 million, $5.4 million and $6.8 million, respectively, with the corresponding bad debt expense recorded as Regulatory Assets or Other Long-Term Assets as these amounts are probable of recovery. As of December 31, 2010, these amounts totaled $65 million, $6.9 million and $7.5 million, respectively.

G. Fuel, Materials and Supplies and Allowance Inventory

Fuel, Materials and Supplies include natural gas, coal, oil and materials purchased primarily for construction or operation and maintenance purposes. Natural gas inventory, coal and oil are valued at their respective weighted average cost. Materials and supplies are valued at the lower of average cost or market.

PSNH is subject to federal and state laws and regulations that regulate emissions of air pollutants, including SO₂, CO₂, and NO_x related to its regulated generation units, and uses SO₂, CO₂, and NO_x emissions allowances. At the end of each compliance period, PSNH is required to relinquish SO₂, CO₂, and NO_x emissions allowances corresponding to the actual respective emissions emitted by its generating units over the compliance period. SO₂ and NO_x emissions allowances are obtained through an annual allocation from the federal and state regulators that are granted at no cost and through purchases from third parties. CO₂ emissions allowances are acquired through auctions and through purchases from third parties.

SO₂, CO₂, and NO_x emissions allowances are recorded within Fuel, Materials and Supplies and are classified on the balance sheet as short-term or long-term depending on the period in which they are expected to be utilized against actual emissions. As of December 31, 2011 and 2010, PSNH had $0.8 million and $7.1 million, respectively, of short-term SO₂, CO₂, and NO_x emissions allowances classified as Fuel, Materials and Supplies on the accompanying consolidated balance sheets and $19.4 million and $18.2 million, respectively, of long-term SO₂ and CO₂ emissions allowances classified as Other Long-Term Assets on the accompanying consolidated balance sheets.

SO₂, CO₂, and NO_x emissions allowances are charged to expense based on their weighted average cost as they are utilized against emissions volumes at PSNH’s generating units. PSNH recorded expenses of $5.1 million, $6.6 million and $7.6 million for the years ended December 31, 2011, 2010, and 2009, respectively, which were included in Fuel, Purchased and Net Interchange Power on the accompanying consolidated statements of income. These costs are recovered from customers through PSNH ES revenues.

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H. Restricted Cash and Other Deposits

As of December 31, 2011, NU, CL&P and PSNH had $17.9 million, $9.4 million, and $7 million, respectively, of restricted cash, primarily relating to amounts held in escrow related to property damage at CL&P and insurance proceeds on bondable property at PSNH, which were included in Prepayments and Other Current Assets on the accompanying consolidated balance sheets. There was no restricted cash held as of December 31, 2010.

As of December 31, 2011, PSNH and WMECO, and as of December 31, 2010, CL&P, PSNH and WMECO, had amounts on deposit related to subsidiaries used to facilitate the issuance of RRBs. In addition, NU, CL&P, PSNH and WMECO had other cash deposits held with unaffiliated parties, including deposits related to Select Energy’s position in transactions with counterparties, as of December 31, 2011 and 2010. These amounts are included in Prepayments and Other Current Assets and Other Long-Term Assets on the accompanying consolidated balance sheets. These amounts were as follows:

NU	As of December 31,
(Millions of Dollars)	2011		2010
Rate Reduction Bond Deposits	$	29.5	$	53.1
Other Deposits		17.7		29.9

	As of December 31,
	2011						2010
(Millions of Dollars)	CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
Rate Reduction Bond Deposits	$	—	$	24.4	$	5.1	$	22.1	$	26.9	$	4.1
Other Deposits		1.1		2.5		2.2		2.1		2.8		1.2

I. Fair Value Measurements

NU, including CL&P, PSNH, and WMECO, applies fair value measurement guidance to all derivative contracts recorded at fair value and to the marketable securities held in the NU supplemental benefit trust and WMECO’s spent nuclear fuel trust. Fair value measurement guidance is also applied to investment valuations used to calculate the funded status of NU’s Pension and PBOP Plans and non-recurring fair value measurements of NU’s non-financial assets and liabilities.

Fair Value Hierarchy: In measuring fair value, NU uses observable market data when available and minimizes the use of unobservable inputs. Inputs used in fair value measurements are categorized into three fair value hierarchy levels for disclosure purposes. The entire fair value measurement is categorized based on the lowest level of input that is significant to the fair value measurement. NU evaluates the classification of assets and liabilities measured at fair value on a quarterly basis, and NU’s policy is to recognize transfers between levels of the fair value hierarchy as of the end of the reporting period. The three levels of the fair value hierarchy are described below:

Level 1 — Inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 — Inputs are quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations in which all significant inputs are observable.

Level 3 — Quoted market prices are not available. Fair value is derived from valuation techniques in which one or more significant inputs or assumptions are unobservable. Where possible, valuation techniques incorporate observable market inputs that can be validated to external sources such as industry exchanges, including prices of energy and energy-related products.

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Determination of Fair Value: The valuation techniques and inputs used in NU’s fair value measurements are described in Note 4, “Derivative Instruments,” and Note 5, “Marketable Securities,” to the consolidated financial statements.

J. Derivative Accounting

Most of CL&P, PSNH and WMECO’s contracts for the purchase and sale of energy or energy-related products are derivatives, along with all but one of NU Enterprises’ remaining wholesale marketing contracts. The accounting treatment for energy contracts entered into varies and depends on the intended use of the particular contract and on whether or not the contract is a derivative.

The application of derivative accounting is complex and requires management judgment in the following respects: identification of derivatives and embedded derivatives, election and designation of the “normal purchases or normal sales” (normal) exception, identifying, electing and designating hedge relationships, assessing and measuring hedge effectiveness, and determining the fair value of derivatives. All of these judgments, depending upon their timing and effect, can have a significant impact on the consolidated financial statements.

The fair value of derivatives is based upon the contract terms and conditions and the underlying market price or fair value per unit. When quantities are not specified in the contract, the Company determines whether the contract has a determinable quantity by using amounts referenced in default provisions and other relevant sections of the contract. The estimated quantities to be served are updated during the term of the contract. The fair value of derivative assets and liabilities with the same counterparty are offset and recorded as a net derivative asset or liability to the consolidated balance sheets.

The judgment applied in the election of the normal exception (and resulting accrual accounting) includes the conclusion that it is probable at the inception of the contract and throughout its term that it will result in physical delivery of the underlying product and that the quantities will be used or sold by the business in the normal course of business. If facts and circumstances change and management can no longer support this conclusion, then the normal exception and accrual accounting is terminated and fair value accounting is applied prospectively.

The remaining wholesale marketing contracts that are marked-to-market derivative contracts are not considered to be held for trading purposes, and sales and purchase activity is reported on a net basis in Fuel, Purchased and Net Interchange Power on the consolidated statements of income.

For further information regarding derivative contracts of NU, CL&P, PSNH and WMECO and their accounting, see Note 4, “Derivative Instruments,” to the consolidated financial statements.

K. Equity Method Investments

Regional Nuclear Companies: As of December 31, 2011, CL&P, PSNH and WMECO owned common stock in three regional nuclear generation companies (Yankee Companies). Each of the Yankee Companies owned a single nuclear generating facility that has been decommissioned. Ownership interests in the Yankee Companies as of December 31, 2011, which are accounted for on the equity method, are as follows:

(Percent)	CYAPC			YAEC			MYAPC
CL&P		34.5			24.5			12.0
PSNH		5.0			7.0			5.0
WMECO		9.5			7.0			3.0
Total NU		49.0	%		38.5	%		20.0	%

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The total carrying values of ownership interests in CYAPC, YAEC and MYAPC, which are included in Other Long-Term Assets on the accompanying consolidated balance sheets and in the Regulated companies — Electric distribution reportable segment, are as follows:

(Millions of Dollars)	2011		2010
CL&P	$	1.4	$	1.3
PSNH		0.3		0.3
WMECO		0.4		0.4
Total NU	$	2.1	$	2.0

For further information on the Yankee Companies, see Note 12C, “Commitments  and Contingencies — Deferred Contractual Obligations,” to the consolidated financial statements.

Other: NU has a 22.7 percent equity ownership interest in two companies that transmit electricity imported from the Hydro-Québec system in Canada. NU’s investment totaled $4.6 million and $5.6 million as of December 31, 2011 and 2010, respectively. As of December 31, 2011, NU also had an equity ownership of $4.2 million in an energy investment fund.

These equity investments are included in Other Long-Term Assets on the accompanying consolidated balance sheets and net earnings related to these equity investments are included in Other Income, Net on the accompanying consolidated statements of income.

L. Revenues

Regulated Companies: The Regulated companies’ retail revenues are based on rates approved by the state regulatory commissions. In general, rates can only be changed through formal proceedings with the state regulatory commissions. The Regulated companies also utilize regulatory commission-approved tracking mechanisms to recover certain costs as incurred. The tracking mechanisms allow for rates to be changed periodically, with overcollections refunded to customers or undercollections collected from customers in future periods. Beginning in 2011, WMECO was allowed to establish a revenue decoupling mechanism to recover a pre-established level of baseline distribution delivery service revenues of $125.6 million per year, independent of actual customer usage. Such decoupling mechanisms effectively break the relationship between kWhs consumed by customers and revenues recognized.

Energy purchases under derivative instruments are recorded in Fuel, Purchased and Net Interchange Power, and sales of energy associated with these purchases are recorded in Operating Revenues.

Regulated Companies’ Unbilled Revenues: Unbilled revenues represent an estimate of electricity or natural gas delivered to customers for which the customers have not yet been billed. Unbilled revenues are included in Operating Revenues on the consolidated statements of income and are assets on the consolidated balance sheets that are reclassified to accounts receivable in the following month as customers are billed. Such estimates are subject to adjustment when actual meter readings become available, when changes in estimating methodology occur and under other circumstances.

The Regulated companies estimate unbilled revenues monthly using the daily load cycle method. The daily load cycle method allocates billed sales to the current calendar month based on the daily load for each billing cycle. The billed sales are subtracted from total month load, net of delivery losses, to estimate unbilled sales. Unbilled revenues are estimated by first allocating sales to the respective customer classes, then applying an average rate by customer class to the estimate of unbilled sales.

Regulated Companies’ Transmission Revenues — Wholesale Rates: Wholesale transmission revenues are based on formula rates that are approved by the FERC. Wholesale transmission revenues for CL&P, PSNH, and WMECO are collected under the ISO-NE FERC, Transmission, Markets and Services Tariff (ISO-NE Tariff).

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The ISO-NE Tariff includes RNS and Schedule 21 — NU rate schedules to recover fees for transmission and other services. The RNS rate, administered by ISO-NE and billed to all New England transmission users, including CL&P, PSNH and WMECO’s transmission businesses, is reset on June 1^st of each year and recovers the revenue requirements associated with transmission facilities that benefit the entire New England region. The Schedule 21 — NU rate, administered by NU, is reset on January 1^st and June 1^st of each year and recovers the revenue requirements for local transmission facilities and other transmission costs not recovered under the RNS rate. The Schedule 21 — NU rate calculation recovers total transmission revenue requirements net of revenues received from other sources (i.e., RNS, rentals, etc.), thereby ensuring that NU recovers all of CL&P’s, PSNH’s and WMECO’s regional and local revenue requirements as prescribed in the ISO-NE Tariff. Both the RNS and Schedule 21 — NU rates provide for the annual reconciliation and recovery or refund of estimated (or projected) costs to actual costs. The financial impacts of differences between actual and projected costs are deferred for future recovery from, or refunded to, transmission customers. As of December 31, 2011, the Schedule 21 — NU rates were in a total overrecovery position of $31.4 million ($18.6 million for CL&P, $1.7 million for PSNH and $11.1 million for WMECO), which will be refunded to transmission customers in June 2012.

Regulated Companies’ Transmission Revenues — Retail Rates: A significant portion of the NU transmission segment revenue comes from ISO-NE charges to the distribution segments of CL&P, PSNH and WMECO, each of which recovers these costs through rates charged to their retail customers. CL&P, PSNH and WMECO each have a retail transmission cost tracking mechanism as part of their rates, which allows the electric distribution companies to charge their retail customers for transmission costs on a timely basis.

M. Operating Expenses

Costs related to fuel (and natural gas costs as it related to Yankee Gas) included in Fuel, Purchased and Net Interchange Power on the accompanying consolidated statements of income were as follows:

	For the Years Ended December 31,
(Millions of Dollars)	2011		2010		2009
NU	$	307.9	$	391.6	$	401.7
PSNH		115.9		184.3		174.1
Yankee Gas		191.3		206.4		226.1

N. Allowance for Funds Used During Construction

AFUDC is included in the cost of the Regulated companies’ utility plant and represents the cost of borrowed and equity funds used to finance construction. The portion of AFUDC attributable to borrowed funds is recorded as a reduction of Other Interest Expense, and the AFUDC related to equity funds is recorded as Other Income, Net on the accompanying consolidated statements of income.

NU	For the Years Ended December 31,
(Millions of Dollars, except percentages)	2011			2010			2009
AFUDC:
Borrowed Funds	$	11.8		$	10.2		$	5.9
Equity Funds		22.5			16.7			9.4
Total	$	34.3		$	26.9		$	15.3
Average AFUDC Rate		7.3	%		7.1	%		6.1	%

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	For the Years Ended December 31,
	2011									2010									2009
(Millions of Dollars, except percentages)	CL&P			PSNH			WMECO			CL&P			PSNH			WMECO			CL&P			PSNH			WMECO
AFUDC:
Borrowed Funds	$	3.3		$	7.1		$	0.5		$	2.7		$	6.6		$	0.3		$	2.2		$	3.1		$	0.2
Equity Funds		6.0			13.2			1.0			4.9			10.4			0.6			5.7			3.6			—
Total	$	9.3		$	20.3		$	1.5		$	7.6		$	17.0		$	0.9		$	7.9		$	6.7		$	0.2
Average AFUDC Rate		8.3	%		7.1	%		7.4	%		8.3	%		6.8	%		6.4	%		7.2	%		6.2	%		1.7	%

The Regulated companies’ average AFUDC rate is based on a FERC-prescribed formula that produces an average rate using the cost of a company’s short-term financings as well as a company’s capitalization (preferred stock, long-term debt and common equity). The average rate is applied to average eligible CWIP amounts to calculate AFUDC.

O. Other Income, Net

The other income/(loss) items included within Other Income, Net on the accompanying consolidated statements of income primarily consist of investment income/(loss), interest income, AFUDC related to equity funds and equity in earnings, which relates to the Company’s investments, including investments of CL&P, PSNH and WMECO in the Yankee Companies and NU’s investment in two regional transmission companies.

P. Other Taxes

Certain excise taxes levied by state or local governments are collected by CL&P and Yankee Gas from their respective customers. These excise taxes are shown on a gross basis with collections in revenues and payments in expenses. Gross receipts taxes, franchise taxes and other excise taxes were included in Operating Revenues and Taxes Other Than Income Taxes on the accompanying consolidated statements of income as follows:

	For the Years Ended December 31,
(Millions of Dollars)	2011		2010		2009
NU	$	137.8	$	143.7	$	135.6
CL&P		121.6		128.0		119.0

Certain sales taxes are also collected by CL&P, WMECO, and Yankee Gas from their respective customers as agents for state and local governments and are recorded on a net basis with no impact on the accompanying consolidated statements of income.

Q. Supplemental Cash Flow Information

NU	For the Years Ended December 31,
(Millions of Dollars)	2011			2010		2009
Cash Paid/(Received) During the Year for:
Interest, Net of Amounts Capitalized	$	256.3		$	258.3	$	263.8
Income Taxes		(76.6	)		84.5		35.1
Non-Cash Investing Activities:
Capital Expenditures Incurred But Not Paid		168.5			127.9		125.5

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	For the Years Ended December 31,
	2011									2010						2009
(Millions of Dollars)	CL&P			PSNH			WMECO			CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
Cash Paid/(Received) During the Year for:
Interest, Net of Amounts Capitalized	$	136.6		$	49.3		$	22.1		$	142.2	$	51.4	$	20.2	$	146.7	$	49.0	$	19.4
Income Taxes		(27.5	)		(29.0	)		(4.9	)		71.5		1.6		5.0		42.4		12.8		(9.1	)
Non-Cash Investing Activities:
Capital Expenditures Incurred But Not Paid		32.7			51.1			61.3			46.2		35.8		21.2		48.2		46.5		10.3

The majority of the short-term borrowings of NU, including CL&P, PSNH and WMECO, have original maturities of three months or less. Accordingly, borrowings and repayments are shown net on the statement of cash flows.

R. Self-Insurance Accruals

NU, including CL&P, PSNH and WMECO, are self-insured for employee medical coverage, long-term disability coverage and general liability coverage and up to certain limits for workers compensation coverage. Liabilities for insurance claims include accruals of estimated settlements for known claims, as well as accruals of estimates of incurred but not reported claims. Accruals for employee medical coverage are included in Other Current Liabilities and the remainder of these accruals are included in Other Long-Term Liabilities on the accompanying consolidated balance sheets. In estimating these costs, NU considers historical loss experience and makes judgments about the expected levels of costs per claim. These claims are accounted for based on estimates of the undiscounted claims, including those claims incurred but not reported.

S. Related Parties

Several wholly owned subsidiaries of NU provide support services for NU, including CL&P, PSNH and WMECO. NUSCO provides centralized accounting, administrative, engineering, financial, information technology, legal, operational, planning, purchasing, and other services to NU’s companies. RRR, Renewable Properties, Inc. and Properties, Inc., three other NU subsidiaries, construct, acquire or lease some of the property and facilities used by NU’s companies.

As of both December 31, 2011 and 2010, CL&P, PSNH and WMECO had long-term receivables from NUSCO in the amount of $25 million, $3.8 million and $5.5 million, respectively, which are included in Other Long-Term Assets on the accompanying consolidated balance sheets related to the funding of investments held in trust by NUSCO in connection with certain postretirement benefits for CL&P, PSNH and WMECO employees. These amounts have been eliminated in consolidation on the NU financial statements.

Included in the CL&P, PSNH and WMECO consolidated balance sheets as of December 31, 2011 and 2010 are Accounts Receivable from Affiliated Companies and Accounts Payable to Affiliated Companies relating to transactions between CL&P, PSNH and WMECO and other subsidiaries that are wholly owned by NU. These amounts have been eliminated in consolidation on the NU financial statements.

The NU Foundation is an independent not-for-profit charitable entity designed to fund initiatives or entities that emphasize economic development, workforce training and education, and a clean and healthy environment. The board of directors of the NU Foundation consists of certain NU officers. The NU Foundation is not included

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in the consolidated financial statements of NU as it is a not-for-profit entity and the Company does not have title to the NU Foundation’s assets and cannot receive contributions back from the NU Foundation. NU did not make any contributions to the NU Foundation in 2011 or 2009. NU, CL&P, PSNH and WMECO recorded aggregate contributions to the NU Foundation of $2 million in 2010.

2. REGULATORY ACCOUNTING

The Regulated companies continue to be rate-regulated on a cost-of-service basis; therefore, the accounting policies of the Regulated companies conform to GAAP applicable to rate-regulated enterprises and historically reflect the effects of the rate-making process.

Management believes it is probable that the Regulated companies will recover their respective investments in long-lived assets, including regulatory assets. If management determined that it could no longer apply the accounting guidance applicable to rate-regulated enterprises to the Regulated companies’ operations, or that management could not conclude it is probable that costs would be recovered or reflected in future rates, the costs would be charged to net income in the period in which the determination is made.

Regulatory Assets: The components of regulatory assets are as follows:

NU	As of December 31,
(Millions of Dollars)	2011		2010
Deferred Benefit Costs	$	1,360.5	$	1,094.2
Regulatory Assets Offsetting Derivative Liabilities		939.6		859.7
Securitized Assets		101.8		171.7
Income Taxes, Net		425.4		401.5
Unrecovered Contractual Obligations		100.9		123.2
Regulatory Tracker Deferrals		45.9		70.3
Storm Cost Deferrals		356.0		60.1
Asset Retirement Obligations		47.5		45.3
Losses on Reacquired Debt		24.5		21.5
Deferred Environmental Remediation Costs		38.5		36.8
Deferred Operation and Maintenance Costs		4.0		29.5
Other Regulatory Assets		78.2		81.5
Total Regulatory Assets	$	3,522.8	$	2,995.3
Less: Current Portion	$	255.1	$	238.7
Total Long-Term Regulatory Assets	$	3,267.7	$	2,756.6

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	As of December 31,
	2011						2010
(Millions of Dollars)	CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
Deferred Benefit Costs	$	572.8	$	200.0	$	118.9	$	471.8	$	152.6	$	96.0
Regulatory Assets Offsetting Derivative Liabilities		932.0		—		7.3		846.2		12.8		—
Securitized Assets		—		76.4		25.4		—		129.8		41.9
Income Taxes, Net		339.6		38.0		17.8		328.9		31.4		16.8
Unrecovered Contractual Obligations		80.9		—		20.0		97.9		—		25.3
Regulatory Tracker Deferrals		5.5		11.9		22.1		35.5		14.7		15.2
Storm Cost Deferrals		268.3		44.0		43.7		4.0		40.7		15.4
Asset Retirement Obligations		27.9		13.5		3.2		24.9		14.7		3.0
Losses on Reacquired Debt		13.9		9.0		0.3		11.2		8.4		0.4
Deferred Environmental Remediation Costs		—		9.7		—		—		9.7		—
Deferred Operation and Maintenance Costs		4.0		—		—		29.5		—		—
Other Regulatory Assets		29.1		25.6		10.0		29.0		19.6		13.1
Total Regulatory Assets	$	2,274.0	$	428.1	$	268.7	$	1,878.9	$	434.4	$	227.1
Less: Current Portion	$	170.2	$	34.2	$	35.5	$	157.5	$	39.2	$	19.5
Total Long-Term Regulatory Assets	$	2,103.8	$	393.9	$	233.2	$	1,721.4	$	395.2	$	207.6

Additionally, the Regulated companies had $32.4 million ($5 million for CL&P, $22.4 million for PSNH, and $1.6 million for WMECO) and $37.5 million ($0.6 million for CL&P, $26.5 million for PSNH, and $1.9 million for WMECO) of regulatory costs as of December 31, 2011 and 2010, respectively, which were included in Other Long-Term Assets on the accompanying consolidated balance sheets. These amounts represent incurred costs that have not yet been approved for recovery by the applicable regulatory agency. Management believes these costs are probable of recovery in future cost-of-service regulated rates.

Of the total December 31, 2011 amount, $21.7 million for PSNH related to costs incurred for Tropical Storm Irene and the October snowstorm restorations that met the NHPUC criteria for cost deferral. Refer to the “Storm Cost Deferrals” section below for further discussion.

The December 31, 2010 balance of regulatory costs included in Other Long-Term Assets at PSNH included costs incurred for the February 2010 wind storm restorations that met the NHPUC specified criteria for cost deferral and certain costs related to previously recognized lost tax benefits as a result of a provision in the 2010 Healthcare Act that eliminated the tax deductibility of actuarially equivalent Medicare Part D benefits for retirees. During June 2011, the NHPUC approved these costs for recovery, with a return on the storm costs, and PSNH recorded a regulatory asset of $10.9 million related to the wind storm restoration costs and $7.2 million for the recovery of the lost tax benefits. On July 28, 2010, PURA allowed the creation by CL&P of a regulatory asset for the recovery of lost tax benefits as a result of the 2010 Healthcare Act, subject to review in its next rate case. On January 31, 2011, the DPU allowed the creation by WMECO of a regulatory asset as a result of the 2010 Healthcare Act. NU has concluded that the costs associated with these lost tax benefits are probable of recovery and as of December 31, 2011, $32.2 million ($18.9 million for CL&P, $6.6 million for PSNH, $3.2 million for WMECO and $3.5 million for Yankee Gas) are included in Other Regulatory Assets in the table above. These assets are not earning a return. PSNH and WMECO’s costs are being recovered over a period of 5 to 7 years. For further information regarding the 2010 Healthcare Act, see Note 11, “Income Taxes,” to the consolidated financial statements.

For rate-making purposes, the Regulated companies recover the cost of allowed equity return on certain regulatory assets. This cost, which is not recorded on the accompanying consolidated balance sheets, totaled $3.5 million and $6.1 million for CL&P and $7.6 million and $0.5 million for PSNH as of December 31, 2011 and 2010, respectively. These costs will be recovered in rates.

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Deferred Benefit Costs: NU’s Pension, SERP and PBOP Plans are accounted for in accordance with accounting guidance on defined benefit pension and other postretirement plans. Under this accounting guidance, the funded status of pension and other postretirement plans is recorded with an offset to Accumulated Other Comprehensive Income/(Loss) and is remeasured annually. However, because the Regulated companies are rate-regulated on a cost-of-service basis, offsets were recorded as regulatory assets as of December 31, 2011 and 2010 as these amounts have been, and continue to be, recoverable in cost-of-service regulated rates. Regulatory accounting was also applied to the portions of the NUSCO costs that support the Regulated companies, as these amounts are also recoverable. The deferred benefit costs of CL&P and PSNH are not in rate base. WMECO’s deferred benefit costs are earning an equity return at the same rate as the assets included in rate base. Pension and PBOP costs are expected to be amortized into expense over the average future employee service period of approximately 10 and 9 years, respectively.

Regulatory Assets Offsetting Derivative Liabilities: The regulatory assets offsetting derivative liabilities relate to the fair value of contracts used to purchase power and other related contracts that will be collected from customers in the future. Included in these amounts are derivative liabilities relating to CL&P’s capacity contracts, referred to as CfDs. See Note 4, “Derivative Instruments,” to the consolidated financial statements for further information. These assets are excluded from rate base and are being recovered as the actual settlement occurs over the duration of the contracts.

Securitized Assets: In April 2001, PSNH issued RRBs in the amount of $525 million. PSNH used the majority of the proceeds from that issuance to buydown its power contracts with an affiliate, North Atlantic Energy Corporation. In May 2001, WMECO issued $155 million in RRBs and used the majority of the proceeds from that issuance to buyout an IPP contract. These assets are not earning an equity return and are being recovered over the amortization period of their associated RRBs. PSNH RRBs are scheduled to fully amortize by May 1, 2013 and WMECO RRBs are scheduled to fully amortize by June 1, 2013.

Income Taxes, Net: The tax effect of temporary differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of taxable income, including those differences relating to uncertain tax positions) is accounted for in accordance with the rate-making treatment of the applicable regulatory commissions and accounting guidance for income taxes. Differences in income taxes between the accounting guidance and the rate-making treatment of the applicable regulatory commissions are recorded as regulatory assets. These assets are excluded from rate base. For further information regarding income taxes, see Note 11, “Income Taxes,” to the consolidated financial statements.

Unrecovered Contractual Obligations: Under the terms of contracts with CYAPC, YAEC and MYAPC, CL&P, PSNH and WMECO are responsible for their proportionate share of the remaining costs of the nuclear facilities, including decommissioning. A portion of these amounts was recorded as unrecovered contractual obligations regulatory assets. These obligations for CL&P are earning a return and are being recovered through the CTA. Amounts for WMECO are being recovered without a return and are anticipated to be recovered by 2013, the scheduled completion date of stranded cost recovery. Amounts for PSNH were fully recovered by 2006.

Regulatory Tracker Deferrals: Regulatory tracker deferrals are approved rate mechanisms that allow utilities to recover costs in specific business segments through reconcilable tracking mechanisms that are reviewed at least annually by the applicable regulatory commission. The reconciliation process produces deferrals for future recovery or refund, which can be either under or over-collections to be included in future customer rates each year. Regulatory tracker deferrals are recorded as regulatory assets if costs are in excess of collections from customers and are recorded as regulatory liabilities if collections from customers are in excess of costs. All material regulatory tracker deferrals that are in a regulatory asset position are earning some form of return. The following regulatory tracker deferrals were recorded as either regulatory assets or liabilities as of December 31, 2011 and 2010:

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CL&P Reconciliation Mechanisms: The PURA has established several reconciliation mechanisms, which allow CL&P to recover costs associated with the procurement of energy for SS and LRS, congestion and other costs associated with power market rules approved by the FERC or as approved by the PURA, C&LM programs, the retail transmission of energy, certain regulatory and energy public policy costs, such as hardship protection costs and transition period property taxes, and stranded costs, such as the amortization of regulatory assets and IPP over market costs. As part of the CTA mechanism reconciliation process, CL&P has also established an obligation to refund the variable incentive portion of its transition service procurement fee, which totaled $26.3 million and $24.7 million as of December 31, 2011 and 2010, respectively, and was recorded as a regulatory liability.

PSNH Reconciliation Mechanisms: The NHPUC permits PSNH to recover the costs of providing generation, restructuring costs as a result of deregulation, the retail transmission of energy, and the cost of C&LM programs through various reconciliation mechanisms.

WMECO Reconciliation Mechanisms: The DPU has approved a number of individual cost and revenue requirement recovery mechanisms. These mechanisms recover costs associated with providing energy, retail transmission of energy, administrative costs to procure energy, bad debt costs associated with providing energy, company investments in renewable energy, such as solar, and credits given to customers who generate renewable energy. There is also a mechanism for the recovery of stranded generation costs. Additionally, the DPU has provided cost and revenue requirement recovery mechanisms for certain operating expenses. These individual mechanisms include recovery of pension and PBOP costs, certain state government regulatory review, energy efficiency programs, customer arrearage forgiveness programs and low income customer discounts.

In the January 31, 2011 rate case, WMECO received approval for a revenue decoupling reconciliation mechanism, which provides assurance that WMECO will recover a DPU pre-established level of baseline distribution delivery service revenue to manage all other distribution operating expenses and earn a level of return on its capital investment.

Storm Cost Deferrals: The storm cost deferrals relate to costs incurred at CL&P, PSNH and WMECO for restorations that met regulatory agency specified criteria for cost deferral.

On June 1, 2011, a series of severe thunderstorms with high winds, including tornadoes, struck portions of WMECO’s service territory. On June 9, 2011, another series of severe thunderstorms with high winds struck CL&P, PSNH and WMECO’s service territories. The cost of restoration that was deferred for future recovery from customers and recorded as a regulatory asset as of December 31, 2011 for CL&P and WMECO totaled $11 million and $3.3 million, respectively.

On August 28, 2011, Tropical Storm Irene caused extensive damage to NU’s distribution system. The estimated cost of restoration that was deferred for future recovery from customers and recorded as a regulatory asset as of December 31, 2011 for CL&P and WMECO totaled $105.6 million and $3.2 million, respectively. PSNH recorded $7 million in Other Long-Term Assets as previously described.

On October 29, 2011, an unprecedented storm inundated NU’s service territory with heavy snow causing significant damage to NU’s distribution and transmission systems. In terms of customer outages, this was the most severe storm in CL&P’s history, surpassing Tropical Storm Irene; the third most severe in PSNH’s history and the most severe in WMECO’s history. The estimated cost of restoration that was deferred for future recovery from customers and recorded as a regulatory asset as of December 31, 2011 for CL&P and WMECO totaled $157.7 million and $23.5 million, respectively. PSNH recorded $14.7 million in Other Long-Term Assets as previously described. The estimated cost of restoration is subject to change as additional cost information becomes available.

Management believes its response to the storm damage was prudent and therefore believes it is probable that CL&P, PSNH and WMECO will be allowed to recover these deferred storm costs. CL&P, PSNH and WMECO will seek recovery of these estimated deferred storm costs through the appropriate regulatory recovery process.

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The PSNH deferral as of December 31, 2011 relates to remaining costs incurred for a major storm in December 2008 and the February 2010 wind storm restorations, both of which were approved for recovery and are included in rate base. WMECO’s remaining storm deferral relates to 2008 and 2010 storm costs, which were approved for recovery and are earning a return.

Asset Retirement Obligations: The costs associated with the depreciation of the Regulated companies’ ARO assets and accretion of the ARO liabilities are recorded as regulatory assets in accordance with regulatory accounting guidance. For CL&P and WMECO, ARO assets, regulatory assets and liabilities offset and are excluded from rate base. PSNH’s ARO assets, regulatory assets and liabilities are included in rate base. These costs are being recovered over the life of the underlying property, plant and equipment.

Losses on Reacquired Debt: The regulatory asset relates to the losses associated with the reacquisition or redemption of long-term debt and are amortized over the life of the respective long-term debt issuance. These deferred losses are incorporated as part of debt costs included in the rate of return calculation.

Deferred Environmental Remediation Costs: This regulatory asset relates to environmental remediation costs at PSNH of $9.7 million and Yankee Gas of $28.8 million. Both PSNH and Yankee Gas have regulatory rate recovery mechanisms for environmental costs and accordingly, offsets to environmental reserves were recorded as regulatory assets. Management continues to believe these costs are probable of recovery in future cost-of-service regulated rates.

Deferred Operation and Maintenance Costs: This regulatory asset represents the deferral of maintenance expense in connection with the deferred recovery of revenue requirements for the period July 1, 2010 through December 31, 2010, as allowed by the PURA. CL&P is allowed to recover these costs from January 1, 2011 through June 30, 2012.

Regulatory Liabilities: The components of regulatory liabilities are as follows:

NU	As of December 31,
(Millions of Dollars)	2011		2010
Cost of Removal	$	172.2	$	194.8
Regulatory Liabilities Offsetting Derivative Assets		—		38.1
Regulatory Tracker Deferrals		139.1		95.1
AFUDC Transmission Incentive		67.0		62.1
Pension Liability — Yankee Gas Acquisition		10.0		12.5
Overrecovered Spent Nuclear Fuel Costs and Contractual Obligations		15.4		14.6
Wholesale Transmission Overcollections		9.6		13.7
Other Regulatory Liabilities		20.6		8.2
Total Regulatory Liabilities	$	433.9	$	439.1
Less: Current Portion	$	167.8	$	99.4
Total Long-Term Regulatory Liabilities	$	266.1	$	339.7

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	As of December 31,
	2011						2010
(Millions of Dollars)	CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
Cost of Removal	$	63.8	$	53.2	$	7.2	$	78.6	$	57.3	$	9.5
Regulatory Liabilities Offsetting
Derivative Assets		—		—		—		38.1		—		—
Regulatory Tracker Deferrals		94.4		17.3		21.3		79.4		6.6		4.8
AFUDC Transmission Incentive		57.7		—		9.3		56.5		—		5.6
Overrecovered Spent Nuclear Fuel Costs and
Contractual Obligations		15.4		—		—		14.6		—		—
Wholesale Transmission Overcollections		4.5		2.6		9.5		13.7		—		—
Other Regulatory Liabilities		11.8		5.8		2.4		1.2		3.1		3.1
Total Regulatory Liabilities	$	247.6	$	78.9	$	49.7	$	282.1	$	67.0	$	23.0
Less: Current Portion	$	108.3	$	24.5	$	33.1	$	75.7	$	8.4	$	8.0
Total Long-Term Regulatory Liabilities	$	139.3	$	54.4	$	16.6	$	206.4	$	58.6	$	15.0

Cost of Removal: NU’s Regulated companies currently recover amounts in rates for future costs of removal of plant assets over the lives of the assets. These amounts are classified as Regulatory Liabilities on the accompanying consolidated balance sheets.

Regulatory Liabilities Offsetting Derivative Assets: The regulatory liabilities offsetting derivative assets relate to the fair value of contracts used to purchase power and other related contracts that will benefit customers in the future. See Note 4, “Derivative Instruments,” to the consolidated financial statements for further information. This liability is excluded from rate base and is refunded as the actual settlement occurs over the duration of the contracts.

AFUDC Transmission Incentive: AFUDC was recorded on 100 percent of CL&P and WMECO’s CWIP for their NEEWS projects through May 31, 2011, all of which was reserved as a regulatory liability to reflect rate base recovery for 100 percent of the CWIP as a result of FERC-approved transmission incentives. Effective June 1, 2011, FERC approved changes to the ISO-NE Tariff in order to include 100 percent of the NEEWS CWIP in regional rate base. As a result, CL&P and WMECO no longer record AFUDC on NEEWS CWIP.

Overrecovered Spent Nuclear Fuel Costs and Contractual Obligations: CL&P and WMECO currently recover amounts in rates for costs of disposal of spent nuclear fuel and high-level radioactive waste for the period prior to the sale of their ownership shares in the Millstone nuclear power stations. Collections in excess of these costs are recorded as regulatory liabilities. CL&P has also established a regulatory liability for the overrecovery of its proportionate share of the remaining costs, including decommissioning, of the MYAPC nuclear facility.

Wholesale Transmission Overcollections: CL&P, PSNH and WMECO’s transmission rates recover total transmission revenue requirements, recovering all regional and local revenue requirements for providing transmission service. These rates provide for annual reconciliations to actual costs and the difference between billed and actual costs is deferred. Regulatory liabilities were recorded for collections in excess of costs.

Pension Liability — Yankee Gas Acquisition: When Yankee Gas was acquired by NU, the pension liability was adjusted to fair value with an offset to the adjustment recorded as a regulatory liability, as approved by the PURA. The pension liability was approved for amortization over an approximate 13-year period beginning in 2002.

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3. PROPERTY, PLANT AND EQUIPMENT AND ACCUMULATED DEPRECIATION

The following tables summarize the NU, CL&P, PSNH and WMECO investments in utility property, plant and equipment:

NU	As of December 31,
(Millions of Dollars)	2011			2010
Distribution — Electric	$	6,540.4		$	6,197.2
Distribution — Natural Gas		1,247.6			1,126.6
Transmission		3,541.9			3,378.0
Generation		1,096.0			697.1
Electric and Natural Gas Utility		12,425.9			11,398.9
Other (1)		305.1			305.5
Total Property, Plant and Equipment, Gross		12,731.0			11,704.4
Less: Accumulated Depreciation Electric and Natural Gas Utility		(3,035.5	)		(2,862.3	)
Other		(120.2	)		(119.9	)
Total Accumulated Depreciation		(3,155.7	)		(2,982.2	)
Property, Plant and Equipment, Net		9,575.3			8,722.2
Construction Work in Progress		827.8			845.5
Total Property, Plant and Equipment, Net	$	10,403.1		$	9,567.7

(1) These assets are primarily owned by RRR ($161.5 million and $166 million) and NUSCO ($131.5 million and $126.6 million) as of December 31, 2011 and 2010, respectively, and are mainly comprised of building improvements at RRR and software and equipment at NUSCO.

	As of December 31,
	2011									2010
(Millions of Dollars)	CL&P			PSNH			WMECO			CL&P			PSNH			WMECO
Distribution	$	4,419.6		$	1,451.6		$	704.3		$	4,180.7		$	1,375.4		$	673.7
Transmission		2,689.1			546.4			297.4			2,668.4			476.1			233.5
Generation		—			1,074.8			21.2			—			687.7			9.4
Total Property, Plant and Equipment, Gross		7,108.7			3,072.8			1,022.9			6,849.1			2,539.2			916.6
Less: Accumulated Depreciation		(1,596.7	)		(893.6	)		(240.5	)		(1,508.7	)		(837.3	)		(228.5	)
Property, Plant and Equipment, Net		5,512.0			2,179.2			782.4			5,340.4			1,701.9			688.1
Construction Work in Progress		315.4			77.5			295.4			246.1			351.4			129.0
Total Property, Plant and Equipment, Net	$	5,827.4		$	2,256.7		$	1,077.8		$	5,586.5		$	2,053.3		$	817.1

On May 31, 2011, CL&P completed the sale of a segment of high voltage transmission lines in the town of Wallingford, Connecticut. The assets were sold at their net book value of $42.5 million, plus reimbursement of closing costs. CL&P will operate and maintain the lines under an operations and maintenance agreement.

PSNH charges planned major maintenance activities to Operating Expenses unless the cost represents the acquisition of additional components.

CL&P, PSNH and WMECO have entered into certain equipment purchase contracts that require the Company to make advance payments during the design, manufacturing, shipment and installation of equipment. As of December 31, 2011 and 2010, advance payments totaling $15.2 million and $9.3 million, respectively ($1.3 million and $1.3 million for CL&P, zero and $4.9 million for PSNH and $13.9 million and $3.1 million for WMECO, respectively) are included in CWIP in the table above and are not subject to depreciation.

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The following table summarizes average depreciable lives as of December 31, 2011:

	Average Depreciable Life
(Years)	NU		CL&P		PSNH		WMECO
Distribution		38.8		42.1		33.9		29.6
Transmission		41.2		40.6		41.9		47.0
Generation		29.6		—		29.6		25.0
Other		17.7		—		—		—

The provision for depreciation on utility assets is calculated using the straight-line method based on the estimated remaining useful lives of depreciable plant in-service, adjusted for salvage value and removal costs, as approved by the appropriate regulatory agency (the PURA, NHPUC and the DPU for CL&P, PSNH and WMECO, respectively). Depreciation rates are applied to plant-in-service from the time it is placed in service. When a plant is retired from service, the original cost of the plant is charged to the accumulated provision for depreciation, which includes cost of removal less salvage. Cost of removal is classified as a Regulatory Liability on the accompanying consolidated balance sheets. The depreciation rates for the several classes of utility plant-in-service are equivalent to composite rates as follows:

(Percent)	2011		2010		2009
NU		2.6		2.7		2.9
CL&P		2.4		2.7		3.0
PSNH		2.9		2.8		2.7
WMECO		2.9		2.8		2.9

4. DERIVATIVE INSTRUMENTS

The costs and benefits of derivative contracts that meet the definition of and are designated as “normal purchases or normal sales” (normal) are recognized in Operating Expenses or Operating Revenues on the accompanying consolidated statements of income, as applicable, as electricity or natural gas is delivered.

Derivative contracts that are not recorded as normal under the applicable accounting guidance are recorded at fair value as current or long-term derivative assets or liabilities. For the Regulated companies, regulatory assets or liabilities are recorded for the changes in fair values of derivatives, as these contracts are part of current regulated operating costs, or have an allowed recovery mechanism, and management believes that these costs will continue to be recovered from or refunded to customers in cost-of-service, regulated rates. Changes in fair values of NU’s remaining unregulated wholesale marketing contracts are included in Net Income.

The Regulated companies are exposed to the volatility of the prices of energy and energy-related products in procuring energy supply for their customers. The costs associated with supplying energy to customers are recoverable through customer rates. The Company manages the risks associated with the price volatility of energy and energy-related products through the use of derivative contracts, many of which are accounted for as normal, and the use of nonderivative contracts.

CL&P and WMECO mitigate the risks associated with the price volatility of energy and energy-related products through the use of SS, LRS, and basic service contracts, which fix the price of electricity purchased for customers for periods of time ranging from three months to three years for CL&P and from three months to one year for WMECO and are accounted for as normal. CL&P has entered into derivatives, including FTR contracts, to manage the risk of congestion costs associated with its SS and LRS contracts. As required by regulation, CL&P has also entered into derivative and nonderivative contracts for the purchase of energy and energy-related products and contracts related to capacity and WMECO has entered into a contract to purchase renewable energy that is a derivative. While the risks managed by these contracts relate to regional congestion costs, capacity prices and the development of renewable energy, electric distribution companies, including CL&P and WMECO,

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are required to enter into these contracts. The costs or benefits from these contracts are recoverable from or refundable to customers, and, therefore changes in fair value are recorded as Regulatory Assets and Regulatory Liabilities on the accompanying consolidated balance sheets.

PSNH mitigates the risks associated with the volatility of energy prices in procuring energy supply for its customers through its generation facilities and the use of derivative contracts, including energy forward contracts and FTRs. PSNH enters into these contracts in order to stabilize electricity prices for customers by mitigating uncertainties associated with the New England spot market. The costs or benefits from these contracts are recoverable from or refundable to PSNH’s customers, and, therefore changes in fair value are recorded as Regulatory Assets and Regulatory Liabilities on the accompanying consolidated balance sheets.

NU, through Select Energy, has one remaining fixed price forward sales contract to serve electrical load that is part of its remaining unregulated wholesale energy marketing portfolio. NU mitigates the price risk associated with this contract through the use of forward purchase contracts. The contracts are accounted for at fair value, and changes in their fair values are recorded in Fuel, Purchased and Net Interchange Power on the accompanying consolidated statements of income.

NU is also exposed to interest rate risk associated with its long-term debt. From time to time, various subsidiaries of the Company enter into forward starting interest rate swaps, accounted for as cash flow hedges, to mitigate the risk of changes in interest rates when they expect to issue long-term debt. NU parent has also entered into an interest rate swap on fixed rate long-term debt in order to balance its fixed and floating rate debt. This interest rate swap is accounted for as a fair value hedge.

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The gross fair values of derivative assets and liabilities with the same counterparty are offset and reported as net Derivative Assets or Derivative Liabilities, with current and long-term portions, in the accompanying consolidated balance sheets. Cash collateral posted or collected under master netting agreements is recorded as an offset to the derivative asset or liability. The following tables present the gross fair values of contracts and the net amounts recorded as current or long-term derivative assets or liabilities, by primary underlying risk exposures or purpose:

	As of December 31, 2011
	Derivatives Not Designated as Hedges
(Millions of Dollars)	Commodity and  Capacity Contracts Required by Regulation			Commodity Supply and Price Risk Management			Hedging Instruments		Collateral and Netting (1)			Net Amount Recorded as Derivative Asset/(Liability) (2)
Current Derivative Assets:
Level 2:
Other	$	—		$	—		$	2.3	$	—		$	2.3
Level 3:
CL&P		17.5			0.4			—		(11.6	)		6.3
Other		—			4.7			—		—			4.7
Total Current Derivative Assets	$	17.5		$	5.1		$	2.3	$	(11.6	)	$	13.3
Long-Term Derivative Assets:
Level 3:
CL&P	$	174.2		$	—		$	—	$	(80.4	)	$	93.8
Other		—			4.6			—		—			4.6
Total Long-Term Derivative Assets	$	174.2		$	4.6		$	—	$	(80.4	)	$	98.4
Current Derivative Liabilities:
Level 3:
CL&P	$	(95.9	)	$	—		$	—	$	—		$	(95.9	)
WMECO		(0.1	)		—			—		—			(0.1	)
Other		—			(16.1	)		—		4.5			(11.6	)
Total Current Derivative Liabilities	$	(96.0	)	$	(16.1	)	$	—	$	4.5		$	(107.6	)
Long-Term Derivative Liabilities:
Level 3:
CL&P	$	(935.8	)	$	—		$	—	$	—		$	(935.8	)
WMECO		(7.2	)		—			—		—			(7.2	)
Other		—			(17.3	)		—		0.4			(16.9	)
Total Long-Term Derivative Liabilities	$	(943.0	)	$	(17.3	)	$	—	$	0.4		$	(959.9	)

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	As of December 31, 2010
	Derivatives Not Designated as Hedges
(Millions of Dollars)	Commodity and Capacity Contracts Required by Regulation			Commodity Supply and Price Risk Management			Hedging Instruments		Collateral and Netting (1)			Net Amount Recorded as Derivative Asset/(Liability) (2)
Current Derivative Assets:
Level 2:
Other	$	—		$	—		$	7.7	$	—		$	7.7
Level 3:
CL&P		5.8			2.1			—		—			7.9
Other		—			1.7			—		—			1.7
Total Current Derivative Assets	$	5.8		$	3.8		$	7.7	$	—		$	17.3
Long-Term Derivative Assets:
Level 2:
Other	$	—		$	—		$	4.1	$	—		$	4.1
Level 3:
CL&P		195.9			—			—		(80.0	)		115.9
Other		—			3.2			—		—			3.2
Total Long-Term Derivative Assets	$	195.9		$	3.2		$	4.1	$	(80.0	)	$	123.2
Current Derivative Liabilities:
Level 2:
PSNH	$	—		$	(12.8	)	$	—	$	—		$	(12.8	)
Level 3:
CL&P		(54.3	)		(0.2	)		—		7.7			(46.8	)
Other		—			(12.4	)		—		0.5			(11.9	)
Total Current Derivative Liabilities	$	(54.3	)	$	(25.4	)	$	—	$	8.2		$	(71.5	)
Long-Term Derivative Liabilities:
Level 3:
CL&P	$	(883.1	)	$	—		$	—	$	—		$	(883.1	)
Other		—			(26.8	)		—		0.2			(26.6	)
Total Long-Term Derivative Liabilities	$	(883.1	)	$	(26.8	)	$	—	$	0.2		$	(909.7	)

(1) Amounts represent cash collateral posted under master netting agreements and the netting of derivative assets and liabilities. See “Credit Risk” below for discussion of cash collateral posted under master netting agreements.

(2) Current derivative assets are included in Prepayments and Other Current Assets on the accompanying consolidated balance sheets. WMECO derivative liabilities are included in Other Current Liabilities and Other Long-Term Liabilities on the accompanying consolidated balance sheets.

The business activities of the Company that resulted in the recognition of derivative assets also create exposure to various counterparties. As of December 31, 2011, NU and CL&P’s derivative assets are exposed to counterparty credit risk. Of these amounts, $102.0 million and $99.7 million, respectively, is contracted with investment grade entities and the remainder is contracted with multiple other counterparties.

For further information on the fair value of derivative contracts, see Note 1I, “Summary of Significant Accounting Policies — Fair Value Measurements,” and Note 1J, “Summary of Significant Accounting Policies — Derivative Accounting,” to the consolidated financial statements.

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Derivatives not designated as hedges

Commodity and capacity contracts required by regulation: CL&P has capacity-related contracts with generation facilities. These contracts and similar UI contracts have an expected capacity of 787 MW. CL&P has a sharing agreement with UI, with 80 percent of each contract allocated to CL&P and 20 percent allocated to UI. The capacity contracts have terms up to 15 years and obligate the utilities to make or receive payments on a monthly basis to or from the generation facilities based on the difference between a set capacity price and the forward capacity market price received in the ISO-NE capacity markets. The largest of these generation facilities achieved commercial operation in July 2011. In addition, CL&P has a contract to purchase 0.1 million MWh of energy per year through 2020.

WMECO has a renewable energy contract to purchase 0.1 million MWh of energy per year through 2027 with a facility that is expected to achieve commercial operation by December 2012.

Commodity supply and price risk management: As of December 31, 2011 and 2010, CL&P had 0.6 million and 1.8 million MWh, respectively, remaining under FTRs that extend through December 2012 and require monthly payments or receipts.

PSNH has 0.3 million MWh remaining under FTRs as of December 31, 2011 and 2010 that extend through December 2012 and require monthly payments or receipts. PSNH had electricity procurement contracts with delivery dates through 2011 to purchase an aggregate amount of 0.4 million MWh of power as of December 31, 2010.

As of December 31, 2011 and 2010, NU had approximately 0.1 million and 0.3 million MWh, respectively, of supply volumes remaining in its unregulated wholesale portfolio when expected sales are compared with contracted supply, both of which extend through 2013.

The following table presents the realized and unrealized gains/(losses) associated with derivative contracts not designated as hedges:

		Amount of Gain/(Loss) Recognized on Derivative Instrument
	Location of Gain or Loss Recognized on Derivative	For the Years Ended December 31,
(Millions of Dollars)		2011			2010			2009
NU
Commodity and Capacity Contracts Required by Regulation	Regulatory Assets/Liabilities	$	(158.1	)	$	(74.0	)	$	(99.9	)
Commodity Supply and Price Risk Management	Regulatory Assets/Liabilities		(3.9	)		(21.7	)		(73.2	)
Commodity Supply and Price Risk Management	Fuel, Purchased and Net Interchange Power		0.5			2.7			6.2
CL&P
Commodity and Capacity Contracts Required by Regulation	Regulatory Assets/Liabilities		(150.8	)		(74.0	)		(99.9	)
Commodity Supply and Price Risk Management	Regulatory Assets/Liabilities		(2.8	)		(6.2	)		(7.8	)
PSNH
Commodity Supply and Price Risk Management	Regulatory Assets/Liabilities		(1.0	)		(15.0	)		(62.6	)
WMECO
Commodity and Capacity Contracts Required by Regulation	Regulatory Assets/Liabilities		(7.3	)		—			—

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For the Regulated companies, monthly settlement amounts are recorded as receivables or payables and as Operating Revenues or Fuel, Purchased and Net Interchange Power on the accompanying consolidated financial statements. Regulatory Assets/Liabilities are established with no impact to Net Income.

Hedging instruments

Fair Value Hedge: To manage the balance of its fixed and floating rate debt, NU parent has a fixed to floating interest rate swap on its $263 million, fixed rate senior notes maturing on April 1, 2012. This interest rate swap qualifies and was designated as a fair value hedge and requires semi-annual cash settlements. The changes in fair value of the swap and the interest component of the hedged long-term debt instrument are recorded in Interest Expense on the accompanying consolidated statements of income. There was no ineffectiveness recorded for the years ended December 31, 2011, 2010 and 2009. The cumulative changes in fair values of the swap and the Long-Term Debt are recorded as a Derivative Asset/Liability and an adjustment to Long-Term Debt — Current Portion. Interest Receivable is recorded as a reduction of Interest Expense and is included in Prepayments and Other Current Assets.

The realized and unrealized gains/(losses) related to changes in fair value of the swap and Long-Term Debt as well as pre-tax Interest Expense, are as follows:

	For the Years Ended December 31,
	2011					2010					2009
(Millions of Dollars)	Swap		Hedged Debt			Swap		Hedged Debt			Swap		Hedged Debt
Changes in Fair Value	$	1.0	$	(1.0	)	$	9.5	$	(9.5	)	$	1.6	$	(1.6	)
Interest Recorded in Net Income		—		10.5			—		10.9			—		9.1

Cash Flow Hedges: Cash flow hedges are recorded at fair value, and the changes in the fair value of the effective portion of those contracts are recognized in AOCI. When a cash flow hedge is settled, the settlement amount is recorded in AOCI and is amortized into Net Income over the term of the underlying debt instrument. Cash flow hedges also impact Net Income when hedge ineffectiveness is measured and recorded, when the forecasted transaction being hedged is improbable of occurring or when the transaction is settled. In 2011, PSNH and WMECO entered into cash flow hedges related to a portion of their respective planned debt issuances. PSNH entered into three forward starting swaps to fix the U.S. dollar LIBOR swap rate of 3.749 percent on $80 million of a planned $160 million long-term debt issuance, 2.804 percent on the remaining $80 million of the planned $160 million long-term debt issuance and 3.6 percent on $120 million of long-term debt to be issued to refinance outstanding PCRBs. In May 2011, PSNH settled the swap associated with the $120 million refinancing of PCRBs and a $2.9 million pre-tax reduction in AOCI is being amortized over the life of the debt. In September 2011, PSNH settled the two remaining swaps associated with the $160 million long-term debt issuance and a $15.3 million pre-tax reduction in AOCI is being amortized over the life of the debt. WMECO entered into a forward starting swap to fix the U.S. dollar LIBOR swap rate of 3.7624 percent associated with $50 million of a planned $100 million long-term debt issuance. In September 2011, WMECO settled the swap and a $6.9 million pre-tax reduction in AOCI is being amortized over the life of the debt.

The pre-tax impact of cash flow hedging instruments on AOCI is as follows:

	Gains/(Losses) Recognized on Derivative Instruments For the Year Ended December 31,			Gains/(Losses) Reclassified from AOCI into Interest Expense For the Years Ended December 31,
(Millions of Dollars)	2011			2011			2010			2009
NU	$	(25.1	)	$	(1.3	)	$	(0.4	)	$	(0.4	)
CL&P		—			(0.7	)		(0.7	)		(0.7	)
PSNH		(18.2	)		(0.8	)		(0.2	)		(0.2	)
WMECO		(6.9	)		(0.1	)		0.1			0.1

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For further information, see Note 16, “Accumulated Other Comprehensive Income/(Loss),” to the consolidated financial statements.

Credit Risk

Certain derivative contracts that are accounted for at fair value, including NU’s sourcing contracts related to the remaining wholesale marketing contract and PSNH’s electricity procurement contracts, contain credit risk contingent features. These features require these companies to maintain investment grade credit ratings from the major rating agencies and to post cash or standby LOCs as collateral for contracts in a net liability position over specified credit limits. NU parent provides standby LOCs under its revolving credit agreement for NU subsidiaries to post with counterparties. The following summarizes the fair value of derivative contracts that are in a liability position and subject to credit risk contingent features, the fair value of cash collateral and standby LOCs posted with counterparties and the additional collateral in the form of LOCs that would be required to be posted by NU or PSNH if the respective unsecured debt credit ratings of NU parent or PSNH were downgraded to below investment grade as of December 31, 2011 and 2010:

	As of December 31, 2011
(Millions of Dollars)	Fair Value Subject to Credit Risk Contingent Features			Cash Collateral Posted		Standby LOCs Posted		Additional Standby LOCs Required if Downgraded Below Investment Grade
NU	$	(23.5	)	$	4.1	$	—	$	19.9

	As of December 31, 2010
(Millions of Dollars)	Fair Value Subject to Credit Risk Contingent Features			Cash Collateral Posted		Standby LOCs Posted		Additional Standby LOCs Required if Downgraded Below Investment Grade
NU	$	(30.9	)	$	0.5	$	24.0	$	18.5
PSNH		(12.8	)		—		24.0		—

Fair Value Measurements of Derivative Instruments:

Valuation of Derivative Instruments: Derivative contracts classified as Level 2 in the fair value hierarchy include Commodity Supply and Price Risk Management contracts and Interest Rate Risk Management contracts. Commodity Supply and Price Risk Management contracts include PSNH forward contracts to purchase energy for periods for which prices are quoted in an active market. Prices are obtained from broker quotes and based on actual market activity. The contracts are valued using the mid-point of the bid-ask spread. Valuations of these contracts also incorporate discount rates using the yield curve approach. Interest Rate Risk Management contracts represent interest rate swap agreements and are valued using a market approach provided by the swap counterparty using a discounted cash flow approach utilizing forward interest rate curves.

The derivative contracts classified as Level 3 in the tables below include the Regulated companies’ Commodity and Capacity Contracts Required by Regulation, and Commodity Supply and Price Risk Management contracts (CL&P and PSNH FTRs and NU’s remaining wholesale marketing portfolio). For Commodity and Capacity Contracts Required by Regulation and NU’s remaining unregulated wholesale marketing portfolio, fair value is modeled using income techniques such as discounted cash flow approaches. Significant observable inputs for valuations of these contracts include energy and energy-related product prices for which quoted prices in an active market exist. Significant unobservable inputs used in the valuations of these contracts include energy and energy-related product prices for future years for long-dated Commodity and Capacity Contracts Required by Regulation and future contract quantities. Discounted cash flow valuations incorporate estimates of premiums or discounts that would be required by a market participant to arrive at an exit price, using available historical market transaction information. Valuations of derivative contracts include assumptions regarding the timing and likelihood of scheduled payments and also reflect nonperformance risk, including credit, using the default probability approach based on the counterparty’s credit rating for assets and the Company’s credit rating for liabilities.

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The remaining contracts included in Commodity Supply and Price Risk Management and classified as Level 3 in the tables below are valued using broker quotes based on prices in an inactive market.

Valuations using significant unobservable inputs: The following tables present changes for the years ended December 31, 2011 and 2010 in the Level 3 category of derivative assets and derivative liabilities measured at fair value on a recurring basis. The derivative assets and liabilities are presented on a net basis. The Company classifies assets and liabilities in Level 3 of the fair value hierarchy when there is reliance on at least one significant unobservable input to the valuation model. In addition to these unobservable inputs, the valuation models for Level 3 assets and liabilities typically also rely on a number of inputs that are observable either directly or indirectly. Thus the gains and losses presented below include changes in fair value that are attributable to both observable and unobservable inputs. There were no transfers into or out of Level 3 assets and liabilities for the years ended December 31, 2011 and 2010.

	NU
(Millions of Dollars)	Commodity and Capacity Contracts Required By Regulation			Commodity Supply and Price Risk Management			Total Level 3
Derivatives, Net:
Fair Value as of January 1, 2010	$	(720.3	)	$	(40.9	)	$	(761.2	)
Net Realized/Unrealized Gains/(Losses) Included in:
Net Income (1)		—			2.7			2.7
Regulatory Assets/Liabilities		(74.0	)		(7.2	)		(81.2	)
Settlements		(13.7	)		13.2			(0.5	)
Fair Value as of December 31, 2010	$	(808.0	)	$	(32.2	)	$	(840.2	)
Net Realized/Unrealized Gains/(Losses) Included in:
Net Income (1)		—			0.5			0.5
Regulatory Assets/Liabilities		(158.1	)		(2.9	)		(161.0	)
Settlements		26.8			11.7			38.5
Fair Value as of December 31, 2011	$	(939.3	)	$	(22.9	)	$	(962.2	)
Gains Included in Net Income Relating to
Items Held as of End of Year:
2011		—			0.7			0.7
2010		—			1.2			1.2

	CL&P									WMECO
(Millions of Dollars)	Commodity and Capacity Contracts Required By Regulation			Commodity Supply and Price Risk Management			Total Level 3			Commodity and Capacity Contracts Required By Regulation
Derivatives, Net:
Fair Value as of January 1, 2010	$	(720.3	)	$	4.5		$	(715.8	)	$	—
Net Realized/Unrealized Losses Included in:
Regulatory Assets/Liabilities		(74.0	)		(6.2	)		(80.2	)		—
Settlements		(13.7	)		3.6			(10.1	)		—
Fair Value as of December 31, 2010	$	(808.0	)	$	1.9		$	(806.1	)	$	—
Net Realized/Unrealized Losses Included in:
Regulatory Assets/Liabilities		(150.8	)		(2.8	)		(153.6	)		(7.3	)
Settlements		26.8			1.3			28.1			—
Fair Value as of December 31, 2011	$	(932.0	)	$	0.4		$	(931.6	)	$	(7.3	)

B-78

(1) Gains and losses on derivatives included in Net Income relate to NU’s remaining wholesale marketing contracts and are reported in Fuel, Purchased and Net Interchange Power on the accompanying consolidated statements of income.

5. MARKETABLE SECURITIES (NU, WMECO)

NU maintains a supplemental benefit trust to fund NU’s SERP and non-SERP obligations and WMECO maintains a spent nuclear fuel trust to fund WMECO’s prior period spent nuclear fuel liability, both of which hold marketable securities. These trusts are not subject to regulatory oversight by state or federal agencies.

The Company elects to record mutual funds purchased by the NU supplemental benefit trust at fair value. As such, any change in fair value of these purchased equity securities is reflected in Net Income. These equity securities, classified as Level 1 in the fair value hierarchy, totaled $41.1 million and $42.2 million as of December 31, 2011 and 2010, respectively, and are included in current Marketable Securities. Losses on these securities of $1.1 million and gains of $6.9 million for the years ended December 31, 2011 and 2010, respectively, were recorded in Other Income, Net on the accompanying consolidated statements of income. Dividend income is recorded when dividends are declared and are recorded in Other Income, Net on the accompanying consolidated statements of income. All other marketable securities are accounted for as available-for-sale.

Available-for-Sale Securities: The following is a summary of NU’s available-for-sale securities held in the NU supplemental benefit trust and WMECO’s spent nuclear fuel trust. These securities are recorded at fair value and included in current and long-term Marketable Securities on the accompanying consolidated balance sheets.

	As of December 31, 2011
(Millions of Dollars)	Amortized Cost		Pre-Tax Unrealized Gains (1)		Pre-Tax Unrealized Losses (1)			Fair Value
NU	$	88.4	$	2.0	$	(0.2	)	$	90.2
WMECO		57.3		—		(0.2	)		57.1

	As of December 31, 2010
(Millions of Dollars)	Amortized Cost		Pre-Tax Unrealized Gains (1)		Pre-Tax Unrealized Losses (1)			Fair Value
NU	$	86.3	$	1.3	$	(0.3	)	$	87.3
WMECO		57.2		—		(0.1	)		57.1

(1) Unrealized gains and losses on debt securities for the NU supplemental benefit trust and WMECO spent nuclear fuel trust are recorded in AOCI and Other Long-Term Assets, respectively, on the accompanying consolidated balance sheets.

Unrealized Losses and Other-than-Temporary Impairment: There have been no significant unrealized losses, other-than-temporary impairments or credit losses for the NU supplemental benefit trust or WMECO spent nuclear fuel trust. Factors considered in determining whether a credit loss exists include the duration and severity of the impairment, adverse conditions specifically affecting the issuer, and the payment history, ratings and rating changes of the security. For asset-backed debt securities, underlying collateral and expected future cash flows are also evaluated.

Realized Gains and Losses: Realized gains and losses on available-for-sale-securities, including any credit loss and any gains or losses on securities the company intends to sell or will be required to sell, are recorded in Other Income, Net for the NU supplemental benefit trust and in Other Long-Term Assets for the WMECO spent nuclear fuel trust. NU utilizes the specific identification basis method for the NU supplemental benefit trust securities and the average cost basis method for the WMECO spent nuclear fuel trust to compute the realized gains and losses on the sale of available-for-sale securities.

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Contractual Maturities: As of December 31, 2011, the contractual maturities of available-for-sale debt securities are as follows:

	NU				WMECO
(Millions of Dollars)	Amortized Cost		Fair Value		Amortized Cost		Fair Value
Less than one year	$	29.9	$	29.9	$	26.4	$	26.3
One to five years		25.4		25.6		20.7		20.7
Six to ten years		10.9		11.3		6.1		6.1
Greater than ten years		22.2		23.4		4.1		4.0
Total Debt Securities	$	88.4	$	90.2	$	57.3	$	57.1

Fair Value Measurements: The following table presents the marketable securities recorded at fair value on a recurring basis by the level in which they are classified within the fair value hierarchy:

	NU				WMECO
	As of December 31,				As of December 31,
(Millions of Dollars)	2011		2010		2011		2010
Level 1:
Mutual Funds	$	41.1	$	42.2	$	—	$	—
Money Market Funds		1.8		1.8		0.1		0.3
Total Level 1	$	42.9	$	44.0	$	0.1	$	0.3
Level 2:
U.S. Government Issued Debt Securities (Agency and Treasury)		11.1		17.8		8.0		6.0
Corporate Debt Securities		16.5		22.5		9.1		15.6
Asset-Backed Debt Securities		25.9		11.6		7.9		4.7
Municipal Bonds		16.1		16.1		15.4		15.4
Other Fixed Income Securities		18.8		17.5		16.6		15.1
Total Level 2	$	88.4	$	85.5	$	57.0	$	56.8
Total Marketable Securities	$	131.3	$	129.5	$	57.1	$	57.1

U.S. government issued debt securities are valued using market approaches that incorporate transactions for the same or similar bonds and adjustments for yields and maturity dates. Corporate debt securities are valued using a market approach, utilizing recent trades of the same or similar instrument and also incorporating yield curves, credit spreads and specific bond terms and conditions. Asset-backed debt securities include collateralized mortgage obligations, commercial mortgage backed securities, and securities collateralized by auto loans, credit card loans or receivables. Asset-backed debt securities are valued using recent trades of similar instruments, prepayment assumptions, yield curves, issuance and maturity dates and tranche information. Municipal bonds are valued using a market approach that incorporates reported trades and benchmark yields. Other fixed income securities are valued using pricing models, quoted prices of securities with similar characteristics, and discounted cash flows.

6. ASSET RETIREMENT OBLIGATIONS

In accordance with accounting guidance for conditional AROs, NU, including CL&P, PSNH and WMECO, recognizes a liability for the fair value of an ARO on the obligation date if the liability’s fair value can be reasonably estimated and is conditional on a future event. Settlement dates and future costs are reasonably estimated when sufficient information becomes available. Management has identified various categories of AROs, primarily certain assets containing asbestos and hazardous contamination and has performed fair value calculations, reflecting expected probabilities for settlement scenarios.

B-80

The fair value of an ARO is recorded as a liability in Other Long-Term Liabilities with an offset included in Property, Plant and Equipment, Net on the accompanying consolidated balance sheets. As the Regulated companies are rate-regulated on a cost-of-service basis, these companies apply regulatory accounting guidance and the costs associated with the Regulated companies’ AROs are included in Other Regulatory Assets as of December 31, 2011 and 2010. The ARO assets are depreciated, and the ARO liabilities are accreted over the estimated life of the obligation with corresponding credits recorded as accumulated depreciation and ARO liabilities, respectively. Both the depreciation and accretion were recorded as increases to Regulatory Assets on the accompanying consolidated balance sheets as of December 31, 2011 and 2010. For further information, see Note 2, “Regulatory Accounting,” to the consolidated financial statements.

A reconciliation of the beginning and ending carrying amounts of Regulated companies’ ARO liabilities are as follows:

NU	As of December 31,
(Millions of Dollars)	2011			2010
Balance as of Beginning of Year	$	53.3		$	50.6
Liabilities Incurred During the Year		2.1			0.2
Liabilities Settled During the Year		(0.8	)		(1.2	)
Accretion		3.5			3.3
Revisions in Estimated Cash Flows		(1.9	)		0.4
Balance as of End of Year	$	56.2		$	53.3

	As of December 31,
	2011								2010
(Millions of Dollars)	CL&P			PSNH			WMECO		CL&P			PSNH		WMECO
Balance as of Beginning of Year	$	29.3		$	17.6		$	3.6	$	28.6		$	16.4	$	3.3
Liabilities Incurred During the Year		1.7			0.2			0.2		0.1			—		0.1
Liabilities Settled During the Year		(0.8	)		—			—		(1.2	)		—		—
Accretion		2.0			1.1			0.2		1.8			1.1		0.2
Revisions in Estimated Cash Flows		—			(1.9	)		—		—			0.1		—
Balance as of End of Year	$	32.2		$	17.0		$	4.0	$	29.3		$	17.6	$	3.6

7. GOODWILL (NU)

Goodwill and intangible assets deemed to have indefinite useful lives are reviewed for impairment at least annually by applying a fair value-based test. NU uses October 1^st as the annual goodwill impairment testing date. However, if an event occurs or circumstances change that would indicate that goodwill might be impaired, NU management would test the goodwill between the annual testing dates. Goodwill impairment is deemed to exist if the net book value of a reporting unit exceeds its estimated fair value and if the implied fair value of goodwill based on the estimated fair value of the reporting unit is less than the carrying amount.

NU’s reporting units are consistent with the operating segments underlying the reportable segments identified in Note 21, “Segment Information,” to the consolidated financial statements. The only reporting unit that maintains goodwill is the Yankee Gas reporting unit, which is classified under the Regulated companies — natural gas reportable segment and related to the acquisition of Yankee Energy System, Inc., parent of Yankee Gas. Such goodwill is not being recovered from the customers of Yankee Gas. The goodwill balance held by the Yankee Gas reporting unit as of December 31, 2011 and 2010 is $287.6 million.

NU completed its impairment analysis of the Yankee Gas goodwill balance as of October 1, 2011 and determined that no impairment exists. In completing this analysis, the fair value of the reporting unit was estimated using a discounted cash flow methodology and analyses of comparable companies and transactions.

B-81

8. SHORT-TERM DEBT

Limits: The amount of short-term borrowings that may be incurred by CL&P and WMECO is subject to periodic approval by the FERC. As a result of the NHPUC having jurisdiction over PSNH’s short-term debt, PSNH is not currently required to obtain FERC approval for its short-term borrowings. On November 30, 2011, the FERC granted authorization to allow CL&P and WMECO to incur total short-term borrowings up to a maximum of $450 million and $300 million, respectively, effective January 1, 2012 through December 31, 2013.

PSNH is authorized by regulation of the NHPUC to incur short-term borrowings up to 10 percent of net fixed plant. In an order dated December 17, 2010, the NHPUC increased the amount of short-term borrowings authorized for PSNH to a maximum of 10 percent of net fixed plant plus an additional $60 million until further ordered by the NHPUC. As of December 31, 2011, PSNH’s short-term debt authorization under the 10 percent of net fixed plant test plus $60 million totaled approximately $270 million.

CL&P’s certificate of incorporation contains preferred stock provisions restricting the amount of unsecured debt that CL&P may incur, including limiting unsecured indebtedness with a maturity of less than 10 years to 10 percent of total capitalization. In November 2003, CL&P obtained from its preferred stockholders a waiver of such 10 percent limit for a ten-year period expiring in March 2014, provided that all unsecured indebtedness does not exceed 20 percent of total capitalization. As of December 31, 2011, CL&P had $826.3 million of unsecured debt capacity available under this authorization.

Yankee Gas is not required to obtain approval from any state or federal authority to incur short-term debt.

CL&P, PSNH, WMECO and Yankee Gas Credit Agreement: On September 24, 2010, CL&P, PSNH, WMECO and Yankee Gas jointly entered into a three-year unsecured revolving credit facility in the amount of $400 million, which terminates on September 24, 2013. CL&P and PSNH may borrow up to $300 million each under this facility, with WMECO and Yankee Gas able to borrow up to $200 million each, subject to the $400 million maximum aggregate borrowing limit. This total commitment may be increased to $500 million at the request of the borrowers, subject to lender approval. Under this facility, each company can borrow either on a short-term or a long-term basis subject to regulatory approval. As of December 31, 2011, CL&P and Yankee Gas had $31 million and $30 million, respectively, in short-term borrowings outstanding under this credit facility. The weighted average interest rate on such borrowings outstanding under this credit facility as of December 31, 2011 was 4.03 percent and 2.07 percent, respectively. There were no borrowings outstanding by PSNH and WMECO under this facility as of December 31, 2011. As of December 31, 2010, PSNH had $30 million in short-term borrowings outstanding under this credit facility. The weighted average interest rate on such borrowings outstanding under this credit facility as of December 31, 2010 was 2.05 percent. There were no borrowings outstanding by CL&P, WMECO and Yankee Gas under this facility as of December 31, 2010.

NU Parent Credit Agreement: On September 24, 2010, NU parent entered into a three-year unsecured revolving credit facility in the amount of $500 million, which terminates on September 24, 2013. Subject to the amount of advances outstanding, LOCs can be issued under this facility for periods up to 364 days on the account of NU parent or any of its subsidiaries up to the total amount of the facility. This total commitment may be increased to $600 million at the request of NU parent, subject to lender approval. Under this facility, NU parent can borrow either on a short-term or a long-term basis. As of December 31, 2011 and 2010, NU parent had $256 million and $237 million, respectively, in short-term borrowings outstanding under this facility. The weighted-average interest rate on such borrowings outstanding under this credit facility as of December 31, 2011 and 2010 was 2.20 percent and 2.85 percent, respectively. There were $17.9 million, $4 million and $5.4 million in LOCs outstanding as of December 31, 2011 for NU, CL&P and PSNH, respectively. There were $32.1 million and $30.1 million in LOCs outstanding as of December 31, 2010 for NU and PSNH, respectively.

Under these credit facilities, NU parent and CL&P, PSNH, WMECO and Yankee Gas may borrow at prime rates or LIBOR-based rates, plus an applicable margin based upon the higher of S&P’s or Moody’s credit ratings assigned to the borrower.

B-82

In addition, NU parent, CL&P, PSNH, WMECO and Yankee Gas must comply with certain financial and non-financial covenants, including a consolidated debt to total capitalization ratio. NU parent, CL&P, PSNH, WMECO and Yankee Gas were in compliance with these covenants as of December 31, 2011. If NU parent or CL&P, PSNH, WMECO or Yankee Gas were not in compliance with these covenants, an event of default would occur requiring all outstanding borrowings by such borrower to be repaid and additional borrowings by such borrower would not be permitted under the respective credit facility.

Amounts outstanding under these credit facilities are classified as current liabilities as Notes Payable to Banks on the accompanying consolidated balance sheets, as management anticipates that all borrowings under these credit facilities will be outstanding for no more than 364 days at one time.

Money Pool: NU parent, CL&P, PSNH, WMECO, Yankee Gas and certain of NU’s other subsidiaries are members of the Money Pool. The Money Pool provides an efficient use of cash resources of NU and reduces outside short-term borrowings. NUSCO participates in the Money Pool and administers the Money Pool as agent for the member companies. Short-term borrowing needs of the member companies are met with available funds of other member companies, including funds borrowed by NU parent. NU parent may lend to the Money Pool but may not borrow. Funds may be withdrawn from or repaid to the Money Pool at any time without prior notice. Investing and borrowing subsidiaries receive or pay interest based on the average daily federal funds rate. Borrowings based on external loans of NU, however, accrue interest at NU’s cost and are payable on demand. In NU’s consolidated financial statements, Money Pool amounts payable to or receivable from members eliminate in consolidation. By order, the FERC has exempted all holding company system money pools from active regulation. As of December 31, 2011 and 2010, CL&P, PSNH and WMECO had the following borrowings from/(lendings to) the Money Pool with the respective weighted-average interest rate on borrowings from the Money Pool:

	As of and for the Years Ended December 31,
	2011									2010
(Millions of Dollars, except percentages)	CL&P			PSNH			WMECO			CL&P			PSNH			WMECO
Borrowings from/(Lendings to)	$	58.5		$	(55.9	)	$	(11.0	)	$	6.2		$	47.9		$	20.4
Weighted-Average Interest Rates		0.08	%		0.1	%		0.1	%		0.19	%		0.18	%		0.14	%

The net borrowings from/(lendings to) the Money Pool are recorded in Notes Payable to/Notes Receivable from Affiliated Companies on the accompanying consolidated balance sheets, respectively.

B-83

9. LONG-TERM DEBT

Details of long-term debt outstanding for NU, including CL&P, PSNH and WMECO are as follows:

CL&P	As of December 31,
(Millions of Dollars)	2011			2010
First Mortgage Bonds:
7.875% 1994 Series D due 2024	$	139.8		$	139.8
4.800% 2004 Series A due 2014		150.0			150.0
5.750% 2004 Series B due 2034		130.0			130.0
5.000% 2005 Series A due 2015		100.0			100.0
5.625% 2005 Series B due 2035		100.0			100.0
6.350% 2006 Series A due 2036		250.0			250.0
5.375% 2007 Series A due 2017		150.0			150.0
5.750% 2007 Series B due 2037		150.0			150.0
5.750% 2007 Series C due 2017		100.0			100.0
6.375% 2007 Series D due 2037		100.0			100.0
5.650% 2008 Series A due 2018		300.0			300.0
5.500% 2009 Series A due 2019		250.0			250.0
Total First Mortgage Bonds		1,919.8			1,919.8
Pollution Control Notes:
5.85%-5.90% Tax Exempt Fixed Rate due 2016-2022		46.4			46.4
5.85% Fixed Rate Tax Exempt due 2028 (1)		—			245.5
5.95% Fixed Rate Tax Exempt due 2028		70.0			70.0
4.375% Fixed Rate Tax Exempt due 2028 (1)		120.5			—
1.25% Fixed Rate Tax Exempt due 2028 (1)		125.0			—
One-Year Fixed Rate Tax Exempt due 2031 (2)		62.0			62.0
Total Pollution Control Notes		423.9			423.9
Total First Mortgage Bonds and Pollution Control Notes		2,343.7			2,343.7
Fees and Interest due for Spent Nuclear Fuel Disposal Costs		244.1			243.8
Less Amounts due Within One Year (2)		(62.0	)		(62.0	)
Unamortized Premiums and Discounts, Net		(4.0	)		(4.4	)
CL&P Long-Term Debt	$	2,521.8		$	2,521.1

B-84

PSNH	As of December 31,
(Millions of Dollars)	2011			2010
First Mortgage Bonds:
5.25% 2004 Series L due 2014	$	50.0		$	50.0
5.60% 2005 Series M due 2035		50.0			50.0
6.15% 2007 Series N due 2017		70.0			70.0
6.00% 2008 Series O due 2018		110.0			110.0
4.50% 2009 Series P due 2019		150.0			150.0
4.05% 2011 Series Q due 2021 (3)		122.0			—
3.20% 2011 Series R due 2021		160.0			—
Total First Mortgage Bonds		712.0			430.0
Pollution Control Revenue Bonds:
4.75%- 5.45% Tax Exempt Series B and C due 202		198.2			198.2
6.00% Tax Exempt Series D and E due 2021(3)		—			119.8
Adjustable Rate Series A due 2021		89.3			89.3
Total Pollution Control Revenue Bonds		287.5			407.3
Unamortized Premiums and Discounts, Net		(1.8	)		(0.9	)
PSNH Long-Term Debt	$	997.7		$	836.4

WMECO	As of December 31,
(Millions of Dollars)	2011			2010
Pollution Control and Other Notes:
Tax Exempt 1993 Series A, 5.85% due 2028	$	53.8		$	53.8
Senior Notes Series A, 5.00% due 2013		55.0			55.0
Senior Notes Series B, 5.90% due 2034		50.0			50.0
Senior Notes Series C, 5.24% due 2015		50.0			50.0
Senior Notes Series D, 6.70% due 2037		40.0			40.0
Senior Notes Series E, 5.10% due 2020		95.0			95.0
Senior Notes Series F, 3.50% due 2021		100.0			—
Total Pollution Control Notes and Other Notes		443.8			343.8
Fees and Interest due for Spent Nuclear Fuel Disposal Costs		57.3			57.2
Unamortized Premiums and Discounts, Net		(1.6	)		(0.7	)
WMECO Long-Term Debt	$	499.5		$	400.3

B-85

OTHER	As of December 31,
(Millions of Dollars)	2011			2010
Yankee Gas — First Mortgage Bonds:
8.48% Series B due 2022	$	20.0		$	20.0
7.19% Series E due 2012		4.3			8.6
4.80% Series G due 2014		75.0			75.0
5.26% Series H due 2019		50.0			50.0
5.35% Series I due 2035		50.0			50.0
6.90% Series J due 2018		100.0			100.0
4.87% Series K due 2020		50.0			50.0
Total First Mortgage Bonds		349.3			353.6
Less Amounts due Within One Year		(4.3	)		(4.3	)
Unamortized Premiums and Discounts, Net		0.9			1.0
Total First Mortgage Bonds		345.9			350.3
NU Parent — Notes:
7.25% Senior Notes Series A due 2012		263.0			263.0
5.65% Senior Notes Series C due 2013		250.0			250.0
Total NU Parent — Notes		513.0			513.0
Less Amounts due Within One Year		(265.3	)		—
Fair Value Adjustment		2.3			11.8
Other Long-Term Debt		595.9			875.1
Total NU Long-Term Debt	$	4,614.9		$	4,632.9

(1) On October 24, 2011, CL&P issued $120.5 million of tax-exempt PCRBs carrying a coupon of 4.375 percent that mature on September 1, 2028 and issued $125 million of tax-exempt PCRBs carrying a coupon of 1.25 percent that mature on September 1, 2028 and are subject to mandatory tender for purchase on September 3, 2013. The $125 million of tax-exempt PCRBs were issued with an initial fixed rate term period ending on September 2, 2013, at which time CL&P expects to remarket the PCRBs. The proceeds from these two CL&P issuances were used to refund $245.5 million of PCRBs that carried a coupon of 5.85 percent and had a maturity date of September 1, 2028.

(2) On April 1, 2011, CL&P remarketed the $62 million of tax-exempt PCRBs for a one-year period. The PCRBs, which mature on May 1, 2031, carry a coupon rate of 1.25 percent during the current one-year fixed-rate period and are subject to mandatory tender for purchase on April 1, 2012, at which time CL&P expects to remarket the bonds.

(3) On May 26, 2011, PSNH issued $122 million of first mortgage bonds with a coupon rate of 4.05 percent and a maturity date of June 1, 2021, and used the proceeds to redeem $119.8 million of its tax-exempt 1992 Series D and 1993 Series E PCRBs, each with a maturity date of May 1, 2021 and a coupon rate of 6 percent.

Long-term debt maturities and cash sinking fund requirements on debt outstanding as of December 31, 2011 for the years 2012 through 2016 and thereafter, are shown below. These amounts exclude fees and interest due for spent nuclear fuel disposal costs, net unamortized premiums and discounts and other fair value adjustments as of December 31, 2011:

(Millions of Dollars)	NU		CL&P		PSNH		WMECO
2012	$	329.3	$	62.0	$	—	$	—
2013		430.0		125.0		—		55.0
2014		275.0		150.0		50.0		—
2015		150.0		100.0		—		50.0
2016		15.4		15.4		—		—
Thereafter		3,449.6		1,891.3		949.5		338.8
Total	$	4,649.3	$	2,343.7	$	999.5	$	443.8

B-86

The utility plant of CL&P, PSNH and Yankee Gas is subject to the lien of each company’s respective first mortgage bond indenture.

The CL&P, PSNH and WMECO tax-exempt bonds contain call provisions providing call prices ranging between 100 percent and 102 percent of par. All other long-term debt securities are subject to make-whole provisions.

As of December 31, 2011, CL&P had $423.9 million of tax-exempt PCRBs outstanding, $70 million of which is secured by second mortgage liens on transmission assets, junior to the liens of its first mortgage bond indenture. CL&P has $307.5 million of tax-exempt PCRBs secured by first mortgage bonds. If CL&P failed to meet its obligations under the PCRBs, then these first mortgage bonds would become outstanding.

As of December 31, 2011, PSNH had $287.5 million in PCRBs outstanding. PSNH’s obligation to repay each series of PCRBs is secured by first mortgage bonds and bond insurance. Each such series of first mortgage bonds contains similar terms and provisions as the applicable series of PCRBs. If PSNH failed to meet its obligations under the PCRBs, then these first mortgage bonds would become outstanding. The 2001 Series A PCRBs, in the aggregate principal amount of $89.3 million, bears interest at a rate that is periodically set pursuant to auctions. The Company is not obligated to purchase these PCRBs, which mature in 2021, from the remarketing agent. The weighted average effective interest rate on PSNH’s Series A variable-rate PCRBs was 0.21 percent in 2011 and 0.34 percent in 2010.

NU’s, including CL&P, PSNH and WMECO, long-term debt agreements provide that NU and certain of its subsidiaries must comply with certain financial and non-financial covenants as are customarily included in such agreements, including a consolidated debt to total capitalization ratio. NU and these subsidiaries were in compliance with these covenants as of December 31, 2011.

Yankee Gas has certain long-term debt agreements that contain cross-default provisions applicable to all of Yankee Gas’ outstanding first mortgage bond series. The cross-default provisions on Yankee Gas’ Series B Bonds would be triggered if Yankee Gas were to default on a payment due on indebtedness in excess of $2 million. The cross-default provisions on all other series of Yankee Gas’ first mortgage bonds would be triggered if Yankee Gas were to default in a payment due on indebtedness in excess of $10 million. No debt issuances of CL&P, PSNH, WMECO or NU parent contain cross-default provisions as of December 31, 2011.

The fair value adjustment relates to the NU parent 7.25 percent note, due 2012 in the amount of $263 million, that is hedged with a fixed to floating interest rate swap. The change in fair value of the interest component of the debt was recorded as an adjustment to Long-Term Debt (Long-Term Debt — Current Portion as of December 31, 2011 since the note was due within one year) with an equal and offsetting adjustment to Derivative Assets for the change in fair value of the fixed to floating interest rate swap.

Spent Nuclear Fuel Obligation: Under the Nuclear Waste Policy Act of 1982, CL&P and WMECO must pay the DOE for the costs of disposal of spent nuclear fuel and high-level radioactive waste for the period prior to the sale of their ownership shares in the Millstone nuclear power stations.

The DOE is responsible for the selection and development of repositories for, and the disposal of, spent nuclear fuel and high-level radioactive waste. For nuclear fuel used to generate electricity prior to April 7, 1983 (Prior Period Spent Nuclear Fuel) for CL&P and WMECO, an accrual has been recorded for the full liability, and payment must be made by CL&P and WMECO to the DOE prior to the first delivery of spent fuel to the DOE. After the sale of Millstone, CL&P and WMECO remained responsible for their share of the disposal costs associated with the Prior Period Spent Nuclear Fuel. Until such payment to the DOE is made, the outstanding liability will continue to accrue interest at the 3-month Treasury bill yield rate. Fees due to the DOE for the disposal of Prior Period Spent Nuclear Fuel as of December 31, 2011 and 2010 are included in Long-Term Debt, including accumulated interest costs of $219.3 million and $218.9 million ($177.6 million and $177.3 million for CL&P and $41.7 million and $41.6 million for WMECO), respectively.

B-87

WMECO maintains a trust that holds marketable securities to fund amounts due to the DOE for the disposal of WMECO’s Prior Period Spent Nuclear Fuel. For further information on this trust, see Note 5, “Marketable Securities,” to the consolidated financial statements.

10. EMPLOYEE BENEFITS

A. Pension Benefits and Postretirement Benefits Other Than Pensions

Pursuant to GAAP, NU is required to record the funded status of its Pension and PBOP Plans on the accompanying consolidated balance sheets, based on the difference between the projected benefit obligation for the Pension Plan and accumulated postretirement benefit obligation for the PBOP Plans and the fair value of plan assets measured in accordance with fair value measurement accounting guidance. Pursuant to GAAP, the funded status of pension and PBOP plans is recorded with an offset to Accumulated Other Comprehensive Income/(Loss). This amount is remeasured annually, or as circumstances dictate.

Charges for the Regulated companies are recorded as Regulatory Assets and included as deferred benefit costs as these benefits expense amounts have been and continue to be recoverable in cost-of-service, regulated rates. Regulatory accounting was also applied to the portions of the NUSCO costs that support the Regulated companies, as these amounts are also recoverable through rates charged to customers. Charges for the unregulated companies are recorded on an after-tax basis to Accumulated Other Comprehensive Income/(Loss). For further information see Note 2, “Regulatory Accounting,” and Note 16, “Accumulated Other Comprehensive Income/(Loss),” to the consolidated financial statements.

Pension Benefits: NUSCO sponsors a Pension Plan, which is subject to the provisions of ERISA, as amended by the PPA of 2006. The Pension Plan covers nonbargaining unit employees (and bargaining unit employees, as negotiated) of NU, including CL&P, PSNH, and WMECO, hired before 2006 (or as negotiated, for bargaining unit employees). Benefits are based on years of service and the employees’ highest eligible compensation during 60 consecutive months of employment. NU allocates net periodic pension expense to its subsidiaries based on the actual participant demographic data for each subsidiary’s participants. Benefit payments to participants and contributions are also tracked by the trustee for each subsidiary. The actual investment return for the trust each year is allocated to each of the subsidiaries in proportion to the investment return expected to be earned during the year. NU uses a December 31^st measurement date for the Pension Plan.

In addition, NU has maintained a SERP since 1987. The SERP provides its eligible participants, who are officers of NU, with benefits that would have been provided to them under the Pension Plan if certain Internal Revenue Code limitations were not imposed. NU allocates net periodic SERP benefit costs to its subsidiaries based upon actuarial calculations by participant.

Although the Company maintains a trust to support the SERP with marketable securities held in the NU supplemental benefit trust, the plan itself does not contain any assets. For information regarding the investments in the NU supplemental benefit trust that are used to support the SERP liability, see Note 5, “Marketable Securities,” to the consolidated financial statements.

PBOP Plan: On behalf of NU’s retirees, NUSCO also sponsors plans that provide certain retiree health care benefits, primarily medical and dental, and life insurance benefits through PBOP Plans. These benefits are available for employees retiring from NU who have met specified service requirements. For current employees and certain retirees, the total benefit is limited to two times the 1993 per retiree health care cost. These costs are charged to expense over the estimated work life of the employee. NU uses December 31 as the measurement date for the PBOP Plan.

NU annually funds postretirement costs through external trusts with amounts that have been and will continue to be recovered in rates and that are tax deductible.

B-88

NU allocates net periodic postretirement benefits expense to its subsidiaries based on the actual participant demographic data for each subsidiary’s participants. Benefit payments to participants and contributions are also tracked for each subsidiary. The actual investment return for the trust each year is allocated to each of the subsidiaries in proportion to the investment return expected to be earned during the year.

Actuarial Determination of Expense: Pension and PBOP expense consists of the service cost and prior service cost determined by actuaries, the interest cost based on the discounting of the obligations and the amortization of the net transition obligation, offset by the expected return on plan assets. Pension and PBOP expense also includes amortization of actuarial gains and losses, which represent differences between expected and actual plan experience.

The expected return on plan assets is calculated by applying the assumed rate of return to a four-year rolling average of plan asset fair values, which reduces year-to-year volatility. This calculation recognizes investment gains or losses over a four-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the calculated expected return and the actual return based on the change in the fair value of assets during the year. As investment gains and losses are reflected in the average plan asset fair values, they are subject to amortization with other unrecognized gains/losses. Unrecognized gains/losses are amortized as a component of pension and PBOP expense over the estimated average future service period of the employees of approximately 10 and 9 years, respectively.

B-89

The following tables represent information on NU’s plan benefit obligations, fair values of plan assets, and funded status. Amounts related to the SERP obligation and expense are included with the Pension Plan in the tables below:

	Pension and SERP Benefits
	As of December 31, 2011												As of December 31, 2010
(Millions of Dollars)	NU			CL&P			PSNH			WMECO			NU			CL&P			PSNH			WMECO
Change in Benefit Obligation
Benefit Obligation as of Beginning of Year	$	(2,820.9	)	$	(964.3	)	$	(448.7	)	$	(196.6	)	$	(2,610.3	)	$	(899.2	)	$	(412.1	)	$	(184.3	)
Service Cost		(55.4	)		(19.5	)		(10.6	)		(3.9	)		(51.0	)		(17.6	)		(10.0	)		(3.5	)
Interest Cost		(153.3	)		(51.9	)		(24.4	)		(10.7	)		(152.6	)		(52.2	)		(24.1	)		(10.7	)
Actuarial Loss		(206.1	)		(64.0	)		(33.2	)		(15.4	)		(140.6	)		(49.7	)		(20.7	)		(8.4	)
Benefits Paid — Excluding Lump Sum Payments		134.4			55.6			18.9			10.8			130.2			54.1			18.1			10.3
Benefits Paid — SERP		2.4			0.3			0.1			—			2.5			0.3			0.1			—
Benefits Paid — Lump Sum Payments		—			—			—			—			0.9			—			—			—
Benefit Obligation as of End of Year	$	(3,098.9	)	$	(1,043.8	)	$	(497.9	)	$	(215.8	)	$	(2,820.9	)	$	(964.3	)	$	(448.7	)	$	(196.6	)
Change in Pension Plan Assets
Fair Value of Plan Assets as of Beginning of Year	$	1,977.6		$	918.4		$	185.4		$	209.8		$	1,789.6		$	844.5		$	137.1		$	190.8
Actual Return on Plan Assets		19.1			6.8			0.6			3.0			274.1			128.0			21.4			29.3
Employer Contribution		143.6			—			112.6			—			45.0			—			45.0			—
Benefits Paid — Excluding Lump Sum Payments		(134.4	)		(55.6	)		(18.9	)		(10.8	)		(130.2	)		(54.1	)		(18.1	)		(10.3	)
Benefits Paid — Lump Sum Payments		—			—			—			—			(0.9	)		—			—			—
Fair Value of Plan Assets as of End of Year	$	2,005.9		$	869.6		$	279.7		$	202.0		$	1,977.6		$	918.4		$	185.4		$	209.8
Funded Status as of December 31st	$	(1,093.0	)	$	(174.2	)	$	(218.2	)	$	(13.8	)	$	(843.3	)	$	(45.9	)	$	(263.3	)	$	13.2
	PBOP Benefits
	As of December 31, 2011												As of December 31, 2010
(Millions of Dollars)	NU			CL&P			PSNH			WMECO			NU			CL&P			PSNH			WMECO
Change in Benefit Obligation
Benefit Obligation as of Beginning of Year	$	(489.9	)	$	(190.2	)	$	(89.9	)	$	(41.7	)	$	(475.7	)	$	(188.1	)	$	(87.5	)	$	(41.0	)
Service Cost		(9.2	)		(2.9	)		(1.9	)		(0.6	)		(8.5	)		(2.7	)		(1.8	)		(0.6	)
Interest Cost		(25.7	)		(10.0	)		(4.8	)		(2.2	)		(26.8	)		(10.5	)		(5.0	)		(2.3	)
Actuarial Loss		(30.1	)		(8.5	)		(8.4	)		(1.0	)		(17.5	)		(4.3	)		(1.5	)		(1.0	)
Federal Subsidy on Benefits Paid		(4.1	)		(1.8	)		(0.7	)		(0.4	)		(3.7	)		(1.6	)		(0.6	)		(0.3	)
Benefits Paid		38.1			14.5			6.5			3.0			42.3			17.0			6.5			3.5
Benefit Obligation as of End of Year	$	(520.9	)	$	(198.9	)	$	(99.2	)	$	(42.9	)	$	(489.9	)	$	(190.2	)	$	(89.9	)	$	(41.7	)
Change in Plan Assets
Fair Value of Plan Assets as of Beginning of Year	$	278.5		$	108.6		$	56.9		$	26.7		$	240.3		$	93.2		$	47.7		$	23.6
Actual Return on Plan Assets		(2.5	)		(1.2	)		(0.4	)		(0.1	)		34.9			13.8			7.0			3.4
Employer Contribution		47.5			19.3			8.7			3.5			45.6			18.6			8.7			3.2
Benefits Paid		(38.1	)		(14.5	)		(6.5	)		(3.0	)		(42.3	)		(17.0	)		(6.5	)		(3.5	)
Fair Value of Plan Assets as of End of Year	$	285.4		$	112.2		$	58.7		$	27.1		$	278.5		$	108.6		$	56.9		$	26.7
Funded Status as of December 31st	$	(235.5	)	$	(86.7	)	$	(40.5	)	$	(15.8	)	$	(211.4	)	$	(81.6	)	$	(33.0	)	$	(15.0	)

B-90

Pension and SERP benefits funded status includes the current portion of the SERP liability, which is included in Other Current Liabilities on the accompanying consolidated balance sheets.

The accumulated benefit obligation for the Pension Plan as of December 31, 2011 and 2010 is as follows:

	Pension and SERP Benefits
(Millions of Dollars)	2011		2010
NU	$	2,810.6	$	2,551.1
CL&P		938.4		868.3
PSNH		444.8		397.9
WMECO		195.5		177.4

The following actuarial assumptions were used in calculating the plans’ year end funded status:

	As of December 31,
	Pension and SERP Benefits						PBOP Benefits
	2011			2010			2011			2010
Discount Rate		5.03	%		5.57	%		4.84	%		5.28	%
Compensation/Progression Rate		3.50	%		3.50	%		N/A			N/A
Health Care Cost Trend Rate		N/A			N/A			7.00	%		7.00	%

The following is a summary of the changes in plan assets and benefit obligations recognized in Regulatory Assets and OCI as well as amounts in Regulatory Assets and OCI reclassified as net periodic benefit (expense)/income during the years presented:

	Amount Reclassified To/From
	Regulatory Assets						OCI
	For the Years Ended December 31,
(Millions of Dollars)	2011			2010			2011			2010
Pension and SERP
Actuarial Losses Reclassified as Net Periodic Benefit Expense	$	(79.4	)	$	(51.0	)	$	(4.8	)	$	(2.7	)
Actuarial Losses Arising During the Year		334.8			45.3			23.0			3.7
Prior Service Cost Reclassified as Net Periodic Benefit Expense		(9.4	)		(9.5	)		(0.3	)		(0.3	)
PBOP
Actuarial Losses Reclassified as Net Periodic Benefit Expense	$	(18.1	)	$	(15.9	)	$	(0.9	)	$	(0.8	)
Actuarial Losses Arising During the Year		50.2			4.2			4.0			0.7
Prior Service Credit Reclassified as Net Periodic Benefit Income		0.3			0.3			—			—
Transition Obligation Reclassified as Net Periodic Benefit Expense		(11.3	)		(11.3	)		(0.2	)		(0.2	)

The following is a summary of the remaining Regulatory Assets and Accumulated Other Comprehensive Loss amounts that have not been recognized as components of net periodic benefit expense as of December 31, 2011 and 2010, and the amounts that are expected to be recognized as components in 2012:

	Regulatory Assets as  of December 31,						Expected 2012 Expense			AOCI as of December 31,				Expected 2012 Expense
(Millions of Dollars)	2011			2010						2011		2010
Pension and SERP
Actuarial Loss	$	1,126.1		$	871.2		$	113.4		$	70.2	$	51.9	$	7.0
Prior Service Cost		29.3			38.8			8.1			1.4		1.7		0.3
PBOP
Actuarial Loss	$	196.3		$	164.2		$	20.6		$	12.1	$	9.0	$	1.2
Prior Service Credit		(2.4	)		(2.7	)		(0.3	)		—		—		—
Transition Obligation		11.4			22.7			11.3			0.2		0.5		0.2

B-91

The Company amortizes the prior service cost on an individual subsidiary basis and amortizes unrecognized net actuarial gains/(losses) and any remaining transition obligation over the remaining service lives of its employees as calculated on an NU consolidated basis. The pension transition obligation is fully amortized and the PBOP transition obligation will be fully amortized in 2013.

The components of net periodic benefit expense/(income), the portion of pension amounts capitalized related to employees working on capital projects, and intercompany allocations not included in the net periodic benefit expense amounts for the Pension and PBOP Plans are as follows:

	For the Year Ended December 31, 2011
	Pension and SERP												PBOP
(Millions of Dollars)	NU			CL&P			PSNH			WMECO			NU			CL&P			PSNH			WMECO
Service Cost	$	55.4		$	19.5		$	10.6		$	3.9		$	9.2		$	2.9		$	1.9		$	0.6
Interest Cost		153.3			51.9			24.4			10.7			25.7			10.0			4.8			2.2
Expected Return on Plan Assets		(170.8	)		(76.6	)		(19.8	)		(17.7	)		(21.6	)		(8.7	)		(4.3	)		(2.0	)
Actuarial Loss		84.2			33.4			10.7			7.1			19.0			7.2			3.2			1.1
Prior Service Cost/(Credit)		9.7			4.2			1.8			0.9			(0.3	)		—			—			1.3
Net Transition Obligation Cost		—			—			—			—			11.6			6.2			2.5
Total Net Periodic Benefit Expense	$	131.8		$	32.4		$	27.7		$	4.9		$	43.6		$	17.6		$	8.1		$	3.2
Related Intercompany Allocations		N/A		$	34.1		$	7.6		$	6.2			N/A		$	8.2		$	2.0		$	1.5
Capitalized Pension Expense	$	29.7		$	16.6		$	7.6		$	2.7

	For the Year Ended December 31, 2010
	Pension and SERP												PBOP
(Millions of Dollars)	NU			CL&P			PSNH			WMECO			NU			CL&P			PSNH			WMECO
Service Cost	$	51.0		$	17.6		$	10.0		$	3.5		$	8.5		$	2.7		$	1.8		$	0.6
Interest Cost		152.6			52.2			24.1			10.7			26.8			10.5			5.0			2.3
Expected Return on Plan Assets		(182.6	)		(85.8	)		(14.7	)		(19.5	)		(21.7	)		(8.7	)		(4.3	)		(2.1	)
Actuarial Loss		53.5			20.7			7.2			4.3			16.7			6.3			2.7			0.9
Prior Service Cost/(Credit)		9.9			4.2			1.8			0.9			(0.3	)		—			—			—
Net Transition Obligation Cost		—			—			—			—			11.6			6.1			2.5			1.3
Total Net Periodic Benefit
Expense/(Income)	$	84.4		$	8.9		$	28.4		$	(0.1	)	$	41.6		$	16.9		$	7.7		$	3.0
Related Intercompany
Allocations		N/A		$	25.2		$	6.0		$	4.5			N/A		$	7.9		$	2.0		$	1.4
Capitalized Pension Expense	$	16.9		$	3.8		$	6.9		$	—

	For the Year Ended December 31, 2009
	Pension and SERP												PBOP
(Millions of Dollars)	NU			CL&P			PSNH			WMECO			NU			CL&P			PSNH			WMECO
Service Cost	$	45.8		$	16.0		$	8.9		$	3.3		$	7.2		$	2.2		$	1.5		$	0.5
Interest Cost		155.7			54.5			24.4			11.1			29.1			11.5			5.4			2.5
Expected Return on Plan Assets		(189.4	)		(89.0	)		(15.0	)		(20.0	)		(20.9	)		(8.3	)		(4.1	)		(2.0	)
Actuarial Loss		21.0			8.9			3.2			1.8			10.5			4.0			1.7			0.4
Prior Service Cost/(Credit)		9.9			4.2			1.8			0.9			(0.3	)		—			—			—
Net Transition Obligation Cost		0.3			—			0.3			—			11.6			6.1			2.5			1.3
Total Net Periodic Benefit
Expense/(Income)	$	43.3		$	(5.4	)	$	23.6		$	(2.9	)	$	37.2		$	15.5		$	7.0		$	2.7
Related Intercompany
Allocations		N/A		$	16.3		$	3.6		$	2.7			N/A		$	7.3		$	1.7		$	1.1
Capitalized Pension Expense	$	6.2		$	(2.6	)	$	6.0		$	(1.2	)

B-92

The following assumptions were used to calculate Pension and PBOP expense and income amounts:

	For the Years Ended December 31,
	Pension and SERP									PBOP
	2011			2010			2009			2011			2010			2009
Discount Rate		5.57	%		5.98	%		6.89	%		5.28	%		5.73	%		6.90	%
Expected Long-Term Rate of Return		8.25	%		8.75	%		8.75	%		N/A			N/A			N/A
Compensation/Progression Rate		3.50	%		4.00	%		4.00	%		N/A			N/A			N/A
Expected Long-Term Rate of Return —
Health Assets, Taxable		N/A			N/A			N/A			6.45	%		6.85	%		6.85	%
Life Assets and Non-Taxable Health Assets		N/A			N/A			N/A			8.25	%		8.75	%		8.75	%

For 2011 through 2013, the health care cost trend assumption is 7 percent, subsequently decreasing 50 basis points per year to an ultimate rate of 5 percent in 2017.

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. The effect of changing the assumed health care cost trend rate by one percentage point for the year ended December 31, 2011 would have the following effects:

NU (Millions of Dollars)	One Percentage Point Increase		One Percentage Point Decrease
Effect on Postretirement Benefit Obligation	$	16.2	$	(13.5	)
Effect on Total Service and Interest Cost Components		1.2		(1.0	)

Estimated Future Benefit Payments: The following benefit payments, which reflect expected future service, are expected to be paid/(received) by the Pension, SERP and PBOP Plans:

NU (Millions of Dollars)	Pension and SERP Benefits		PBOP Benefits		Government Subsidy
2012	$	145.4	$	41.4	$	(4.7	)
2013		152.8		42.0		(5.0	)
2014		159.5		42.4		(5.4	)
2015		166.3		42.7		(5.7	)
2016		173.7		42.9		(6.0	)
2017-2021		983.9		215.7		(34.9	)

The government benefits represent amounts expected to be received from the federal government for the Medicare prescription drug benefit under the PBOP Plan related to the corresponding year’s benefit payments.

Contributions: NU’s policy is to annually fund the Pension Plan in an amount at least equal to an amount that will satisfy the requirements of ERISA, as amended by the PPA of 2006, and the Internal Revenue Code. A contribution of $143.6 million ($112.6 million of which was contributed by PSNH) was made in 2011. Based on the current status of the Pension Plan, NU is required to make a contribution to the Pension Plan of approximately $197.3 million in 2012, which will be made in quarterly installments, to meet minimum current funding requirements under the PPA.

For the PBOP plan, it is NU’s policy to annually fund an amount equal to the PBOP Plan’s postretirement benefit cost, excluding curtailment and termination benefits. NU contributed $43.8 million to the PBOP plan in 2011 and expects to make $44.7 million in contributions to the PBOP plan in 2012. NU also makes an additional contribution to the PBOP plan for the amounts received from the federal Medicare subsidy. This amount was $3.7 million in 2011 and is expected to be $4.7 million in 2012.

B-93

Fair Value of Pension and PBOP Assets: Pension and PBOP funds are held in external trusts. Trust assets, including accumulated earnings, must be used exclusively for Pension and PBOP payments. NU’s investment strategy for its Pension and PBOP Plans is to maximize the long-term rates of return on these plans’ assets within an acceptable level of risk. The investment strategy for each asset category includes a diversification of asset types, fund strategy and fund managers and establishes target asset allocations that are routinely reviewed and periodically rebalanced. In 2011, PBOP assets are comprised of specific assets within the defined benefit pension plan trust (401(h) assets) as well as assets held in the PBOP Plans. The investment policy and strategy of the 401(h) assets is consistent with those of the defined benefit pension plans, which are detailed below. NU’s expected long-term rates of return on Pension and PBOP Plan assets are based on these target asset allocation assumptions and related expected long-term rates of return. In developing its expected long-term rate of return assumptions for the Pension and PBOP Plans, NU evaluated input from actuaries and consultants, as well as long-term inflation assumptions and historical returns. As of December 31, 2011, management has assumed long-term rates of return of 8.25 percent on Pension and PBOP Plan assets. These long-term rates of return are based on the assumed rates of return for the target asset allocations as follows:

	As of December 31,
							Pension and PBOP						PBOP
	Pension and PBOP						Life and Non-Taxable Health						Taxable Health
	2011						2010						2010
	Target Asset Allocation			Assumed Rate of  Return			Target Asset Allocation			Assumed Rate of  Return			Target Asset Allocation			Assumed Rate of  Return
Equity Securities:
United States		24	%		9	%		24	%		9	%		55	%		9	%
International		13	%		9	%		13	%		9	%		15	%		9	%
Emerging Markets		3	%		10	%		3	%		10	%		—			—
Private Equity		12	%		13	%		12	%		13	%		—			—
Debt Securities:
Fixed Income		20	%		5	%		20	%		5	%		30	%		5	%
High Yield Fixed Income		3.5	%		7.5	%		3.5	%		7.5	%		—			—
Emerging Markets Debt		3.5	%		7.5	%		3.5	%		7.5	%		—			—
Real Estate and Other Assets		8	%		7.5	%		8	%		7.5	%		—			—
Hedge Funds		13	%		7	%		13	%		7	%		—			—

The following table presents, by asset category, the Pension and PBOP Plan assets recorded at fair value on a recurring basis by the level in which they are classified within the fair value hierarchy:

	Pension Plan
	Fair Value Measurements as of December 31,
	2011									2010
(Millions of Dollars)	Level 1		Level 2		Level 3		Total			Level 1		Level 2		Level 3		Total
Asset Category:
Equity Securities:
United States (1)	$	218.7	$	14.8	$	259.4	$	492.9		$	256.3	$	46.9	$	266.0	$	569.2
International (1)		20.0		221.9		—		241.9			6.4		250.9		—		257.3
Emerging Markets (1)		—		66.6		—		66.6			—		81.1		—		81.1
Private Equity		11.3		—		255.1		266.4			6.9		—		229.5		236.4
Fixed Income (2)		17.8		268.7		276.2		562.7			7.6		261.6		247.6		516.8
Real Estate and								—
Other Assets		24.8		57.8		71.8		154.4			—		26.0		43.7		69.7
Hedge Funds		—		—		240.0		240.0			—		—		247.1		247.1
Total Master Trust Assets	$	292.6	$	629.8	$	1,102.5	$	2,024.9		$	277.2	$	666.5	$	1,033.9	$	1,977.6
Less: 401(h) PBOP Assets								(19.0	)								—
Total Pension Assets							$	2,005.9								$	1,977.6

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	PBOP Plan
	Fair Value Measurements as of December 31,
	2011								2010
(Millions of Dollars)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Asset Category:
Cash and Cash
Equivalents	$	5.9	$	—	$	—	$	5.9	$	4.4	$	—	$	—	$	4.4
Equity Securities:
United States		116.9		—		10.7		127.6		132.1		—		10.1		142.2
International		29.6		—		—		29.6		34.8		—		—		34.8
Emerging Markets		4.6		—		—		4.6		7.7		—		—		7.7
Debt Securities:
Fixed Income (2)		—		34.9		26.0		60.9		—		35.3		23.4		58.7
High Yield Fixed Income		—		4.5		—		4.5		—		4.4		—		4.4
Emerging Market Debt		—		4.9		—		4.9		—		4.8		—		4.8
Hedge Funds		—				16.1		16.1		—		—		16.4		16.4
Private Equity		—		—		5.1		5.1		—		—		0.3		0.3
Real Estate and Other Assets		—		4.7		2.5		7.2		—		4.8		—		4.8
Total	$	157.0	$	49.0	$	60.4	$	266.4	$	179.0	$	49.3	$	50.2	$	278.5
Add: 401(h) PBOP Assets								19.0								—
Total PBOP Assets							$	285.4							$	278.5

(1) United States, International and Emerging Markets equity securities classified as Level 2 include investments in commingled funds and unrealized gains/(losses) on holdings in equity index swaps. Level 3 investments include hedge funds that are overlayed with equity index swaps and futures contracts.

(2) Fixed Income investments classified as Level 3 investments include fixed income funds that invest in a variety of opportunistic fixed income strategies, and hedge funds that are overlayed with fixed income futures.

The Company values assets based on observable inputs when available. Equity securities, exchange traded funds and futures contracts classified as Level 1 in the fair value hierarchy are priced based on the closing price on the primary exchange as of the balance sheet date. Commingled funds included in Level 2 equity securities are recorded at the net asset value provided by the asset manager, which is based on the market prices of the underlying equity securities. Swaps are valued using pricing models that incorporate interest rates and equity and fixed income index closing prices to determine a net present value of the cash flows. Fixed income securities, such as government issued securities, corporate bonds and high yield bond funds, are included in Level 2 and are valued using pricing models, quoted prices of securities with similar characteristics or discounted cash flows. The pricing models utilize observable inputs such as recent trades for the same or similar instruments, yield curves, discount margins and bond structures. Hedge funds and investments in opportunistic fixed income funds are recorded at net asset value based on the values of the underlying assets. The assets in the hedge funds and opportunistic fixed income funds are valued using observable inputs and are classified as Level 3 within the fair value hierarchy due to redemption restrictions. Private Equity investments and Real Estate and Other Assets are valued using the net asset value provided by the partnerships, which are based on discounted cash flows of the underlying investments, real estate appraisals or public market comparables of the underlying investments. These investments are classified as Level 3 due to redemption restrictions.

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Fair Value Measurements Using Significant Unobservable Inputs (Level 3): The following tables present changes for the Level 3 category of Pension and PBOP Plan assets for the years ended December 31, 2011 and 2010:

	Pension Plan
(Millions of Dollars)	United States Equity			Private Equity			Fixed Income			Real Estate and Other Assets		Hedge Funds			Total
Balance as of January 1, 2010	$	252.1		$	193.8		$	174.0		$	38.5	$	231.2		$	889.6
Actual Return on Plan Assets:
Relating to Assets Still Held as of Year End		13.9			10.9			21.0			0.5		15.9			62.2
Relating to Assets Distributed During the Year		—			—			—			0.5		—			0.5
Purchases, Sales and Settlements		—			24.8			52.6			4.2		—			81.6
Balance as of December 31, 2010	$	266.0		$	229.5		$	247.6		$	43.7	$	247.1		$	1,033.9
Actual Return on Plan Assets:
Relating to Assets Still Held as of Year End		(6.6	)		20.0			(1.5	)		1.6		(7.1	)		6.4
Relating to Assets Distributed During the Year		—			19.5			(2.8	)		0.3		—			17.0
Purchases, Sales and Settlements		—			(13.9	)		32.9			26.2		—			45.2
Balance as of December 31, 2011	$	259.4		$	255.1		$	276.2		$	71.8	$	240.0		$	1,102.5

	PBOP Plan
(Millions of Dollars)	United States Equity		Private Equity		Fixed Income			Real Estate and Other Assets			Hedge Funds			Total
Balance as of January 1, 2010	$	—	$	—	$	24.6		$	—		$	—		$	24.6
Actual Return/(Loss) on Plan Assets:
Relating to Assets Still Held as of Year End		0.5		—		3.2			—			0.4			4.1
Purchases, Sales and Settlements		9.6		0.3		(4.4	)		—			16.0			21.5
Balance as of December 31, 2010	$	10.1	$	0.3	$	23.4		$	—		$	16.4		$	50.2
Actual Return/(Loss) on Plan Assets:
Relating to Assets Still Held as of Year End		0.6		0.6		0.2			(0.1	)		(0.3	)		1.0
Purchases, Sales and Settlements		—		4.2		2.4			2.6						9.2
Balance as of December 31, 2011	$	10.7	$	5.1	$	26.0		$	2.5		$	16.1		$	60.4

B. Defined Contribution Plans

NU maintains a 401(k) Savings Plan for substantially all employees, including CL&P, PSNH and WMECO employees. This savings plan provides for employee contributions up to specified limits. NU matches employee contributions up to a maximum of three percent of eligible compensation with one percent in cash and two percent in NU common shares allocated from the ESOP. The 401(k) matching contributions of cash and NU common shares were as follows:

(Millions of Dollars)	NU		CL&P		PSNH		WMECO
2011	$	13.2	$	4.0	$	2.5	$	0.8
2010		12.7		4.0		2.4		0.8
2009		12.2		3.9		2.3		0.7

Effective on January 1, 2006, all newly hired, non-bargaining unit employees, and effective on January 1, 2007 or as subject to collective bargaining agreements, certain newly hired bargaining unit employees participate in a program under the 401(k) Savings Plan called the K-Vantage benefit. These employees are not eligible to

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participate in the Pension Plan. In addition, participants in the Pension Plan as of January 1, 2006 were given the opportunity to choose to become a participant in the K-Vantage benefit beginning in 2007, in which case their benefit under the Pension Plan was frozen. NU makes contributions to the K-Vantage benefit based on a percentage of participants’ eligible compensation, as defined by the benefit document. The contributions made were as follows:

(Millions of Dollars)	NU		CL&P		PSNH		WMECO
2011	$	4.2	$	0.5	$	0.6	$	0.1
2010		3.4		0.4		0.4		0.1
2009		2.6		0.2		0.3		—

C. Employee Stock Ownership Plan

NU maintains an ESOP for purposes of allocating shares to NU, CL&P, PSNH and WMECO’s employees participating in NU’s 401(k) Savings Plan. NU issued unsecured notes during 1991 and 1992 totaling $250 million, the proceeds of which were loaned to the ESOP trust (ESOP Notes) for the purchase of 10.8 million newly issued NU common shares (ESOP shares). During 2010, the ESOP Notes were fully repaid and all ESOP shares purchased with the proceeds of the ESOP Notes were fully allocated. As of December 31, 2011 and 2010, total allocated ESOP shares were 10,800,185. Following complete allocation of the ESOP shares, continuing allocations of NU common shares were made from NU treasury shares to satisfy the 401(k) Savings Plan obligation to provide a portion of the matching contribution in NU common shares. NU’s contributions to the ESOP trust for the years ended December 31, 2010 and 2009 totaled $1.1 million and $6.1 million, respectively. As the ESOP notes were fully repaid in 2010, no contributions were made in 2011. In 2010, the ESOP trust allocated 127,054 of NU common shares to satisfy 401(k) Savings Plan obligations to employees.

For treasury shares used to satisfy the 401(k) Savings Plan matching contributions, compensation expense is recognized equal to the fair value of shares that have been allocated to participants. Any difference between the fair value and the average cost of the allocated treasury shares is charged or credited to Capital Surplus, Paid In. For the years ended December 31, 2011, 2010 and 2009, NU recognized $8.8 million, $8.5 million and $8.2 million, respectively, of expense related to the ESOP.

Dividends on the ESOP unallocated shares are not considered dividends for financial reporting purposes. For the years ended 2011, 2010 and 2009, NU paid quarterly dividends of $0.275 per share, $0.25625 per share and $0.2375 per share, respectively.

D. Share-Based Payments

In accordance with accounting guidance for share-based payments, share-based compensation awards are recorded using the fair value-based method based on the fair value at the date of grant. This guidance applies to share-based compensation awards granted on or after January 1, 2006 or to awards for which the requisite service period has not been completed. NU, CL&P, PSNH and WMECO record compensation cost related to these awards, as applicable, for shares issued or sold to NU, CL&P, PSNH and WMECO employees and officers, as well as the allocation of costs associated with shares issued or sold to NUSCO employees and officers that support CL&P, PSNH and WMECO.

NU Incentive Plan: NU maintains long-term equity-based incentive plans under the NU Incentive Plan in which NU, CL&P, PSNH and WMECO employees, officers and board members are entitled to participate. The NU Incentive Plan was approved in 2007, and authorized NU to grant up to 4,500,000 new shares for various types of awards, including RSUs and performance shares, to eligible employees, officers, and board members. As of December 31, 2011 and 2010, NU had 2,685,615 and 3,068,850 common shares, respectively, available for issuance under the NU Incentive Plan. In addition to the NU Incentive Plan, NU maintains an ESPP for all eligible NU, CL&P, PSNH and WMECO employees.

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NU accounts for its various share-based plans as follows:

• For grants of RSUs, NU records compensation expense, net of estimated forfeitures, on a straight-line basis over the vesting period based upon the fair value of NU’s common shares at the date of grant. Dividend equivalents on RSUs are charged to retained earnings, net of estimated forfeitures.

• For grants of performance shares, NU records compensation expense, net of estimated forfeitures, on a straight-line basis over the vesting period. Performance shares vest based upon the extent to which Company goals are achieved. For the majority of performance shares, fair value is based upon the value of NU’s common shares at the date of grant and compensation expense is recorded based upon the probable outcome of the achievement of Company targets. The fair value of the remaining performance shares are based upon the achievement of the Company’s share price as compared to an index of similar equity securities. The fair value at the date of grant for these remaining performance shares was determined using a lattice model and compensation expense is recorded over the vesting period.

• For shares sold under the ESPP, no compensation expense is recorded, as the ESPP qualifies as a non-compensatory plan.

For the years ended December 31, 2011, 2010 and 2009, additional tax benefits totaling $1.3 million, $0.9 million and $0.9 million, respectively, increased cash flows from financing activities.

RSUs: NU has granted RSUs under the 2004 through 2011 incentive programs that are subject to three-year and four-year graded vesting schedules for employees, and one-year graded vesting schedules for board members. RSUs are paid in shares, reduced by amounts sufficient to satisfy withholdings, subsequent to vesting. A summary of RSU transactions is as follows:

RSUs	RSUs (Units)			Weighted Average Grant-Date Fair Value
Outstanding as of January 1, 2009		912,991		$	24.75
Granted		347,112		$	23.26
Shares issued		(203,888	)	$	25.55
Forfeited		(18,303	)	$	26.26
Outstanding as of December 31, 2009		1,037,912		$	24.07
Granted		258,174		$	26.03
Shares issued		(267,951	)	$	25.05
Forfeited		(13,656	)	$	24.26
Outstanding as of December 31, 2010		1,014,479		$	24.31
Granted		208,533		$	33.87
Shares issued		(244,782	)	$	24.47
Forfeited		(18,310	)	$	23.74
Outstanding as of December 31, 2011		959,920		$	26.36

As of December 31, 2011 and 2010, the number and weighted average grant-date fair value of unvested RSUs was 403,108 and $28.70 per share, and 519,900 and $24.77 per share, respectively. The number and weighted average grant-date fair value of RSUs vested during 2011 was 292,185 and $25.25 per share, respectively. As of December 31, 2011, 556,812 RSUs were fully vested and an additional 382,953 are expected to vest.

On November 16, 2010, NU granted 192,309 RSUs to certain executives, contingent upon completion of the pending merger with NSTAR, with a three year vesting period that would begin as of the closing date of the merger.

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Performance Shares: NU has granted performance shares under the 2009, 2010 and 2011 incentive programs that vest based upon the extent to which the Company achieves targets at the end of each respective three-year performance measurement period. Performance shares are paid in shares, after the performance measurement period. A summary of performance share transactions is as follows:

Performance Shares	Performance Shares (Units)			Weighted Average Grant-Date Fair Value
Outstanding as of January 1, 2009		—		$	—
Granted		104,150		$	23.93
Shares issued		—		$	—
Forfeited		(5,064	)	$	23.96
Outstanding as of December 31, 2009		99,086		$	23.93
Granted		149,520		$	25.24
Shares issued		—		$	—
Forfeited		(47	)	$	23.96
Outstanding as of December 31, 2010		248,559		$	24.72
Granted		244,870		$	33.76
Shares issued		—		$	—
Forfeited		(10,296	)	$	30.47
Outstanding as of December 31, 2011		483,133		$	29.18

As of December 31, 2011, performance shares vested at 100 percent of target under the 2009 incentive program. Such shares will be distributed to participants in the form of NU common shares prior to March 15, 2012. Under this performance plan, 105,934 shares vested, with a weighted-average grant date fair value of $24.42 per share.

As of December 31, 2011 and 2010, there were 377,199 and 248,559 unvested performance shares with a weighted-average grant date fair value of $30.52 per share and $24.72 per share, respectively. As of December 31, 2011, based upon the probable outcome of certain performance metrics, performance shares are expected to vest at 115 percent of target under the 2010 incentive program, and at 98 percent of target under the 2011 incentive program.

The total compensation cost recognized by NU, CL&P, PSNH and WMECO for share-based compensation awards was as follows:

NU	For the Years Ended December 31,
(Millions of Dollars)	2011		2010		2009
Compensation Cost Recognized	$	12.3	$	10.5	$	8.8
Associated Future Income Tax Benefit Recognized		4.9		4.2		3.5

	For the Years Ended December 31,
	2011						2010						2009
(Millions of Dollars)	CL&P		PSNH		WMECO		CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
Compensation Cost Recognized	$	7.1	$	2.5	$	1.4	$	6.2	$	2.1	$	1.1	$	5.3	$	1.7	$	0.9
Associated Future Income Tax Benefit Recognized		2.8		1.0		0.6		2.5		0.9		0.4		2.1		0.7		0.4

As of December 31, 2011, there was $8.9 million of total unrecognized compensation cost related to nonvested share-based awards for NU, $5.0 million for CL&P, $1.8 million for PSNH and $1.0 million for WMECO. This cost is expected to be recognized ratably over a weighted-average period of 1.77 years for NU, CL&P and PSNH and 1.76 years for WMECO.

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Stock Options: Prior to 2003, NU granted stock options to certain employees. The options expire ten years from the date of grant. All options were fully vested as of December 31, 2005. The fair value of each stock option grant was estimated on the date of grant using the Black-Scholes option pricing model. The weighted average remaining contractual lives for the options outstanding as of December 31, 2011 is 0.3 years. No compensation expense related to stock options was recorded for the years ended December 31, 2011, 2010 or 2009. A summary of stock option transactions is as follows:

	Options			Exercise Price Per Share							Intrinsic Value (Millions)
				Range					Weighted Average
Outstanding and exercisable — January 1, 2009		320,920		$	14.94	—	$	21.03	$	18.83
Exercised		(95,704	)						$	18.54	$	0.6
Forfeited and cancelled		—							$	—
Outstanding and exercisable — December 31, 2009		225,216		$	17.40	—	$	21.03	$	18.96
Exercised		(112,617	)						$	19.12	$	1.0
Forfeited and cancelled		—							$	—
Outstanding and exercisable — December 31, 2010		112,599		$	17.40	—	$	21.03	$	18.80
Exercised		(65,225	)						$	18.81	$	1.0
Forfeited and cancelled		—							$	—
Outstanding and exercisable — December 31, 2011		47,374		$	18.58	—	$	18.90	$	18.78	$	0.8

Cash received for options exercised during the year ended December 31, 2011 totaled $1.2 million. The tax benefit realized from stock options exercised totaled $0.4 million for the year ended December 31, 2011.

Employee Share Purchase Plan: NU maintains an ESPP for all eligible NU, CL&P, PSNH, and WMECO employees, which allows for NU common shares to be purchased by employees at the end of successive six-month offering periods at 95 percent of the closing market price on the last day of each six-month period. Employees are permitted to purchase shares having a value not exceeding 25 percent of their compensation as of the beginning of the offering period up to a limit of $25,000 per annum. The ESPP qualifies as a non-compensatory plan under accounting guidance for share-based payments, and no compensation expense is recorded for ESPP purchases.

During 2011, employees purchased 35,476 shares at discounted prices of $31.27 and $32.30. Employees purchased 38,672 shares in 2010 at discounted prices of $26.45 and $24.05. As of December 31, 2011 and 2010, 896,702 and 932,178 shares, respectively, remained available for future issuance under the ESPP.

An income tax rate of 40 percent is used to estimate the tax effect on total share-based payments determined under the fair value-based method for all awards. The Company generally settles stock option exercises and fully vested RSUs and performance shares with the issuance of new common shares.

E. Other Retirement Benefits

NU provides benefits for retirement and other benefits for certain current and past company officers of NU, including CL&P, PSNH and WMECO. These benefits are accounted for on an accrual basis and expensed over the service lives of the employees. The actuarially-determined liability for these benefits, which is included in Other Long-Term Liabilities on the accompanying consolidated balance sheets, as well as the related expense, were as follows:

NU	For the Years Ended December 31,
(Millions of Dollars)	2011		2010		2009
Actuarially-Determined Liability	$	52.8	$	49.9	$	47.9
Other Retirement Benefits Expense		4.7		4.2		3.9

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	For the Years Ended December 31,
	2011						2010						2009
(Millions of Dollars)	CL&P		PSNH		WMECO		CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
Actuarially-Determined Liability	$	1.2	$	2.5	$	0.2	$	0.4	$	2.4	$	0.2	$	0.4	$	2.4	$	0.2
Other Retirement Benefits Expense		2.6		1.0		0.5		2.3		0.9		0.4		2.2		0.9		0.4

11. INCOME TAXES

The tax effect of temporary differences is accounted for in accordance with the rate-making treatment of the applicable regulatory commissions and relevant accounting authoritative literature. Details of income tax expense and the components of the federal and state income tax provisions are as follows:

NU	For the Years Ended December 31,
(Millions of Dollars)	2011			2010			2009
Current Income Taxes:
Federal	$	3.0		$	9.0		$	4.5
State		(26.0	)		(6.5	)		52.7
Total Current		(23.0	)		2.5			57.2
Deferred Income Taxes, Net:
Federal		187.7			201.2			155.1
State		9.1			9.7			(29.2	)
Total Deferred		196.8			210.9			125.9
Investment Tax Credits, Net		(2.8	)		(3.0	)		(3.2	)
Income Tax Expense	$	171.0		$	210.4		$	179.9

	For the Years Ended December 31,
	2011									2010									2009
(Millions of Dollars)	CL&P			PSNH			WMECO			CL&P			PSNH			WMECO			CL&P			PSNH			WMECO
Current Income Taxes:
Federal	$	13.9		$	(25.8	)	$	0.1		$	20.7		$	6.1		$	3.1		$	28.3		$	(8.9	)	$	(8.6	)
State		(34.4	)		0.1			0.3			(1.1	)		5.6			2.5			40.1			5.8			0.9
Total Current		(20.5	)		(25.7	)		0.4			19.6			11.7			5.6			68.4			(3.1	)		(7.7	)
Deferred Income Taxes, Net:
Federal		106.4			67.7			22.1			108.1			37.6			11.0			80.5			34.4			21.3
State		6.2			7.9			1.0			7.0			1.6			—			(27.6	)		0.8			1.6
Total Deferred		112.6			75.6			23.1			115.1			39.2			11.0			52.9			35.2			22.9
Investment Tax Credits, Net		(2.1	)		—			(0.3	)		(2.3	)		(0.1	)		(0.3	)		(2.5	)		(0.1	)		(0.3	)
Income Tax Expense	$	90.0		$	49.9		$	23.2		$	132.4		$	50.8		$	16.3		$	118.8		$	32.0		$	14.9

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A reconciliation between income tax expense and the expected tax expense at the statutory rate is as follows:

NU	For the Years Ended December 31,
(Millions of Dollars, except percentages)	2011			2010			2009
Income Before Income Tax Expense	$	571.5		$	604.5		$	515.5
Statutory Federal Income Tax Expense at 35%		200.0			211.6			180.4
Tax Effect of Differences:
Depreciation		(14.2	)		(9.5	)		(2.7	)
Investment Tax Credit Amortization		(2.8	)		(3.0	)		(3.2	)
Other Federal Tax Credits		(3.5	)		(3.8	)		(3.8	)
State Income Taxes, Net of Federal Impact		22.1			12.5			11.5
Medicare Subsidy		—			15.6			(3.5	)
Tax Asset Valuation Allowance/Reserve Adjustments		(33.1	)		(10.5	)		3.8
Other, Net		2.5			(2.5	)		(2.6	)
Income Tax Expense	$	171.0		$	210.4		$	179.9
Effective Tax Rate		29.9	%		34.8	%		34.9	%

	For the Years Ended December 31,
	2011									2010									2009
(Millions of Dollars, except percentages)	CL&P			PSNH			WMECO			CL&P			PSNH			WMECO			CL&P			PSNH			WMECO
Income Before Income Tax Expense	$	340.2		$	150.2		$	66.2		$	376.6		$	140.9		$	39.4		$	335.2		$	97.6		$	41.1
Statutory Federal Income Tax Expense at 35%		119.1			52.6			23.2			131.8			49.3			13.8			117.3			34.1			14.4
Tax Effect of Differences:
Depreciation		(8.1	)		(4.4	)		0.1			(6.1	)		(3.2	)		0.2			(1.7	)		(1.2	)		0.3
Investment Tax Credit Amortization		(2.1	)		—			(0.3	)		(2.3	)		(0.1	)		(0.3	)		(2.5	)		(0.1	)		(0.3	)
Other Federal Tax Credits		(0.1	)		(3.4	)		—			(0.1	)		(3.6	)		—			(0.1	)		(3.7	)		—
State Income Taxes, Net of Federal Impact		4.0			5.2			0.9			8.5			4.7			1.6			8.9			4.3			1.6
Medicare Subsidy		—			—			—			7.8			3.8			1.5			(1.3	)		(0.6	)		(0.3	)
Tax Asset Valuation Allowance/ Reserve Adjustments		(22.3	)		—			—			(4.7	)		—			—			(0.8	)		—			—
Other, Net		(0.5	)		(0.1	)		(0.7	)		(2.5	)		(0.1	)		(0.5	)		(1.0	)		(0.8	)		(0.8	)
Income Tax Expense	$	90.0		$	49.9		$	23.2		$	132.4		$	50.8		$	16.3		$	118.8		$	32.0		$	14.9
Effective Tax Rate		26.5	%		33.2	%		35.0	%		35.2	%		36.1	%		41.4	%		35.4	%		32.8	%		36.3	%

NU, CL&P, PSNH and WMECO file a consolidated federal income tax return and unitary, combined and separate state income tax returns. These entities are also parties to a tax allocation agreement under which taxable subsidiaries do not pay any more taxes than they would have otherwise paid had they filed a separate company tax return, and subsidiaries generating tax losses, if any, are paid for their losses when utilized.

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The tax effects of temporary differences that give rise to the net accumulated deferred tax obligations are as follows:

NU	As of December 31,
(Millions of Dollars)	2011		2010
Deferred Tax Assets:
Employee Benefits	$	539.6	$	470.1
Derivative Liabilities and Change in Fair Value of Energy Contracts		415.3		376.5
Regulatory Deferrals		157.9		135.5
Allowance for Uncollectible Accounts		45.4		46.4
Tax Effect — Tax Regulatory Assets		15.5		17.0
Federal Net Operating Loss Carryforwards		178.6		—
Other		204.2		188.0
Total Deferred Tax Assets		1,556.5		1,233.5
Less: Valuation Allowance		4.6		19.8
Net Deferred Tax Assets	$	1,551.9	$	1,213.7
Deferred Tax Liabilities:
Accelerated Depreciation and Other Plant-Related Differences	$	1,920.5	$	1,612.6
Property Tax Accruals		58.9		55.1
Regulatory Amounts:
Other Regulatory Deferrals		1,135.0		873.3
Tax Effect — Tax Regulatory Assets		184.6		177.1
Securitized Contract Termination Costs		39.6		65.8
Derivative Assets		39.1		48.0
Other		24.5		26.3
Total Deferred Tax Liabilities	$	3,402.2	$	2,858.2

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	As of December 31,
	2011						2010
(Millions of Dollars)	CL&P		PSNH		WMECO		CL&P			PSNH		WMECO
Deferred Tax Assets:
Derivative Liabilities and Change in Fair Value of Energy Contracts	$	412.2	$	—	$	2.9	$	371.2		$	5.1	$	—
Allowance for Uncollectible Accounts		32.4		3.0		3.9		31.5			2.9		5.6
Regulatory Deferrals		78.4		39.3		15.0		68.9			34.4		6.5
Employee Benefits		121.4		87.9		13.3		66.9			125.0		2.4
Tax Effect — Tax Regulatory Assets		6.4		1.6		6.5		7.4			1.6		6.9
Federal Net Operating Loss Carryforwards		85.5		60.8		—		—			—		—
Other		76.0		26.0		17.6		82.5			13.6		10.1
Total Deferred Tax Assets	$	812.3	$	218.6	$	59.2	$	628.4		$	182.6	$	31.5
Deferred Tax Liabilities:
Accelerated Depreciation and Other Plant-Related Differences	$	1,046.9	$	423.8	$	194.9	$	917.0		$	309.8	$	168.4
Property Tax Accruals		41.9		4.5		3.4		39.5			4.2		3.2
Regulatory Amounts:
Securitized Contract Termination Costs		—		29.7		10.0		(0.8	)		50.4		16.2
Other Regulatory Deferrals		734.2		122.5		79.3		546.6			105.1		51.1
Tax Effect — Tax Regulatory Assets		141.8		16.1		13.7		138.5			14.0		13.7
Derivative Assets		39.1		—		—		47.9			—		—
Other		8.2		14.0		1.1		8.4			15.7		2.9
Total Deferred Tax Liabilities	$	2,012.1	$	610.6	$	302.4	$	1,697.1		$	499.2	$	255.5

As of December 31, 2011, NU, CL&P, PSNH and WMECO have adjusted the presentation of Deferred Tax Assets and Liabilities. Amounts as of December 31, 2010 have been reclassified to conform to the December 31, 2011 presentation.

As of December 31, 2011, NU had state credit carryforwards of $101.4 million that begin expiring in 2013. NU’s state net operating loss carryforward as of December 31, 2011 was not significant. As of December 31, 2010, NU had state net operating loss carryforwards of $317.7 million that expire between December 31, 2011 and December 31, 2027 and state credit carryforwards of $84.9 million that begin expiring in 2013. The state net operating loss carryforward deferred tax asset has been fully reserved by a valuation allowance. As of December 31, 2011, NU had a federal net operating loss carryforward of $510.2 million and federal credit carryforwards of $6.6 million that expire December 31, 2031.

As of December 31, 2011, CL&P had state tax credit carryforwards of $68.6 million that begin expiring in 2013. As of December 31, 2010, CL&P had state tax credit carryforwards of $56.1 million that begin expiring in 2013. As of December 31, 2011, CL&P had a federal net operating loss carryforward of $244.2 million that expires December 31, 2031.

As of December 31, 2011, PSNH had a $173.8 million federal net operating loss carryforward and a $3.4 million federal credit carryforward that expire December 31, 2031.

As of December 31, 2011, WMECO had a $3.2 million federal credit carryforward that expires December 31, 2031.

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Unrecognized Tax Benefits: A reconciliation of the activity in unrecognized tax benefits from January 1, 2009 to December 31, 2011, all of which would impact the effective tax rate, if recognized, is as follows:

(Millions of Dollars)	NU			CL&P			PSNH			WMECO
Balance as of January 1, 2009	$	156.3		$	106.4		$	12.4		$	3.8
Gross Increases — Current Year		12.3			8.6			—			—
Settlement		(44.2	)		(26.0	)		(12.4	)		(3.8	)
Lapse of Statute of Limitations		(0.1	)		—			—			—
Balance as of December 31, 2009		124.3			89.0			—			—
Gross Increases — Current Year		10.8			5.3			—			—
Gross Increases — Prior Year		0.8			—			—			—
Settlement		(34.3	)		(13.5	)		—			—
Lapse of Statute of Limitations		(0.4	)		—			—			—
Balance as of December 31, 2010		101.2			80.8			—			—
Gross Increases — Current Year		8.0			1.4			—			—
Gross Decreases — Prior Year		(35.7	)		(35.7	)		—			—
Balance as of December 31, 2011	$	73.5		$	46.5		$	—		$	—

Interest and Penalties: Interest on uncertain tax positions is recorded and generally classified as a component of Other Interest Expense. However, when resolution of uncertainties results in the Company receiving interest income, any related interest benefit is recorded in Other Income, Net on the accompanying consolidated statements of income. No penalties have been recorded. If penalties are recorded in the future, then the estimated penalties would be classified as a component of Other Income, Net on the accompanying consolidated statements of income. The components of interest on uncertain tax positions by company in 2011, 2010 and 2009 are as follows:

Other Interest Expense/(Income)	For the Years Ended December 31,									Accrued Interest Expense	As of December 31,
	2011			2010			2009				2011		2010
(Millions of Dollars)										(Millions of Dollars)
CL&P	$	(3.7	)	$	(7.4	)	$	(4.2	)	CL&P	$	2.7	$	6.4
PSNH		(0.6	)		0.1			(1.3	)	PSNH		—		0.6
WMECO		—			—			(0.4	)	WMECO		—		—
NU Parent and Other		1.5			(17.5	)		1.9		NU Parent and Other		4.4		2.9
Total	$	(2.8	)	$	(24.8	)	$	(4.0	)	Total	$	7.1	$	9.9

Tax Positions: During 2011, NU recorded an after-tax benefit of $29.1 million related to various state tax settlements and certain other adjustments. This benefit is recorded as a reduction to both interest expense and income tax expense (including NU and CL&P tax expense reductions of approximately $22.4 million). NU is currently working to resolve the treatments of certain timing and other costs in the remaining open periods.

Tax Years: The following table summarizes NU, CL&P, PSNH and WMECO’s tax years that remain subject to examination by major tax jurisdictions as of December 31, 2011:

Description	Tax Years
Federal	2011
Connecticut	2005-2011
New Hampshire	2008-2011
Massachusetts	2008-2011

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While tax audits are currently ongoing, it is reasonably possible that one or more of these open tax years could be resolved within the next twelve months. Management estimates that potential resolutions of differences of a non-timing nature, could result in a zero to $50 million decrease in unrecognized tax benefits by NU and a zero to $39 million decrease in unrecognized tax benefits by CL&P. These estimated changes could have an impact on NU’s and CL&P’s 2012 earnings of zero to $32 million and zero to $26 million, respectively. Other companies’ impacts are not expected to be material.

2010 Federal Legislation: On March 23, 2010, President Obama signed into law the 2010 Healthcare Act. The 2010 Healthcare Act was amended by a Reconciliation Bill signed into law on March 30, 2010. The 2010 Healthcare Act includes a provision that eliminated the tax deductibility of certain PBOP contributions for retiree prescription drug benefits. The tax deduction eliminated by this legislation represented a loss of previously recognized deferred income tax assets established through 2009 and as a result, these assets were written down by approximately $18 million in 2010. Since the electric and natural gas distribution companies are cost-of-service and rate-regulated, and approximately $15 million of the $18 million is able to be deferred and recovered through future rates, NU reduced 2010 earnings by $3 million of non-recoverable costs. In addition, as a result of the elimination of the tax deduction in 2010, NU was not able to recognize approximately $2 million of net annual benefits.

On September 27, 2010, President Obama signed into law the Small Business Jobs and Credit Act of 2010, which extends the bonus depreciation provisions of the American Recovery and Reinvestment Act of 2009 to small and large businesses through 2010. This extended stimulus provided NU with cash flow benefits of approximately $100 million.

On December 17, 2010, President Obama signed into law the Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act (2010 Tax Act), which, among other things, provides 100 percent bonus depreciation for tangible personal property placed in service after September 8, 2010, and through December 31, 2011. For tangible personal property placed in service after December 31, 2011, and through December 31, 2012, the 2010 Tax Act provides for 50 percent bonus depreciation.

12. COMMITMENTS AND CONTINGENCIES

A. Environmental Matters

General: NU, CL&P, PSNH and WMECO are subject to environmental laws and regulations intended to mitigate or remove the effect of past operations and improve or maintain the quality of the environment. These laws and regulations require the removal or the remedy of the effect on the environment of the disposal or release of certain specified hazardous substances at current and former operating sites. NU, CL&P, PSNH and WMECO have an active environmental auditing and training program and believe that they are substantially in compliance with all enacted laws and regulations.

Environmental reserves are accrued when assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated. The approach used estimates the liability based on the most likely action plan from a variety of available remediation options, including no action required or several different remedies ranging from establishing institutional controls to full site remediation and monitoring.

These estimates are subjective in nature as they take into consideration several different remediation options at each specific site. The reliability and precision of these estimates can be affected by several factors, including new information concerning either the level of contamination at the site, the extent of NU, CL&P, PSNH and WMECO’s responsibility or the extent of remediation required, recently enacted laws and regulations or a change in cost estimates due to certain economic factors.

The amounts recorded as environmental liabilities included in Other Current Liabilities and Other Long-Term Liabilities on the accompanying consolidated balance sheets represent management’s best estimate of the

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liability for environmental costs, and take into consideration site assessment and remediation costs. NU, CL&P, PSNH and WMECO’s environmental liability also takes into account recurring costs of managing hazardous substances and pollutants, mandated expenditures to remediate previously contaminated sites and any other infrequent and non-recurring clean up costs. A reconciliation of the activity in the environmental reserves is as follows:

(Millions of Dollars)	NU			CL&P			PSNH			WMECO
Balance as of December 31, 2009	$	26.0		$	2.7		$	5.3		$	0.4
Additions		18.2			0.5			8.9			0.1
Payments		(7.1	)		(0.4	)		(5.1	)		(0.2	)
Balance as of December 31, 2010		37.1			2.8			9.1			0.3
Additions		1.6			0.4			0.1			0.1
Payments		(7.0	)		(0.3	)		(2.6	)		(0.1	)
Balance as of December 31, 2011	$	31.7		$	2.9		$	6.6		$	0.3

These liabilities are estimated on an undiscounted basis and do not assume that any amounts are recoverable from insurance companies or other third parties. NU, CL&P, PSNH and WMECO have not recorded any probable recoveries from third parties. The environmental reserve includes sites at different stages of discovery and remediation and does not include any unasserted claims.

It is possible that new information or future developments could require a reassessment of the potential exposure to related environmental matters. As this information becomes available, management will continue to assess the potential exposure and adjust the reserves accordingly.

As of December 31, 2011 and 2010, the number of environmental sites and reserves related to these sites for which remediation or long-term monitoring, preliminary site work or site assessment are being performed, as well as the portion related to MGP sites are as follows:

	As of December 31, 2011						As of December 31, 2010
	Number of Sites		Reserve (in  millions)		Portion Related to MGP Sites (in millions)		Number of Sites		Reserve (in millions)		Portion Related to MGP Sites (in millions)
NU		59	$	31.7	$	28.9		58	$	37.1	$	35.2
CL&P		18		2.9		1.5		17		2.8		1.5
PSNH		18		6.6		5.8		18		9.1		8.3
WMECO		10		0.3		0.1		9		0.3		0.1

MGP sites are sites that were operated several decades ago and produced manufacturing gas from coal, which resulted in certain byproducts in the environment that may pose a risk to human health and the environment.

As of December 31, 2011, for 5 environmental sites (2 for PSNH and 1 for WMECO) that are included in the Company’s reserve for environmental costs, the information known and nature of the remediation options at those sites allow for the Company to estimate the range of losses for environmental costs. As of December 31, 2011, $4.9 million ($0.7 million for PSNH) had been accrued as a liability for these sites, which represent management’s best estimates of the liabilities for environmental costs. These amounts are the best estimates within estimated ranges of losses from $1.3 million to $16.8 million (zero to $4.1 million for PSNH and zero to $8.6 million for WMECO). For the sites that comprise the remaining $26.8 million of the environmental reserve ($2.9 million for CL&P, $5.9 million for PSNH and $0.3 million for WMECO), determining an estimated range of loss is not possible at this time.

As of December 31, 2011, in addition to the sites identified above, there were 12 sites (7 for CL&P, 2 for PSNH and 2 for WMECO) for which there are unasserted claims; however, any related site assessment or remediation costs are not probable or estimable at this time.

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HWP: HWP, a subsidiary of NU, continues to investigate the potential need for additional remediation at a river site in Massachusetts containing tar deposits associated with an MGP site that HWP sold to HG&E, a municipal utility, in 1902. HWP shares responsibility for site remediation with HG&E and has conducted substantial investigative and remediation activities. The cumulative expense recorded to the reserve for this site since 1994 through December 31, 2011 was $19.5 million, of which $17.1 million had been spent, leaving $2.4 million in the reserve as of December 31, 2011. For the year ended December 31, 2011, there was no charge recorded to the reserve and for the years ended December 31, 2010 and 2009, pre-tax charges of $2.6 million and $1.1 million, respectively, were recorded to reflect estimated costs associated with the site. HWP’s share of the costs related to this site is not recoverable from customers.

In 2008, the MA DEP issued a letter to HWP and HG&E, representing guidance rather than a mandate, providing conditional authorization for additional investigatory and risk characterization activities and indicating that further removal of tar in certain areas was needed. HWP implemented several supplemental studies to further delineate and assess tar deposits in conformity with the MA DEP’s guidance letter.

In 2010, HWP delivered a report to the MA DEP describing the results of its site investigation studies and testing. Subsequent communications and discussions with the MA DEP have focused on the course of action to achieve resolution of these matters, and are ongoing.

The $2.4 million reserve balance as of December 31, 2011 represents estimated costs that HWP considers probable over the remaining life of the project, including testing and related costs in the near term and field activities to be agreed upon with the MA DEP, further studies and long-term monitoring that are expected to be required by the MA DEP, and certain soft tar remediation activities. Various factors could affect management’s estimates and require an increase to the reserve, which would be reflected as a charge to Net Income. Although a material increase to the reserve is not presently anticipated, management cannot reasonably estimate potential additional investigation or remediation costs because these costs would depend on, among other things, the nature, extent and timing of additional investigation and remediation that may be required by the MA DEP.

CERCLA: CERCLA and its amendments or state equivalents impose joint and several strict liabilities, regardless of fault, upon generators of hazardous substances resulting in removal and remediation costs and environmental damages. Liabilities under these laws can be material and in some instances may be imposed without regard to fault or for past acts that may have been lawful at the time they occurred. Of the total sites included in the remediation and long-term monitoring phase, 6 sites (4 for PSNH, 2 for CL&P and 1 for WMECO) are superfund sites under CERCLA for which the Company has been notified that it is a potentially responsible party but for which the site assessment and remediation are not being managed by the Company. As of December 31, 2011, a liability of $0.7 million ($0.3 million for CL&P and $0.4 million for PSNH) accrued on these sites represents management’s best estimate of its potential remediation costs with respect to these superfund sites.

Environmental Rate Recovery: PSNH and Yankee Gas have rate recovery mechanisms for environmental costs. CL&P recovers a certain level of environmental costs currently in rates but does not have an environmental cost recovery tracking mechanism. Accordingly, changes in CL&P’s environmental reserves impact CL&P’s Net Income. WMECO does not have a separate regulatory mechanism to recover environmental costs from its customers, and changes in WMECO’s environmental reserves impact WMECO’s Net Income.

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B. Long-Term Contractual Arrangements

Estimated Future Annual Costs: The estimated future annual costs of significant long-term contractual arrangements as of December 31, 2011 are as follows:

NU
(Millions of Dollars)	2012		2013		2014		2015		2016		Thereafter		Totals
Supply/Stranded Cost Contracts/Obligations	$	260.9	$	239.5	$	193.6	$	174.8	$	179.0	$	649.4	$	1,697.2
Renewable Energy Contracts		11.4		60.0		175.6		177.9		189.1		2,955.8		3,569.8
Peaker CfDs		70.5		78.2		76.1		72.1		72.1		360.2		729.2
Natural Gas Procurement Contracts		68.1		55.6		52.0		36.8		31.7		73.3		317.5
Coal, Wood and Other Contracts		135.1		33.6		21.0		2.4		1.9		19.3		213.3
PNGTS Pipeline Commitments		3.1		3.1		3.1		3.1		3.1		6.7		22.2
Transmission Support Commitments		21.3		20.2		18.8		18.6		16.1		64.4		159.4
Yankee Companies Billings		27.3		27.8		27.2		22.4		—		—		104.7
Select Energy Purchase Agreements		15.8		18.2		—		—		—		—		34.0
Totals	$	613.5	$	536.2	$	567.4	$	508.1	$	493.0	$	4,129.1	$	6,847.3
CL&P
(Millions of Dollars)	2012		2013		2014		2015		2016		Thereafter		Totals
Supply/Stranded Cost Contracts/Obligations	$	175.3	$	169.4	$	150.0	$	145.6	$	159.6	$	595.3	$	1,395.2
Renewable Energy Contracts		5.9		45.8		106.6		107.9		108.6		1,584.7		1,959.5
Peaker CfDs		70.5		78.2		76.1		72.1		72.1		360.2		729.2
Transmission Support Commitments		12.2		11.5		10.8		10.7		9.2		36.9		91.3
Yankee Companies Billings		18.7		19.1		18.7		15.8		—		—		72.3
Totals	$	282.6	$	324.0	$	362.2	$	352.1	$	349.5	$	2,577.1	$	4,247.5
PSNH
(Millions of Dollars)	2012		2013		2014		2015		2016		Thereafter		Totals
Supply/Stranded Cost Contracts/Obligations	$	85.6	$	70.1	$	43.6	$	29.2	$	19.4	$	54.1	$	302.0
Renewable Energy Contracts		5.1		5.1		59.8		60.7		70.9		1,263.3		1,464.9
Coal, Wood and Other Contracts		135.1		33.6		21.0		2.4		1.9		19.3		213.3
PNGTS Pipeline Commitments		3.1		3.1		3.1		3.1		3.1		6.7		22.2
Transmission Support Commitments		6.6		6.3		5.8		5.7		5.0		19.8		49.2
Yankee Companies Billings		3.4		3.5		3.3		2.3		—		—		12.5
Totals	$	238.9	$	121.7	$	136.6	$	103.4	$	100.3	$	1,363.2	$	2,064.1
WMECO
(Millions of Dollars)	2012		2013		2014		2015		2016		Thereafter		Totals
Renewable Energy Contracts	$	0.4	$	9.1	$	9.2	$	9.3	$	9.6	$	107.8	$	145.4
Transmission Support Commitments		2.5		2.4		2.2		2.2		1.9		7.7		18.9
Yankee Companies Billings		5.2		5.2		5.2		4.3		—		—		19.9
Totals	$	8.1	$	16.7	$	16.6	$	15.8	$	11.5	$	115.5	$	184.2

Supply/Stranded Cost Contracts/Obligations: CL&P, PSNH and WMECO have various IPP contracts or purchase obligations for electricity, including payment obligations resulting from the buydown of electricity purchase contracts. Excluding renewable and CfD contracts, which are discussed below, such contracts extend through 2024 for CL&P. At PSNH such contracts extend through 2023. The total cost of purchases and obligations under these contracts/obligations amounted to $132.2 million ($91.1 million for CL&P, $40.8 million for PSNH, and $0.3 million for WMECO) in 2011, $196.2 million ($151.3 million for CL&P, $42.6 million for PSNH, and $2.3 million for WMECO) in 2010, and $205.3 million ($173.1 million for CL&P, $29.8 million for PSNH, and $2.4 million for WMECO) in 2009.

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In addition, CL&P and UI have entered into four CfDs for a total of approximately 787 MW of capacity with three generation projects being built or modified 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 projects 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 share 20 percent 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. The information in the table above includes 100 percent of the payments projected as of December 31, 2011 under the contracts entered into by CL&P and 80 percent of the payments projected under the contracts entered into by UI. 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. The total cost incurred from these contracts amounted to $23.8 million in 2011.

The contractual obligations table does not include contractual commitments related to CL&P’s SS or LRS or WMECO’s default service, both of which represent contractual commitments that are conditional upon CL&P and WMECO customers’ use of energy, and PSNH’s short-term power supply management.

Renewable Energy Contracts: CL&P has entered into various agreements to purchase energy, capacity and renewable energy credits from renewable energy facilities. Amounts payable under these contracts are subject to a sharing agreement with UI, whereby UI will share approximately 20 percent of the costs and benefits of these contracts. In addition, UI has entered into contracts that are subject to this cost sharing agreement under which CL&P will share in approximately 80 percent of the costs and benefits of the contract. The information in the table above includes 100 percent of the payments projected under the contracts entered into by CL&P and 80 percent of the payments projected under the contracts entered into by UI. CL&P’s portion of the costs and benefits of these contracts will be paid by or refunded to CL&P’s customers. CL&P’s renewable energy contracts have terms ranging between 15 and 20 years. PSNH has supply contracts for the purchase of electricity from renewable suppliers, which extend through 2033. WMECO’s contract to purchase electricity from a renewable supplier has a term of 15 years.

Peaker CfDs: In 2008, CL&P entered into three CfDs with developers of peaking generation units approved by the PURA (Peaker CfDs). These units will 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 information in the table above includes 100 percent of the estimated payments projected under the contracts, before reimbursement from UI under the sharing agreement. The ultimate cost or benefit to CL&P under these contracts will depend on the costs of plant construction and 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. The total cost incurred from these contracts amounted to $40.2 million in 2011 and $10 million in 2010.

Natural Gas Procurement Contracts: Yankee Gas has entered into long-term contracts for the purchase of natural gas in the normal course of business as part of its portfolio of supplies. These contracts extend through 2022. The total cost of Yankee Gas’ procurement portfolio, including these contracts, amounted to $191.7 million in 2011, $209.5 million in 2010 and $236.3 million in 2009.

Coal, Wood and Other Contracts: PSNH has entered into various arrangements for the purchase of wood, coal and the transportation services for fuel supply for its electric generating assets. PSNH’s fuel and natural gas costs, excluding emissions allowances, amounted to approximately $110.5 million in 2011, $168.3 million in 2010 and $156.7 million in 2009.

PNGTS Pipeline Commitments: PSNH has a contract for capacity on the Portland Natural Gas Transmission System (PNGTS) pipeline that extends through 2019. The cost under this contract amounted to $2.7 million in 2011, $2.8 million in 2010 and $1.6 million in 2009. These costs are not recovered from PSNH’s customers.

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Transmission Support Commitments: Along with other New England utilities, CL&P, PSNH and WMECO entered into agreements in 1985 to support transmission and terminal facilities that were built to import electricity from the Hydro-Québec system in Canada. CL&P, PSNH and WMECO are obligated to pay, over a 30-year period ending in 2020, their proportionate shares of the annual operation and maintenance expenses and capital costs of those facilities. CL&P, PSNH and WMECO’s total cost of these agreements amounted to $10.3 million, $5.6 million and $2.2 million, respectively, in 2011, $10.8 million, $5.8 million and $2.3 million, respectively, in 2010, and $10.7 million, $5.7 million and $2.2 million, respectively, in 2009 ($18.1 million in 2011, $18.9 million in 2010 and $18.6 million in 2009 in the aggregate for NU).

Yankee Companies Billings: CL&P, PSNH and WMECO have significant decommissioning and plant closure cost obligations to the Yankee Companies, which have each completed the physical decommissioning of their respective nuclear facilities and are now engaged in the long-term storage of their spent fuel. The Yankee Companies collect decommissioning and closure costs through wholesale, FERC-approved rates charged under power purchase agreements with several New England utilities, including CL&P, PSNH and WMECO. These companies in turn recover these costs from their customers through state regulatory commission-approved retail rates. CL&P’s, PSNH’s and WMECO’s total cost of these billings amounted to $18.3 million, $3.3 million and $5 million, respectively, in 2011, $22.7 million, $4.1 million and $6.2 million, respectively, in 2010, and $18.2 million, $3.7 million and $5 million, respectively, in 2009 ($26.6 million in 2011, $33 million in 2010 and $26.9 million in 2009 in the aggregate for NU).

See Note 12C, “Commitments and Contingencies — Deferred Contractual Obligations,” to the consolidated financial statements for information regarding the collection of the Yankee Companies’ decommissioning costs.

Select Energy Purchase Agreements: Select Energy maintains long-term agreements to purchase energy to meet its actual or expected sales commitments. Most purchase commitments are recorded at their mark-to-market values with the exception of one nonderivative contract, which is accounted for on the accrual basis.

C. Deferred Contractual Obligations

CL&P, PSNH and WMECO have decommissioning and plant closure cost obligations to the Yankee Companies, which have each completed the physical decommissioning of their respective nuclear facilities and are now engaged in the long-term storage of their spent fuel. The Yankee Companies collect decommissioning and closure costs through wholesale, FERC-approved rates charged under power purchase agreements with several New England utilities, including CL&P, PSNH and WMECO. These companies in turn recover these costs from their customers through state regulatory commission-approved retail rates.

CL&P, PSNH and WMECO’s percentage share of the obligations to support the Yankee Companies under FERC-approved rate tariffs is the same as their respective ownership percentages in the Yankee Companies. For further information on the ownership percentages, see Note 1K, “Summary of Significant Accounting Policies — Equity Method Investments,” to the consolidated financial statements.

The Yankee Companies are currently collecting amounts that management believes are adequate to recover the remaining decommissioning and closure cost estimates for the respective plants. Management believes CL&P and WMECO will recover their shares of these decommissioning and closure obligations from their customers. PSNH has already recovered its share of these costs from its customers.

Spent Nuclear Fuel Litigation: In 1998, CYAPC, YAEC and MYAPC (Yankee companies) filed separate complaints against the DOE in the Court of Federal Claims seeking monetary damages resulting from the DOE’s failure to begin accepting spent nuclear fuel for disposal by January 31, 1998 pursuant to the terms of the 1983 spent fuel and high level waste disposal contracts between the Yankee Companies and the DOE. In a ruling released on October 4, 2006, the Court of Federal Claims held that the DOE was liable for damages to CYAPC for $34.2 million through 2001, YAEC for $32.9 million through 2001 and MYAPC for $75.8 million through 2002.

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In December 2006, the DOE appealed the ruling, and the Yankee Companies filed cross-appeals. The Court of Appeals issued its decision on August 7, 2008, effectively agreeing with the trial court’s findings as to the liability of the DOE but disagreeing with the method that the trial court used to calculate damages. The Court of Appeals vacated the decision and remanded the case for new findings consistent with its decision.

On September 7, 2010, the trial court issued its decision following remand, and judgment on the decision was entered on September 9, 2010. The judgment awarded CYAPC $39.7 million, YAEC $21.2 million and MYAPC $81.7 million. The DOE filed an appeal and the Yankee Companies cross-appealed on November 8, 2010. Briefs were filed and oral arguments in the appeal of the remanded case occurred on November 7, 2011. If the Court follows its previous schedule, a decision could be handed down within six months of the argument (second quarter 2012). Interest on the judgments does not start to accrue until all appeals have been decided and/or all appeal periods have expired without appeals being filed. The application of any damages, which are ultimately recovered to benefit customers, is established in the Yankee Companies’ FERC-approved rate settlement agreements, although implementation will be subject to the final determination of the FERC.

In December 2007, the Yankee Companies each filed subsequent lawsuits against the DOE seeking recovery of actual damages incurred in the years following 2001 and 2002. On November 18, 2011, the court ordered the record closed in the YAEC case, and closed the record in the CYAPC and MYAPC cases subject to a limited opportunity of the government to reopen the records for further limited proceedings. The parties’ post-trial briefs will be filed during the first quarter of 2012 with a decision to come thereafter.

The refund to CL&P, PSNH and WMECO of any damages that may be recovered from the DOE will be realized through the Yankee Companies’ FERC-approved rate settlement agreements, subject to final determination of the FERC. CL&P, PSNH and WMECO cannot at this time determine the timing or amount of any ultimate recovery the Yankee Companies may obtain from the DOE on this matter. However, NU believes that any net settlement proceeds it receives would be incorporated into FERC-approved recoveries, which would be passed on to its customers through reduced charges.

D. Guarantees and Indemnifications

NU parent provides credit assurances on behalf of its subsidiaries, including CL&P, PSNH and WMECO, in the form of guarantees and LOCs in the normal course of business.

NU provided guarantees and various indemnifications on behalf of external parties as a result of the sales of former subsidiaries of NU Enterprises, with maximum exposures either not specified or not material.

NU also issued a guaranty for the benefit of Hydro Renewable Energy under which, beginning at the time the Northern Pass Transmission line goes into commercial operation, NU will guarantee the financial obligations of NPT under the TSA in an amount not to exceed $18.8 million. NU’s obligations under the guaranty expire upon the full, final and indefeasible payment of the guaranteed obligations.

Management does not anticipate a material impact to Net Income to result from these various guarantees and indemnifications.

The following table summarizes NU’s guarantees of its subsidiaries, including CL&P, PSNH and WMECO, as of December 31, 2011:

Subsidiary	Description	Maximum Exposure (in millions)			Expiration Dates
Various	Surety Bonds and Performance Guarantees	$	23.6		2012-2013 (1)
CL&P, PSNH and Select Energy	Letters of Credit	$	17.9		March 2012 - December 2012
NUSCO and RRR	Lease Payments for Vehicles and Real Estate	$	22.5		2019 and 2024
NU Enterprises	Surety Bonds, Insurance Bonds and Performance Guarantees	$	92.1	(2)	(2)

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(1) Surety bond expiration dates reflect bond termination dates, the majority of which will be renewed or extended.

(2) The maximum exposure includes $23.5 million related to performance guarantees on wholesale purchase contracts, which expire in 2013, assuming purchase contracts guaranteed have no value; however, actual exposures vary with underlying commodity prices. The maximum exposure also includes $15.7 million related to a performance guarantee for which no maximum exposure is specified in the agreement. The maximum exposure was calculated as of December 31, 2011 based on limits of the liability contained in the underlying service contract and assumes that NU Enterprises will perform under that contract through its expiration in 2020. Also included in the maximum exposure is $1.2 million related to insurance bonds with no expiration date that are billed annually on their anniversary date. The remaining $51.7 million of maximum exposure relates to surety bonds covering ongoing projects, which expire upon project completion.

CL&P, PSNH and WMECO do not guarantee the performance of third parties.

Many of the underlying contracts that NU parent guarantees, as well as certain surety bonds, contain credit ratings triggers that would require NU parent to post collateral in the event that the unsecured debt credit ratings of NU are downgraded below investment grade.

E. Exposure Regarding Complaint on FERC Base ROE

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 New England transmission owners, including CL&P, PSNH and WMECO, is unjust and unreasonable. The complainants asserted that the current 11.14 percent rate, which became effective in 2006, is excessive due to changes in the capital markets and are seeking an order to reduce the rate to 9.2 percent, effective September 30, 2011.

On October 20, 2011, the New England transmission owners responded to the complaint, asking FERC to dismiss the complaint on the basis that the complainants failed to carry their burden of proof under Section 206 of the Federal Power Act to demonstrate that the existing base ROE is unjust and unreasonable. The New England transmission owners included testimony and analysis reflecting a base ROE of 11.2 percent using FERC’s methodology and precedents, which they believe demonstrates that the current base ROE of 11.14 percent remains just and reasonable.

Although additional testimony was submitted by the complainants and the New England transmission owners in November and December 2011, the FERC has not yet issued an order in this proceeding and management cannot predict when this proceeding will be concluded, the outcome of this proceeding, or its impact on CL&P, PSNH, or WMECO’s financial position, results of operations or cash flows.

F. Litigation and Legal Proceedings

NU, including CL&P, PSNH and WMECO, are involved in legal, tax and regulatory proceedings regarding matters arising in the ordinary course of business, which involve management’s assessment to determine the probability of whether a loss will occur and, if probable, its best estimate of probable loss. The Company records and discloses losses when these losses are probable and reasonably estimable, discloses matters when losses are probable but not estimable or reasonably possible, and expenses legal costs related to the defense of loss contingencies as incurred.

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13. LEASES

Various NU subsidiaries, including CL&P, PSNH and WMECO, have entered into lease agreements, some of which are capital leases, for the use of data processing and office equipment, vehicles, and office space. In addition, CL&P, PSNH and WMECO incur costs associated with leases entered into by NUSCO and RRR. These costs are included below in CL&P, PSNH and WMECO’s operating lease payments charged to expense and amounts capitalized as well as future operating lease payments from 2012 through 2016 and thereafter. These amounts are eliminated on an NU consolidated basis. The provisions of these lease agreements generally contain renewal options. Certain lease agreements contain payments impacted by the commercial paper rate plus a credit spread or the consumer price index.

For the years ended December 31, 2011, 2010 and 2009, rental payments made on capital leases, interest included in capital lease payments, and capital lease asset amortization were as follows:

	Rental Payments						Interest						Asset Amortization
(Millions of Dollars)	NU		CL&P		PSNH		NU		CL&P		PSNH		NU		CL&P		PSNH
2011	$	2.7	$	2.0	$	0.6	$	1.7	$	1.5	$	0.2	$	1.0	$	0.5	$	0.4
2010		2.5		1.9		0.5		1.8		1.5		0.3		0.7		0.4		0.2
2009		2.6		1.9		0.5		1.9		1.6		0.3		0.6		0.3		0.2

For the years ended December 31, 2011, 2010 and 2009, operating lease rental payments charged to expense and the capitalized portion of operating lease payments were as follows:

	Expensed								Capitalized
(Millions of Dollars)	NU		CL&P		PSNH		WMECO		NU		CL&P		PSNH		WMECO
2011	$	8.4	$	8.3	$	2.1	$	2.8	$	1.4	$	0.8	$	0.1	$	0.1
2010		11.9		10.0		2.2		2.6		4.8		3.8		0.1		0.1
2009		18.1		12.8		3.9		3.4		9.7		6.1		1.5		1.1

Future minimum rental payments to external third parties excluding executory costs, such as property taxes, state use taxes, insurance, and maintenance, under long-term noncancelable leases, as of December 31, 2011 are as follows:

Capital Leases
(Millions of Dollars)	NU		CL&P		PSNH
2012	$	3.0	$	2.3	$	0.6
2013		2.6		2.1		0.5
2014		2.2		1.9		0.2
2015		2.2		1.9		0.2
2016		2.0		1.9		0.1
Thereafter		9.5		9.4		—
Future minimum lease payments		21.5		19.5		1.6
Less amount representing interest		9.1		8.8		0.3
Present value of future minimum lease payments	$	12.4	$	10.7	$	1.3

Operating Leases
(Millions of Dollars)	NU		CL&P		PSNH		WMECO
2012	$	7.7	$	3.2	$	1.2	$	2.6
2013		6.9		2.8		1.0		2.5
2014		4.9		2.6		0.8		0.9
2015		4.3		2.6		0.8		0.5
2016		4.3		2.6		0.8		0.4
Thereafter		16.6		12.0		2.3		1.3
Future minimum lease payments	$	44.7	$	25.8	$	6.9	$	8.2

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CL&P entered into certain contracts for the purchase of energy that qualify as leases. These contracts do not have minimum lease payments and therefore are not included in the tables above. However, such contracts have been included in the contractual obligations table in Note 12B, “Commitments and Contingencies — Long-Term Contractual Arrangements,” to the consolidated financial statements.

14. FAIR VALUE OF FINANCIAL INSTRUMENTS

The following methods and assumptions were used to estimate the fair value of each of the following financial instruments:

Preferred Stock, Long-Term Debt and Rate Reduction Bonds: The fair value of CL&P’s preferred stock is based upon pricing models that incorporate interest rates and other market factors, valuations or trades of similar securities and cash flow projections. The fair value of fixed-rate long-term debt securities and RRBs is based upon pricing models that incorporate quoted market prices for those issues or similar issues adjusted for market conditions, credit ratings of the respective companies and treasury benchmark yields. Adjustable rate securities are assumed to have a fair value equal to their carrying value. Carrying amounts and estimated fair values are as follows:

	As of December 31, 2011
	NU				CL&P				PSNH				WMECO
(Millions of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value
Preferred Stock Not Subject to Mandatory Redemption	$	116.2	$	105.1	$	116.2	$	105.1	$	—	$	—	$	—	$	—
Long-Term Debt		4,950.7		5,517.0		2,587.8		2,987.1		999.5		1,075.2		501.1		539.8
Rate Reduction Bonds		112.3		116.8		—		—		85.4		88.8		26.9		28.1

	As of December 31, 2010
	NU				CL&P				PSNH				WMECO
(Millions of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value
Preferred Stock Not Subject to Mandatory Redemption	$	116.2	$	93.7	$	116.2	$	93.7	$	—	$	—	$	—	$	—
Long-Term Debt		4,692.4		5,043.8		2,587.5		2,816.7		837.3		871.4		401.0		417.0
Rate Reduction Bonds		181.6		193.3		—		—		138.2		146.9		43.3		46.4

Derivative Instruments: NU, including CL&P, PSNH and WMECO, holds various derivative instruments that are carried at fair value. For further information, see Note 4, “Derivative Instruments,” to the consolidated financial statements.

Other Financial Instruments: Investments in marketable securities are carried at fair value on the accompanying consolidated balance sheets. For further information, see Note 1I, “Summary of Significant Accounting Policies — Fair Value Measurements,” and Note 5, “Marketable Securities,” to the consolidated financial statements.

The carrying value of other financial instruments included in current assets and current liabilities, including cash and cash equivalents and special deposits, approximates their fair value due to the short-term nature of these instruments.

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15. PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION (CL&P)

CL&P’s charter authorizes it to issue up to 9 million shares of preferred stock ($50 par value per share) of which 2,324,000 shares were outstanding as of December 31, 2011 and 2010. CL&P amended its charter on January 3, 2012 to remove references to various series of preferred stock, including the Class A preferred stock, which are no longer outstanding. There were no Class A preferred shares outstanding as of December 31, 2011 and 2010. The issuance of additional preferred shares would be subject to approval by the PURA.

Preferred stockholders have liquidation rights equal to the par value of the preferred stock, which they would receive in preference to any distributions to any junior stock. Were there to be a shortfall, all preferred stockholders would share ratably in available liquidation assets. Details of preferred stock not subject to mandatory redemption are as follows (in millions except in redemption price and shares):

Description		December 31, 2011 Redemption Price		Shares Outstanding as of December 31, 2011 and  2010		As of December 31,
						2011		2010
$  1.90	Series of 1947	$	52.50		163,912	$	8.2	$	8.2
$  2.00	Series of 1947	$	54.00		336,088		16.8		16.8
$  2.04	Series of 1949	$	52.00		100,000		5.0		5.0
$  2.20	Series of 1949	$	52.50		200,000		10.0		10.0
3.90 %	Series of 1949	$	50.50		160,000		8.0		8.0
$  2.06	Series E of 1954	$	51.00		200,000		10.0		10.0
$  2.09	Series F of 1955	$	51.00		100,000		5.0		5.0
4.50 %	Series of 1956	$	50.75		104,000		5.2		5.2
4.96 %	Series of 1958	$	50.50		100,000		5.0		5.0
4.50 %	Series of 1963	$	50.50		160,000		8.0		8.0
5.28 %	Series of 1967	$	51.43		200,000		10.0		10.0
$  3.24	Series G of 1968	$	51.84		300,000		15.0		15.0
6.56 %	Series of 1968	$	51.44		200,000		10.0		10.0
Totals					2,324,000	$	116.2	$	116.2

Dividends totaling $5.6 million for 2011, $6.1 million for 2010 and $5.6 million for 2009 were declared and dividends of $5.6 million were paid to the preferred stockholders in 2011, 2010 and 2009.

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16. ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)

The accumulated balance for each component of other comprehensive income/(loss), net of tax, is as follows:

(Millions of Dollars)	As of December 31,
NU	2011			2010
Qualified Cash Flow Hedging Instruments	$	(18.4	)	$	(4.2	)
Unrealized Gains on Other Securities		1.1			0.6
Pension, SERP and PBOP Benefits		(53.4	)		(39.8	)
Accumulated Other Comprehensive Loss	$	(70.7	)	$	(43.4	)
CL&P
Qualified Cash Flow Hedging Instruments	$	(2.3	)	$	(2.7	)
Unrealized Gains on Other Securities		—			—
Accumulated Other Comprehensive Loss	$	(2.3	)	$	(2.7	)
PSNH
Qualified Cash Flow Hedging Instruments	$	(10.9	)	$	(0.6	)
Unrealized Gains on Other Securities		0.1			—
Accumulated Other Comprehensive Loss	$	(10.8	)	$	(0.6	)
WMECO
Qualified Cash Flow Hedging Instruments	$	(4.2	)	$	(0.1	)
Unrealized Gains on Other Securities		—			—
Accumulated Other Comprehensive Loss	$	(4.2	)	$	(0.1	)

Qualified cash flow hedging items impacting Net Income in the tables above represent amounts that were reclassified from Accumulated Other Comprehensive Income/(Loss) into Net Income for interest rate swap agreements. For the year ended December 31, 2011 amounts were as follows:

	For the Year Ended December 31, 2011
(Millions of Dollars)	NU			PSNH			WMECO
Balance as of January 1, 2011	$	(4.2	)	$	(0.6	)	$	(0.1	)
Hedged Transactions Recognized into Earnings		0.7			0.5			0.1
Cash Flow Hedging Transactions Entered into for the Year		(14.9	)		(10.8	)		(4.2	)
Net Change Associated with Hedging Transactions		(14.2	)		(10.3	)		(4.1	)
Total Fair Value Adjustments Included in Accumulated
Other Comprehensive Loss	$	(18.4	)	$	(10.9	)	$	(4.2	)

For further information regarding cash flow hedging transactions, see Note 4, “Derivative Instruments,” to the consolidated financial statements.

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The changes in the components of other comprehensive income/(loss) are reported net of the following income tax effects:

(Millions of Dollars)
NU	2011			2010			2009
Qualified Cash Flow Hedging Instruments	$	9.5		$	(0.2	)	$	(0.2	)
Change in Unrealized Gains/(Losses) on Other Securities		(0.4	)		(0.2	)		0.7
Pension, SERP and PBOP Benefits		7.9			—			2.9
Total	$	17.0		$	(0.4	)	$	3.4
CL&P
Qualified Cash Flow Hedging Instruments	$	(0.3	)	$	(0.3	)	$	(0.3	)
PSNH
Qualified Cash Flow Hedging Instruments	$	7.0		$	(0.1	)	$	—
WMECO
Qualified Cash Flow Hedging Instruments	$	2.7		$	—		$	0.1

It is estimated that a charge of $2.2 million will be reclassified from Accumulated Other Comprehensive Income/(Loss) as a decrease to earnings over the next 12 months as a result of amortization of the interest rate swap agreements, which have been settled. Included in this amount are estimated charges of $0.4 million, $1.2 million and $0.3 million for CL&P, PSNH and WMECO, respectively. As of December 31, 2011, it is estimated that a pre-tax amount of $8.7 million included in the Accumulated Other Comprehensive Income/(Loss) balance will be reclassified as a decrease to Net Income over the next 12 months related to Pension, SERP and PBOP adjustments for NU.

17. DIVIDEND RESTRICTIONS

NU parent’s ability to pay dividends may be affected by certain state statutes, the ability of its subsidiaries to pay common dividends and the leverage restriction tied to its consolidated total debt to total capitalization ratio requirement in its revolving credit agreement.

CL&P, PSNH and WMECO are subject to Section 305 of the Federal Power Act that makes it unlawful for a public utility to make or pay a dividend from any funds “properly included in its capital account.” Management believes that this Federal Power Act restriction, as applied to CL&P, PSNH and WMECO, would not be construed or applied by the FERC to prohibit the payment of dividends for lawful and legitimate business purposes from retained earnings. In addition, certain state statutes may impose additional limitations on such companies and on Yankee Gas. Such state law restrictions do not restrict payment of dividends from retained earnings or net income. CL&P, PSNH, WMECO and Yankee Gas also have a revolving credit agreement that imposes leverage restrictions including consolidated total debt to total capitalization ratio requirements. The Retained Earnings balances subject to these leverage restrictions are $1.652 billion for NU, $735.9 million for CL&P, $388.9 million for PSNH and $115.5 million for WMECO as of December 31, 2011. PSNH is further required to reserve an additional amount under its FERC hydroelectric license conditions. As of December 31, 2011, approximately $11.9 million of PSNH’s Retained Earnings is subject to restriction under its FERC hydroelectric license conditions. As of December 31, 2011, NU, CL&P, PSNH, WMECO and Yankee Gas were in compliance with all such provisions of its credit agreement that may restrict the payment of dividends.

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18. COMMON SHARES

The following table sets forth the NU common shares and the shares of CL&P, PSNH and WMECO common stock authorized and issued as of December 31, 2011 and 2010 and the respective par values:

	Shares
	Authorized						Issued
	Per Share Par Value		As of December 31,				As of December 31,
			2011		2010		2011		2010
NU	$	5		380,000,000		225,000,000		196,052,770		195,781,740
CL&P	$	10		24,500,000		24,500,000		6,035,205		6,035,205
PSNH	$	1		100,000,000		100,000,000		301		301
WMECO	$	25		1,072,471		1,072,471		434,653		434,653

As of December 31, 2011 and 2010, 18,894,078 and 19,333,659 NU common shares were held as treasury shares, respectively.

On March 4, 2011, NU’s shareholders approved an increase in authorized shares from 225,000,000 to 380,000,000 in connection with the consummation of the NU-NSTAR pending merger.

19. COMMON SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTERESTS (NU)

A summary of the changes in Common Shareholders’ Equity and Noncontrolling Interests of NU is as follows:

	For the Year Ended December 31,
	2011
(Millions of Dollars)	Common Shareholders’ Equity			Noncontrolling Interest		Total Equity			Preferred Stock Not Subject to Mandatory Redemption
Balance, Beginning of Year	$	3,811.2		$	1.5	$	3,812.7		$	116.2
Net Income		400.5			—		400.5			—
Dividends on Common Shares		(195.6	)		—		(195.6	)		—
Dividends on Preferred Stock		(5.6	)		—		(5.6	)		(5.6	)
Issuance of Common Shares		5.9			—		5.9			—
Contributions to NPT		—			1.2		1.2			—
Other Transactions, Net		23.9			—		23.9			—
Net Income Attributable to Noncontrolling Interests		(0.3	)		0.3		—			5.6
Other Comprehensive Loss (Note 16)		(27.3	)		—		(27.3	)		—
Balance, End of Year	$	4,012.7		$	3.0	$	4,015.7		$	116.2

B-119

	For the Years Ended December 31,
	2010											2009
(Millions of Dollars)	Common Shareholders’ Equity			Noncontrolling Interest		Total Equity			Preferred Stock Not Subject to Mandatory Redemption			Total Equity			Preferred Stock Not Subject to Mandatory Redemption
Balance, Beginning of Year	$	3,577.9		$	—	$	3,577.9		$	116.2		$	3,020.3		$	116.2
Net Income		394.1			—		394.1			—			335.6			—
Dividends on Common Shares		(181.7	)		—		(181.7	)		—			(162.8	)		—
Dividends on Preferred Stock		(6.1	)		—		(6.1	)		(6.1	)		(5.6	)		(5.6	)
Issuance of Common Shares		7.4			—		7.4			—			389.7			—
Capital Stock Expenses, Net		(0.3	)		—		(0.3	)		—			(12.5	)		—
Contributions to NPT		—			1.4		1.4			—			—			—
Other Transactions, Net		19.9			—		19.9			—			18.7			—
Net Income Attributable to Noncontrolling Interests		(0.1	)		0.1		—			6.1			—			5.6
Other Comprehensive Income/(Loss) (Note 16)		0.1			—		0.1			—			(5.5	)		—
Balance, End of Year	$	3,811.2		$	1.5	$	3,812.7		$	116.2		$	3,577.9		$	116.2

For the years ended December 31, 2011, 2010, and 2009, there was no change in NU parent’s 100 percent ownership of the common equity of CL&P.

20. EARNINGS PER SHARE (NU)

EPS is computed based upon the monthly weighted average number of common shares outstanding, excluding unallocated ESOP shares, during each period. Diluted EPS is computed on the basis of the monthly weighted average number of common shares outstanding plus the potential dilutive effect if certain securities are converted into common shares. The computation of diluted EPS excludes the effect of the potential exercise of share awards when the average market price of the common shares is lower than the exercise price of the related awards during the period. These outstanding share awards are not included in the computation of diluted EPS because the effect would have been antidilutive. For the years ended December 31, 2011, 2010 and 2009, there were 4,314, 1,578 and 17,637 share awards, respectively, excluded from the computation as these awards were antidilutive.

The following table sets forth the components of basic and diluted EPS.

(Millions of Dollars, except share information)	2011		2010		2009
Net Income Attributable to Controlling Interests	$	394.7	$	387.9	$	330.0
Weighted Average Common Shares Outstanding:
Basic		177,410,167		176,636,086		172,567,928
Dilutive Effect		394,401		249,301		149,318
Diluted		177,804,568		176,885,387		172,717,246
Basic EPS	$	2.22	$	2.20	$	1.91
Diluted EPS	$	2.22	$	2.19	$	1.91

RSUs and performance shares are included in basic weighted average common shares outstanding as of the date that all necessary vesting conditions have been satisfied. The dilutive effect of unvested RSUs and performance shares is calculated using the treasury stock method. Assumed proceeds of the units under the treasury stock method consist of the remaining compensation cost to be recognized and a theoretical tax benefit. The theoretical tax benefit is calculated as the tax impact of the intrinsic value of the units (the difference between the market value of the average units outstanding for the period, using the average market price during the period, and the grant date market value).

B-120

The dilutive effect of stock options to purchase common shares is also calculated using the treasury stock method. Assumed proceeds for stock options consist of remaining compensation cost to be recognized, cash proceeds that would be received upon exercise, and a theoretical tax benefit. The theoretical tax benefit is calculated as the tax impact of the intrinsic value of the stock options (the difference between the market value of the average stock options outstanding for the period, using the average market price during the period, and the exercise price).

Allocated ESOP shares are included in basic common shares outstanding in the above table.

21. SEGMENT INFORMATION

Presentation: NU is organized between the Regulated companies’ segments and Other based on a combination of factors, including the characteristics of each business’ products and services, the sources of operating revenues and expenses and the regulatory environment in which each segment operates. Cash flows for total investments in plant included in the segment information below are cash capital expenditures that do not include amounts incurred but not paid, cost of removal, AFUDC related to equity funds, and the capitalized portions of pension and PBOP expense or income.

The Regulated companies’ segments include the electric distribution segment, the natural gas distribution segment and the electric transmission segment. The electric distribution segment includes the generation activities of PSNH and WMECO. The Regulated companies’ segments represented substantially all of NU’s total consolidated revenues for the years ended December 31, 2011, 2010 and 2009.

Other in the tables below primarily consists of 1) the results of NU parent, which includes other income related to the equity in earnings of NU parent’s subsidiaries and interest income from the NU Money Pool, which are both eliminated in consolidation, and interest income and expense related to the cash and debt of NU parent, respectively, 2) the revenues and expenses of NU’s service companies, most of which are eliminated in consolidation, and 3) the results of other subsidiaries, which are comprised of NU Enterprises, RRR (a real estate subsidiary), the non-energy-related subsidiaries of Yankee and the remaining operations of HWP.

Regulated companies’ revenues from the sale of electricity and natural gas primarily are derived from residential, commercial and industrial customers and are not dependent on any single customer.

B-121

NU’s segment information for the years ended December 31, 2011, 2010 and 2009, with the distribution segment segregated between electric and natural gas, is as follows:

	For the Year Ended December 31, 2011
	Regulated Companies
	Distribution
(Millions of Dollars)	Electric			Natural Gas			Transmission			Other			Eliminations			Total
Operating Revenues	$	3,343.1		$	430.8		$	635.4		$	541.3		$	(484.9	)	$	4,465.7
Depreciation and Amortization		(343.2	)		(27.7	)		(84.0	)		(16.8	)		2.5			(469.2	)
Other Operating Expenses		(2,631.4	)		(333.5	)		(188.2	)		(534.1	)		484.9			(3,202.3	)
Operating Income/(Loss)		368.5			69.6			363.2			(9.6	)		2.5			794.2
Interest Expense		(123.8	)		(21.0	)		(76.7	)		(33.7	)		4.8			(250.4	)
Interest Income		3.7			—			0.5			5.3			(5.3	)		4.2
Other Income, Net		11.6			1.3			10.7			455.2			(455.3	)		23.5
Income Tax (Expense)/Benefit		(67.6	)		(18.2	)		(95.6	)		14.3			(3.9	)		(171.0	)
Net Income		192.4			31.7			202.1			431.5			(457.2	)		400.5
Net Income Attributable to Noncontrolling Interests		(3.3	)		—			(2.5	)		—			—			(5.8	)
Net Income Attributable to Controlling Interests	$	189.1		$	31.7		$	199.6		$	431.5		$	(457.2	)	$	394.7
Total Assets (as of)	$	9,653.1		$	1,511.3		$	3,792.9		$	6,618.0		$	(5,928.2	)	$	15,647.1
Cash Flows Used for Investments in Plant	$	540.7		$	98.2		$	388.9		$	48.9		$	—		$	1,076.7

	For the Year Ended December 31, 2010
	Regulated Companies
	Distribution
(Millions of Dollars)	Electric			Natural Gas			Transmission			Other			Eliminations			Total
Operating Revenues	$	3,802.0		$	434.3		$	625.6		$	521.6		$	(485.3	)	$	4,898.2
Depreciation and Amortization		(506.7	)		(23.8	)		(86.7	)		(15.8	)		3.8			(629.2	)
Other Operating Expenses		(2,919.6	)		(340.0	)		(192.1	)		(505.4	)		488.0			(3,469.1	)
Operating Income		375.7			70.5			346.8			0.4			6.5			799.9
Interest Expense		(133.4	)		(17.9	)		(73.2	)		(17.4	)		4.6			(237.3	)
Interest Income		0.7			—			1.8			5.3			(6.3	)		1.5
Other Income, Net		24.4			0.8			14.3			436.4			(435.5	)		40.4
Income Tax (Expense)/Benefit		(90.3	)		(20.7	)		(109.3	)		11.0			(1.1	)		(210.4	)
Net Income		177.1			32.7			180.4			435.7			(431.8	)		394.1
Net Income Attributable to Noncontrolling Interests		(3.6	)		—			(2.6	)		—			—			(6.2	)
Net Income Attributable to Controlling Interests	$	173.5		$	32.7		$	177.8		$	435.7		$	(431.8	)	$	387.9
Total Assets (as of)	$	8,910.1		$	1,447.2		$	3,434.0		$	6,283.0		$	(5,601.7	)	$	14,472.6
Cash Flows Used for Investments in Plant	$	560.1		$	82.5		$	239.2		$	72.7		$	—		$	954.5

B-122

	For the Year Ended December 31, 2009
	Regulated Companies
	Distribution
(Millions of Dollars)	Electric			Natural Gas			Transmission			Other			Eliminations			Total
Operating Revenues	$	4,358.4		$	449.6		$	577.9		$	482.1		$	(428.6	)	$	5,439.4
Depreciation and Amortization		(431.5	)		(26.8	)		(71.0	)		(13.4	)		1.9			(540.8	)
Other Operating Expenses		(3,604.6	)		(368.1	)		(170.9	)		(435.9	)		432.3			(4,147.2	)
Operating Income		322.3			54.7			336.0			32.8			5.6			751.4
Interest Expense		(149.1	)		(22.1	)		(72.5	)		(36.2	)		6.3			(273.6	)
Interest Income		4.5			—			1.0			7.7			(7.6	)		5.6
Other Income, Net		24.0			0.3			7.6			371.6			(371.4	)		32.1
Income Tax (Expense)/Benefit		(60.2	)		(11.9	)		(105.5	)		0.1			(2.4	)		(179.9	)
Net Income		141.5			21.0			166.6			376.0			(369.5	)		335.6
Net Income Attributable to Noncontrolling Interests		(3.3	)		—			(2.3	)		—			—			(5.6	)
Net Income Attributable to Controlling Interests	$	138.2		$	21.0		$	164.3		$	376.0		$	(369.5	)	$	330.0
Cash Flows Used for Investments in Plant	$	521.5		$	54.8		$	286.0		$	—		$	45.8		$	908.1

The information related to the distribution and transmission segments for CL&P, PSNH and WMECO for the years ended December 31, 2011, 2010, and 2009 is included below.

	CL&P - For the Years Ended December 31,
	2011									2010									2009
(Millions of Dollars)	Distribution			Transmission			Total			Distribution			Transmission			Total			Distribution			Transmission			Total
Operating Revenues	$	2,065.3		$	483.1		$	2,548.4		$	2,500.3		$	498.8		$	2,999.1		$	2,954.6		$	469.9		$	3,424.5
Depreciation and Amortization		(158.7	)		(64.2	)		(222.9	)		(355.5	)		(67.6	)		(423.1	)		(330.3	)		(58.4	)		(388.7	)
Other Operating Expenses		(1,722.7	)		(139.6	)		(1,862.3	)		(1,942.4	)		(146.0	)		(2,088.4	)		(2,441.7	)		(129.0	)		(2,570.7	)
Operating Income		183.9			279.3			463.2			202.4			285.2			487.6			182.6			282.5			465.1
Interest Expense		(71.7	)		(61.0	)		(132.7	)		(77.6	)		(60.1	)		(137.7	)		(93.1	)		(62.7	)		(155.8	)
Interest Income		2.4			0.4			2.8			1.9			1.5			3.4			2.7			0.8			3.5
Other Income, Net		2.5			4.4			6.9			14.6			8.6			23.2			16.2			6.1			22.3
Income Tax Expense		(21.1	)		(68.9	)		(90.0	)		(43.6	)		(88.8	)		(132.4	)		(31.1	)		(87.7	)		(118.8	)
Net Income	$	96.0		$	154.2		$	250.2		$	97.7		$	146.4		$	244.1		$	77.3		$	139.0		$	216.3
Total Assets (as of)	$	6,161.0		$	2,630.4		$	8,791.4		$	5,640.0		$	2,615.2		$	8,255.2
Cash Flows Used for Investments in Plant	$	303.2		$	121.7		$	424.9		$	270.2		$	110.1		$	380.3		$	270.8		$	164.9		$	435.7

B-123

	PSNH - For the Years Ended December 31,
	2011									2010									2009
(Millions of Dollars)	Distribution			Transmission			Total			Distribution			Transmission			Total			Distribution			Transmission			Total
Operating Revenues	$	923.7		$	89.3		$	1,013.0		$	951.0		$	82.4		$	1,033.4		$	1,035.8		$	73.8		$	1,109.6
Depreciation and Amortization		(143.4	)		(11.5	)		(154.9	)		(118.4	)		(10.4	)		(128.8	)		(70.5	)		(9.3	)		(79.8	)
Other Operating Expenses		(644.4	)		(33.6	)		(678.0	)		(696.0	)		(32.4	)		(728.4	)		(865.8	)		(29.4	)		(895.2	)
Operating Income		135.9			44.2			180.1			136.6			39.6			176.2			99.5			35.1			134.6
Interest Expense		(36.2	)		(7.9	)		(44.1	)		(38.6	)		(8.5	)		(47.1	)		(39.8	)		(6.7	)		(46.5	)
Interest Income/(Loss)		0.9			0.1			1.0			(1.7	)		0.2			(1.5	)		2.1			0.1			2.2
Other Income, Net		11.2			2.0			13.2			11.6			1.7			13.3			6.0			1.3			7.3
Income Tax Expense		(35.6	)		(14.3	)		(49.9	)		(38.6	)		(12.2	)		(50.8	)		(20.2	)		(11.8	)		(32.0	)
Net Income	$	76.2		$	24.1		$	100.3		$	69.3		$	20.8		$	90.1		$	47.6		$	18.0		$	65.6
Total Assets (as of)	$	2,551.3		$	565.2		$	3,116.5		$	2,388.4		$	490.7		$	2,879.1
Cash Flows Used for Investments in Plant	$	189.0		$	52.8		$	241.8		$	252.2		$	44.1		$	296.3		$	207.8		$	58.6		$	266.4

	WMECO - For the Years Ended December 31,
	2011									2010									2009
(Millions of Dollars)	Distribution			Transmission			Total			Distribution			Transmission			Total			Distribution			Transmission			Total
Operating Revenues	$	354.4		$	62.9		$	417.3		$	350.9		$	44.3		$	395.2		$	368.2		$	34.2		$	402.4
Depreciation and Amortization		(41.1	)		(8.2	)		(49.3	)		(32.9	)		(8.6	)		(41.5	)		(30.8	)		(3.2	)		(34.0	)
Other Operating Expenses		(264.6	)		(15.0	)		(279.6	)		(281.3	)		(13.8	)		(295.1	)		(297.3	)		(12.5	)		(309.8	)
Operating Income		48.7			39.7			88.4			36.7			21.9			58.6			40.1			18.5			58.6
Interest Expense		(15.9	)		(7.7	)		(23.6	)		(17.1	)		(4.7	)		(21.8	)		(16.1	)		(3.2	)		(19.3	)
Interest Income/(Loss)		0.4			—			0.4			0.4			0.2			0.6			(0.3	)		—			(0.3	)
Other Income/(Loss), Net		(2.1	)		3.2			1.1			(1.8	)		3.8			2.0			1.8			0.3			2.1
Income Tax Expense		(10.9	)		(12.3	)		(23.2	)		(8.1	)		(8.2	)		(16.3	)		(8.8	)		(6.1	)		(14.9	)
Net Income	$	20.2		$	22.9		$	43.1		$	10.1		$	13.0		$	23.1		$	16.7		$	9.5		$	26.2
Total Assets (as of)	$	942.6		$	560.3		$	1,502.9		$	884.2		$	315.4		$	1,199.6
Cash Flows Used for Investments in Plant	$	48.5		$	189.5		$	238.0		$	37.6		$	77.6		$	115.2		$	42.9		$	62.5		$	105.4

22. VARIABLE INTEREST ENTITIES

The Company’s variable interests outside of the consolidated group are not material and consist of contracts that are required by regulation and provide for regulatory recovery of contract costs and benefits through customer rates. NU holds variable interests in variable interest entities (VIEs) through agreements with certain entities that own single renewable energy or peaking generation power plants and with other independent power producers. NU does not control the activities that are economically significant to these VIEs or provide financial or other support to these VIEs. Therefore, NU does not consolidate any power plant VIEs.

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23. QUARTERLY FINANCIAL DATA (UNAUDITED)

NU Consolidated Statements of Quarterly Financial Data	Quarter Ended (a)
(Millions of Dollars, except per share information)	March 31,		June 30,		September 30,		December 31,
2011
Operating Revenues	$	1,235.3	$	1,047.5	$	1,114.9	$	1,068.0
Operating Income		227.4		178.1		203.8		184.9
Net Income		115.6		78.7		91.4		114.8
Net Income Attributable to Controlling Interests		114.2		77.3		90.0		113.2
Basic and Diluted Earnings Per Common Share	$	0.64	$	0.44	$	0.51	$	0.64
2010
Operating Revenues	$	1,339.4	$	1,111.4	$	1,243.3	$	1,204.1
Operating Income		226.7		178.3		199.6		195.3
Net Income		87.6		73.3		101.9		131.3
Net Income Attributable to Controlling Interests		86.2		71.9		100.5		129.3
Basic and Diluted Earnings Per Common Share	$	0.49	$	0.41	$	0.57	$	0.73

(a) The summation of quarterly EPS data may not equal annual data due to rounding.

CL&P Consolidated Statements of Quarterly Financial Data	Quarter Ended
(Millions of Dollars)	March 31,		June 30,		September 30,		December 31,
2011
Operating Revenues	$	673.7	$	608.0	$	673.7	$	593.0
Operating Income		126.0		114.8		137.7		84.7
Net Income		64.3		52.6		66.5		66.8
2010
Operating Revenues	$	795.0	$	707.9	$	789.2	$	707.0
Operating Income		125.5		106.2		131.4		124.6
Net Income		48.4		44.1		69.0		82.6

PSNH Consolidated Statements of Quarterly Financial Data	Quarter Ended
(Millions of Dollars)	March 31,		June 30,		September 30,		December 31,
2011
Operating Revenues	$	269.5	$	240.2	$	259.6	$	243.7
Operating Income		46.9		37.9		48.5		46.8
Net Income		27.5		21.7		25.6		25.5
2010
Operating Revenues	$	258.6	$	238.3	$	277.0	$	259.5
Operating Income		39.9		43.4		49.8		43.1
Net Income		15.8		21.6		28.8		23.9

WMECO Consolidated Statements of Quarterly Financial Data	Quarter Ended
(Millions of Dollars)	March 31,		June 30,		September 30,			December 31,
2011
Operating Revenues	$	106.7	$	98.4	$	104.5		$	107.7
Operating Income		21.1		18.5		19.8			29.0
Net Income		10.0		8.2		8.4	(1)		16.5
2010
Operating Revenues	$	100.2	$	92.5	$	103.7		$	98.8
Operating Income		16.4		14.3		14.9			13.1
Net Income		5.7		5.2		7.3			4.9

(1) Distribution segment Net Income for the quarter ended September 30, 2011 decreased by $3.2 million, as compared to the quarter ended September 30, 2010, related to a pre-tax charge to establish a reserve of $5.3 million to reflect a wholesale billing adjustment, $4.3 million of which related to prior period amounts.

B-125

Selected Consolidated Financial Data (Unaudited)

(Thousands of Dollars, except percentages and common share information)	2011			2010			2009			2008			2007
Balance Sheet Data:
Property, Plant and Equipment, Net	$	10,403,065		$	9,567,726		$	8,839,965		$	8,207,876		$	7,229,945
Total Assets (f)		15,647,066			14,472,601			14,057,679			13,988,480			11,581,822
Total Capitalization (a)		9,078,321			8,627,985			8,253,323			7,293,960			6,667,920
Obligations Under Capital Leases (a)		12,358			12,236			12,873			13,397			14,743
Income Statement Data:
Operating Revenues	$	4,465,657		$	4,898,167		$	5,439,430		$	5,800,095		$	5,822,226
Income from Continuing Operations		400,513			394,107			335,592			266,387			251,455
Income from Discontinued Operations		—			—			—			—			587
Net Income Attributable to Noncontrolling Interests		5,820			6,158			5,559			5,559			5,559
Net Income Attributable to Controlling Interests	$	394,693		$	387,949		$	330,033		$	260,828		$	246,483
Common Share Data:
Basic Earnings Per Common Share:
Income from Continuing Operations	$	2.22		$	2.20		$	1.91		$	1.68		$	1.59
Income from Discontinued Operations		—			—			—			—			—
Net Income Attributable to Controlling Interests	$	2.22		$	2.20		$	1.91		$	1.68		$	1.59
Diluted Earnings Per Common Share:
Income from Continuing Operations	$	2.22		$	2.19		$	1.91		$	1.67		$	1.59
Income from Discontinued Operations		—			—			—			—			—
Net Income Attributable to Controlling Interests	$	2.22		$	2.19		$	1.91		$	1.67		$	1.59
Weighted Average Common Shares Outstanding
Basic		177,410,167			176,636,086			172,567,928			155,531,846			154,759,727
Diluted		177,804,568			176,885,387			172,717,246			155,999,240			155,304,361
Dividends Declared Per Share	$	1.10		$	1.03		$	0.95		$	0.83		$	0.78
Market Price — Closing (high) (b)	$	36.31		$	32.05		$	26.33		$	31.15		$	33.53
Market Price — Closing (low) (b)	$	30.46		$	24.78		$	19.45		$	19.15		$	26.93
Market Price — Closing (end of year) (b)	$	36.07		$	31.88		$	25.79		$	24.06		$	31.31
Book Value Per Share (end of year)	$	22.65		$	21.60		$	20.37		$	19.38		$	18.79
Tangible Book Value Per Share (end of year) (c)	$	21.03		$	19.97		$	18.74		$	17.54		$	16.93
Rate of Return Earned on Average Common Equity (%) (d)		10.1			10.7			10.2			8.8			8.6
Market-to-Book Ratio (end of year) (e)		1.6			1.5			1.3			1.2			1.7
Capitalization:
Total Equity		44	%		44	%		44	%		41	%		44	%
Preferred Stock, not subject to mandatory redemption		1			1			1			2			2
Long-Term Debt (a)		55			55			55			57			54
		100	%		100	%		100	%		100	%		100	%

(a) Includes portions due within one year, but excludes RRBs for Long-Term Debt.

(b) Market price information reflects closing prices as reflected by the New York Stock Exchange.

(c) Common Shareholders’ Equity adjusted for goodwill and intangibles divided by total common shares outstanding.

(d) Net Income divided by average Common Shareholders’ Equity.

(e) The closing market price divided by the book value per share.

(f) As of December 31, 2011, Total Assets has been adjusted to reflect the current portions of regulatory assets and liabilities, and related deferred tax amounts, as current assets and liabilities. Amounts as of December 31, 2010 have been reclassified to conform to the December 31, 2011 presentation.

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NORTHEAST UTILITIES TRUSTEES

Charles W. Shivery	Charles K. Gifford
Chairman of the Board,	Chairman Emeritus, Bank of
Northeast Utilities	America Corporation
Richard H. Booth	Paul A. La Camera
Vice Chairman, Guy Carpenter & Company, LLC,	Administrator of Public Radio, WBUR,
a subsidiary of Marsh & McClennan Companies, Inc.	National Public Radio Station in Boston
John S. Clarkeson	Kenneth R. Leibler
Chairman Emeritus, The Boston	Founding Partner and Former Chairman,
Consulting Group, Inc.	Boston Options Exchange
Cotton M. Cleveland	Thomas J. May
President, Mather Associates	President and Chief Executive Officer,
	Northeast Utilities
Sanford Cloud, Jr.*	William C. Van Faasen
Chairman and Chief Executive Officer,	Chairman of the Board, Blue Cross Blue Shield
The Cloud Company, LLC	of Massachusetts Inc.
James S. DiStasio	Frederica M. Williams
Retired Senior Vice Chairman and	President and Chief Executive Officer,
Americas Chief Operating Officer,	Whittier Street Health Center
Ernst & Young
Francis A. Doyle	Dennis R. Wraase
President and Chief Executive Officer,	Retired Chairman of the Board
Connell Limited Partnership	and Chief Executive Officer,
	Pepco Holdings, Inc.

* Lead Trustee

Biographical information for the Board of Trustees is set forth on pages 9 through 15 of the attached proxy statement.

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NORTHEAST UTILITIES EXECUTIVE OFFICERS

Thomas J. May, President and Chief Executive Officer. Age: 65. Mr. May has served as President and Chief Executive Officer and a Trustee of Northeast Utilities since the closing of the NSTAR merger in April, 2012. He has also served as the Chairman and a director of each of The Connecticut Light and Power Company, Public Service Company of New Hampshire, Western Massachusetts Electric Company and Yankee Gas Services Company since the closing of the Merger. Previously, Mr. May served as Chairman, President and Chief Executive Officer and a trustee of NSTAR until the closing of the merger. He served as Chairman, Chief Executive Officer and a trustee from the creation of NSTAR in 1999, was elected President in 2002 and has served as a director of NSTAR Electric Company and NSTAR Gas Company since 1999. Mr. May has served as a director of Bank of America Corporation since 2004 and a director of Liberty Mutual Holding Company, Inc. since 2002. He is Chair of the Board of Trustees of Stonehill College, is a member of the Executive Committee of the Board of Directors of the Boston Chamber of Commerce, is a member of the Board of Trustees of Dana Farber Cancer Institute and a Board member of the John F. Kennedy Library Foundation. Mr. May received a bachelor’s degree in business administration from Stonehill College and a M.S. in Finance from Bentley College. He is also a graduate of the Harvard Business School’s Advanced Management Program.

James J. Judge, Executive Vice President and Chief Financial Officer. Age: 56. Mr. Judge became Executive Vice President and Chief Financial Officer effective upon completion of the Merger. Previously, Mr. Judge served as Senior Vice President and Chief Financial Officer of NSTAR.

David R. McHale, Executive Vice President and Chief Administrative Officer. Age: 51. Mr. McHale became Executive Vice President and Chief Administrative Officer effective upon completion of the Merger. Previously, Mr. McHale served as Executive Vice President and Chief Financial Officer of Northeast Utilities, effective January 2009; Senior Vice President and Chief Financial Officer of Northeast Utilities from January 2005 to December 2008; and Vice President and Treasurer of Northeast Utilities from July 1998 to December 2004.

Leon J. Olivier, Executive Vice President and Chief Operating Officer. Age: 63. Mr. Olivier has been Executive Vice President and Chief Operating Officer of Northeast Utilities since May 2008. Prior to 2008, Mr. Olivier served as Executive Vice President — Operations of Northeast Utilities from February 2007 to May 2008; Executive Vice President of Northeast Utilities from December 2005 to February 2007, and President — Transmission Group of Northeast Utilities from January 2005 to December 2005.

Gregory B. Butler, Senior Vice President, General Counsel and Secretary. Age 54. Mr. Butler became Senior Vice President, General Counsel and Secretary effective upon completion of the Merger. Mr. Butler had been Senior Vice President and General Counsel of Northeast Utilities from December 2005 until the completion of the Merger. Previously, Mr. Butler served as Senior Vice President, Secretary and General Counsel of Northeast Utilities from August 2003 to December 2005 and Vice President, Secretary and General Counsel of Northeast Utilities from May 2001 through August 2003.

Christine M. Carmody, Senior Vice President of Human Resources, Northeast Utilities Service Company and NSTAR Electric & Gas Corporation. Age 49. Ms. Carmody became Senior Vice President of Human Resources effective upon completion of the Merger. Previously, Ms. Carmody served as Senior Vice President — Human Resources of NSTAR from August 2008 to April 2012, and as Vice President — Organizational Effectiveness of NSTAR from July 2006 to August 2008.

Joseph R. Nolan, Jr., Senior Vice President of Corporate Relations, Northeast Utilities Service Company and NSTAR Electric & Gas Corporation. Age 49. Mr. Nolan became Senior Vice President of Corporate Relations effective upon completion of the Merger. Previously, Mr. Nolan served as Senior Vice President — Customer & Corporate Relations of NSTAR.

Jay S. Buth, Vice President, Controller and Chief Accounting Officer. Age: 42. Mr. Buth became Vice President, Controller and Chief Accounting Officer effective upon completion of the Merger. Previously, he was Vice President — Accounting and Controller from 2009 to 2012. Mr. Buth served as Controller, and Vice President and Controller at NJR Service Corporation, a subsidiary of New Jersey Resources Corporation, a gas utility holding company, from June 2006 to January 2009.

B-128

SHAREHOLDER INFORMATION

Northeast Utilities

Northeast Utilities operates New England’s largest energy delivery system with approximately 3 million electric customers in Connecticut, Massachusetts and New Hampshire and approximately 500,000 natural gas customers in Connecticut and Massachusetts. Northeast Utilities is the parent company of several subsidiaries, including the following public utility companies: The Connecticut Light and Power Company, NSTAR Electric Company, NSTAR Gas Company, Public Service Company of New Hampshire, Western Massachusetts Electric Company and Yankee Gas Services Company.

Shareholders

As of September 4, 2012, there were 51,958 common shareholders of record of Northeast Utilities and a total of 313,842,387 common shares outstanding.

Transfer Agent and Registrar

Computershare Trust Company, N.A.

P.O. Box 43078

Providence, RI 02940-3078

1-800-999-7269

www.computershare.com/investor

Investor Relations

To contact our Investor Relations Department, please call:

Jeffrey Kotkin: 860-728-4650

Barbara Nieman: 860-728-4652

www.nu.com/investors

Shareholder Account Access

You can manage your account online via the Investor Centre website, Computershare’s web-based tool for shareholders at www.computershare.com/investor. Through free around-the-clock access to the Investor Centre website, you can view your account, access forms and request a variety of account transactions.

Dividend Reinvestment Plan

The Northeast Utilities Dividend Reinvestment and Share Purchase Plan provides a convenient and economical way for you to purchase our common shares and offers you the opportunity to reinvest cash dividends and purchase additional common shares with optional cash investments.

Computershare Trust Company, N.A. administers the Plan for participants, maintains records, sends statements of account to participants following the completion of any activity affecting the balance of an account and performs other duties relating to the Plan. You can contact Computershare by mail at Computershare Trust Company, N.A., Northeast Utilities Shareholder Services, P.O. Box 43078, Providence, RI 02940-3078, by phone at 800-999-7269 or on the Internet through its website at www.computershare.com.

Direct Deposit for Quarterly Dividends

Direct deposit provides the convenience of automatic and immediate access to your funds, while eliminating the possibility of mail delays and lost, stolen or destroyed checks. This service is free of charge to you. Please call 1-800-999-7269 to request an enrollment form.

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2012 Annual Meeting

The 2012 Annual Meeting of Shareholders of Northeast Utilities will be held on Wednesday, October 31, 2012, at 2:00 p.m., at the Sheraton Springfield Monarch Place Hotel, One Monarch Place, Springfield, Massachusetts 01144.

Compliance with New York Stock Exchange Corporate Governance Rules

The Company’s Annual Report on Form 10-K for 2011 contained the certifications required by Section 302 of the Sarbanes-Oxley Act of 2002, and on May 16, 2011, the Company’s Chief Executive Officer provided the New York Stock Exchange with the required annual written certification that he was not aware of any violations by the company of the Exchange’s corporate governance listing standards.

Form 10-K

Northeast Utilities will provide shareholders a copy of its 2011 Annual Report on Form 10-K, including the financial statements and schedules thereto, without charge, upon receipt of a written request sent to:

Richard J. Morrison

Assistant Secretary

Northeast Utilities

P.O. Box 270

Hartford, Connecticut 06141-0270

Receive Your Annual Report and Proxy Electronically

If you are interested in receiving your Annual Report and proxy materials electronically, you may log on to: www.computershare/investor.com any time throughout the year to do so. If you have questions, please call 1-800-999-7269.

B-130

	Electronic Voting Instructions Available 24 hours a day, 7 days a week! Instead of mailing your proxy, you may choose one of the voting methods outlined below to vote your proxy. VALIDATION DETAILS ARE LOCATED BELOW IN THE TITLE BAR. Proxies submitted by the Internet or telephone must be received by 11:59 p.m., Eastern Time, on October 30, 2012 (11:59 p.m., Eastern Time, October 28, 2012 for participants in either the Northeast Utilities Service Company 401K Plan or NSTAR Savings Plan).
		Vote by Internet •    Go to www.envisionreports.com/NU •    Or scan the QR code with your smartphone •    Follow the steps outlined on the secure website Vote by telephone •    Call toll free 1-800-652-VOTE (8683) within the USA, US territories & Canada on a touch tone telephone •    Follow the instructions provided by the recorded message

Using a black ink pen, mark your votes with an X as shown in this example. Please do not write outside the designated areas. x

q IF YOU HAVE NOT VOTED VIA THE INTERNET OR TELEPHONE, FOLD ALONG THE PERFORATION, DETACH AND RETURN THE BOTTOM PORTION IN THE ENCLOSED ENVELOPE. q

A Proposals — Management recommends a vote FOR all nominees and FOR Proposals 2, 3 and 4.

1. Election of Trustees: 01 - Richard H. Booth 04 - Sanford Cloud, Jr. 07 - Charles K. Gifford 10 - Thomas J. May 13 - Frederica M. Williams 02 - John S. Clarkeson 05 - James S. DiStasio 08 - Paul A. La Camera 11 - Charles W. Shivery 14 - Dennis R. Wraase 03- Cotton M. Cleveland 06 - Francis A. Doyle 09 - Kenneth R. Leibler 12 - William C. Van Faasen †

¨ Mark here to vote FOR all nominees ¨ Mark here to WITHHOLD vote from all nominees ¨ For All EXCEPT - To withhold authority to vote for any nominee(s), mark here and write the name(s) of such nominee(s) below.

	For	Against	Abstain
2.    To consider and approve the following advisory (non-binding) proposal: “RESOLVED, that the compensation paid to the Company’s named executive officers, as disclosed pursuant to the compensation disclosure rules of the Securities and Exchange Commission, including the compensation discussion and analysis, the compensation tables and any related material disclosed in this Proxy Statement, is hereby APPROVED.”	¨	¨	¨
3.    To re-approve the material terms of performance goals under the 2009 Northeast Utilities Incentive Plan as required by Section 162(m) of the Internal Revenue Code.	¨	¨	¨
4.   To ratify the selection of Deloitte & Touche LLP as independent registered public accountants for 2012.	¨	¨	¨

B Authorized Signatures — This section must be completed for your vote to be counted. — Date and Sign Below

Please sign exactly as name(s) appears hereon. Joint owners should each sign. When signing as attorney, executor, administrator, corporate officer, trustee, guardian, or custodian, please give full title.

Date (mm/dd/yyyy) — Please print date below.	Signature 1 — Please keep signature within the box.	Signature 2 — Please keep signature within the box.
//

1 U P X     N E U 1 †

01|A8G 142750_Admin_Blanks_-1_914155649/000001/000001/i    

You can access your Northeast Utilities account online.

You can now access your registered shareholder information on the following secure Internet site: http://www.computershare.com/investor.

Step 1: Register (1st time users only)	Step 3: View your account details and perform multiple transactions, such as:
Click on “Create Login” in the blue box and follow the instructions.	• View account balances	• Change your address
	• View transaction history	• View electronic shareholder communications
Step 2: Log In (Returning users)	• View payment history	• Buy or sell shares
Enter your User ID and Password and click the Login button.	• View common share quotes	• Check replacements

If you are not an Internet user and wish to contact Northeast Utilities, you may use one of the following methods:

Call: 1.800.999.7269

Write: Northeast Utilities, c/o Computershare, P.O. Box 43078, Providence, RI 02940-3078

Important notice regarding the Internet availability of proxy materials for the Annual Meeting of Shareholders.

The proxy statement, which includes the 2011 Annual Report as an appendix, is available at www.envisionreports.com/NU.

  q   IF YOU HAVE NOT VOTED VIA THE INTERNET OR TELEPHONE, FOLD ALONG THE PERFORATION, DETACH AND RETURN THE BOTTOM PORTION IN THE ENCLOSED ENVELOPE.   q

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Proxy/Vote Authorization Form – NORTHEAST UTILITIES

Annual Meeting of Shareholders October 31, 2012

Proxy/Vote Authorization Form is Solicited by Board of Trustees of the Company

The undersigned appoints Sanford Cloud, Jr., Thomas J. May, and Charles W. Shivery, and each of them, proxies of the undersigned, with power to act without the other and full power of substitution, to act for and to vote all common shares of Northeast Utilities that the undersigned would be entitled to cast if present in person at the 2012 Annual Meeting of Shareholders of Northeast Utilities to be held on October 31, 2012, and at any postponement or adjournment thereof, upon the matters indicated on the reverse side of this card.

This card also constitutes voting instructions for participants in the Northeast Utilities Service Company 401K Plan or NSTAR Savings Plan. The undersigned hereby directs the applicable trustee to vote all Common Shares credited to the undersigned’s account at the Annual Meeting and any adjournment thereof.

(Continued and to be marked, dated and signed, on the reverse side.)

C Non-Voting Items

Change of Address — Please print your new address below.	Comments — Please print your comments below.	Meeting Attendance
		Mark the box to the right if you plan to attend the Annual Meeting.	¨

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IF VOTING BY MAIL, YOU MUST COMPLETE SECTIONS A - C ON BOTH SIDES OF THIS CARD.