EXHIBIT 99.1

This short form prospectus constitutes a public offering of these securities only in those jurisdictions where they may be lawfully offered for sale and therein only by persons permitted to sell such securities. No securities regulatory authority has expressed an opinion about these securities and it is an offence to claim otherwise. The securities to be offered hereunder have not been, and will not be, registered under the United States Securities Act of 1933, as amended (the “U.S. Securities Act”) or the securities laws of the any state of the United States. Accordingly, these securities may not be offered or sold within the United States or to U.S. persons (as such term is defined in Regulation S under the U.S. Securities Act) (“U.S. Persons”) except in accordance with the Underwriting Agreement (as defined herein) and pursuant to transactions exempt from registration under the U.S. Securities Act and under the securities laws of any applicable state. This short form prospectus does not constitute an offer to sell or a solicitation of an offer to buy any of these securities within the United States or to any U.S. Person. See “Plan of Distribution.”

Information has been incorporated by reference in this short form prospectus from documents filed with securities commissions or similar authorities in Canada. Copies of the documents incorporated herein by reference may be obtained on request without charge from the secretary of the issuer at 2845 Bristol Circle, Oakville, Ontario, L6H 7H7, telephone (905) 465-4500, and are also available electronically at www.sedar.com.

SHORT FORM PROSPECTUS

New Issue October 20, 2011

ALGONQUIN POWER & UTILITIES CORP.

$85,315,000

15,100,000 Common Shares

This short form prospectus qualifies the distribution of 15,100,000 common shares (“Common Shares”) of Algonquin Power & Utilities Corp. (“Algonquin” or the “Corporation”) at a price of $5.65 (“Offering Price”) per Common Share (the “Share Offering”) (the “Offering”). The terms and offering price of the Common Shares was determined by negotiation between Algonquin and Scotia Capital Inc., BMO Nesbitt Burns Inc., CIBC World Markets Inc., National Bank Financial Inc., TD Securities Inc., Macquarie Capital Markets Canada Ltd., RBC Dominion Securities Inc., Canaccord Genuity Corp., Desjardins Securities Inc., Stifel Nicolaus Canada Inc., Mackie Research Capital Corporation and Cormark Securities Inc. collectively, the “Underwriters”). See “Plan of Distribution”.

The registered and head office of the Corporation is located at 2845 Bristol Circle, Oakville, Ontario, L6H 7H7.

BMO Nesbitt Burns Inc., CIBC World Markets Inc., National Bank Financial Inc. and TD Securities Inc. are each, directly or indirectly, a wholly-owned or majority-owned subsidiary of a Canadian chartered bank which is a lender to Algonquin Power Co. (“APCo”), a subsidiary entity of the Corporation, under a senior revolving credit facility (the “APCo Senior Credit Facility”). In addition, the Canadian chartered bank affiliate of BMO Nesbitt Burns Inc. has provided APCo with a fixed for floating interest rate swap. Accordingly, the Corporation may be considered to be a connected issuer of each of these Underwriters under applicable securities legislation. See “Relationship between the Corporation and Certain Underwriters”.

The Toronto Stock Exchange (the “TSX”) has conditionally approved the listing of the Common Shares to be issued under the Offering. Listing will be subject to the Corporation fulfilling all of the requirements of the TSX on or before January 11, 2012.

The Underwriters, as principals, conditionally offer the Common Shares, subject to prior sale, if, as and when issued and sold by the Corporation and accepted by the Underwriters in accordance with the conditions contained in the underwriting agreement and referred to under “Plan of Distribution” and subject to the approval of certain legal matters on behalf of the Corporation by Blake, Cassels & Graydon LLP and on behalf of the Underwriters by Cassels Brock & Blackwell LLP.

	Price to the Public		Underwriters’ Fee		Net Proceeds to the Corporation (1)
Per Common Share	$	5.65	$	0.226	$	5.424
TOTAL(2) (3)	$	85,315,000	$	3,412,600	$	81,902,400

(1) Before deducting expenses of the Offering estimated to be approximately $1.1 million which, together with the Underwriters’ fee, will be paid by the Corporation out of the proceeds of the Offering.

(2) Algonquin has granted to the Underwriters an over-allotment option (the “Over-Allotment Option”), exercisable in whole or in part for a period of 30 days from closing of the Offering, to purchase up to an additional 15% of the number of Common Shares issued under the Offering at a price of $5.65 per share on the same terms and conditions as the offering of the Common Shares.

(3) If the Over-Allotment Option is exercised in full, the “Price to the Public”, “Underwriters’ Fee” and “Net Proceeds to the Corporation” (before deducting expenses of the Offering) will be $98,112,250, $3,924,490 and $94,187,760, respectively. This short form prospectus also qualifies for distribution the grant of the Over-Allotment Option and the issuance of the Common Shares pursuant to the exercise of the Over-Allotment Option.

See “Plan of Distribution”.

Underwriter’s Position	Number of Securities Available	Exercise Period	Exercise Price
Over-Allotment Option	2,265,000 Common Shares	Up to 30 days from the closing of the Offering	$5.65 per Common Share

Subject to applicable laws, the Underwriters may, in connection with the Offering, effect transactions intended to stabilize or maintain the market price of the Common Shares at levels other than those which might otherwise prevail in the open market. Such transactions, if commenced, may be discontinued at any time. The Underwriters propose to offer the Common Shares initially at the Offering Price. After the Underwriters have made reasonable efforts to sell all of the Common Shares by this short form prospectus at such price, the Offering Price may be decreased, and further changed from time to time, to an amount not greater than the Offering Price. Any such reduction in the offering price shall not affect the purchase price to be paid to the Corporation. See “Plan of Distribution”.

The outstanding Common Shares are listed on the TSX under the trading symbol “AQN”. The closing price of the Common Shares on the TSX on October 19, 2011 was $5.55 per Common Share.

Subscriptions for Common Shares will be received subject to rejection or allotment in whole or in part and the right is reserved to close the subscription books at any time without notice. The closing of the Offering is expected to occur on or about October 27, 2011 or such later date as the Corporation and the Underwriters may agree, but in any event not later than November 1, 2011 (the “Closing Date”). In any event, the Common Shares are to be taken up by the Underwriters, if at all, on or before a date not later than 42 days after the date of the receipt for this short form prospectus. The Common Shares will be represented by one or more certificates in registered form to CDS Clearing and Depository Services Inc. (“CDS”) or its nominee under the book-based system administered by CDS. No certificates evidencing the Common Shares will be issued to subscribers except in certain limited circumstances, and registration will be made in the depository services of CDS. Subscribers for the Common Shares will receive only a customer confirmation from the Underwriters or other registered dealer who, is a CDS Participant and from or through whom a beneficial interest in the Common Shares is purchased.

In this short form prospectus, unless otherwise specified or the context otherwise requires, all dollar amounts are expressed in Canadian dollars.

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TABLE OF CONTENTS

Page
DOCUMENTS INCORPORATED BY REFERENCE	4
ELIGIBILITY FOR INVESTMENT	5
FORWARD-LOOKING STATEMENTS	5
ALGONQUIN POWER & UTILITIES CORP	6
BUSINESS OF THE CORPORATION	9
DESCRIPTION OF SHARE CAPITAL	10
CONSOLIDATED CAPITALIZATION	11
TRADING PRICES AND VOLUMES	12
PRIOR SALES	14
USE OF PROCEEDS	15
PLAN OF DISTRIBUTION	15
RISK FACTORS	17

Page
RELATIONSHIP BETWEEN THE CORPORATION
AND CERTAIN UNDERWRITERS	19
AUDITORS AND REGISTRAR AND TRANSFER
AGENT	19
INTERESTS OF EXPERTS	19
PURCHASERS’ STATUTORY RIGHTS	20
AUDITORS’ CONSENT	21
APPENDIX A – HISTORICAL FINANCIAL
STATEMENTS OF GRANITE STATE AND
ENERGYNORTH AND PRO FORMA
FINANCIAL STATEMENTS	F-1
CERTIFICATE OF THE CORPORATION	C-1
CERTIFICATE OF THE UNDERWRITERS	C-2

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DOCUMENTS INCORPORATED BY REFERENCE

The following documents of the Corporation, filed with the various provincial securities commissions or similar authorities in each of the provinces of Canada, are specifically incorporated by reference and form an integral part of this short from prospectus and are available under the Corporation’s profile on SEDAR at www.sedar.com:

(a) the annual information form of the Corporation dated March 31, 2011 for the year ended December 31, 2010 (the “AIF”);

(b) the consolidated financial statements of the Corporation as at and for the years ended December 31, 2010 and 2009 together with the notes thereto and the auditors’ report thereon;

(c) management’s discussion and analysis (“MD&A”) of the Corporation for the year ended December 31, 2010;

(d) the unaudited interim consolidated financial statements of the Corporation as at and for the six months ended June 30, 2011, together with the notes thereto (the “Second Quarter Financial Statements”);

(e) MD&A of the Corporation for the six-month period ended June 30, 2011;

(f) the material change report of the Corporation dated and filed on January 10, 2011 in respect of the closing of the acquisition by the Corporation and Emera Incorporated (“Emera”) of the California-based electricity distribution and related generation assets of NV Energy, Inc.;

(g) the material change report of the Corporation dated and filed on July 26, 2011 in respect of the completion by APCo of a private placement $135,000,000 principal amount of 5.50% senior unsecured debentures due July 25, 2018; and

(h) the management information circular of the Corporation filed on May 30, 2011 in respect of an annual and special meeting of shareholders of the Corporation held on June 21, 2011.

All material change reports (excluding confidential material change reports), annual information forms, annual financial statements and the auditors’ report thereon, interim financial statements and related management’s discussion and analysis, information circulars, business acquisition reports and any other documents as may be required to be incorporated by reference herein under applicable securities legislation which are filed with a securities commission or any similar authority in Canada after the date of this short form prospectus and prior to the termination of the Offering shall be deemed to be incorporated by reference into this short form prospectus.

Any statement contained in a document incorporated or deemed to be incorporated by reference herein shall be deemed to be modified or superseded, for purposes of this short form prospectus, to the extent that a statement contained herein or in any other subsequently filed document that also is or is deemed to be incorporated by reference herein modifies or replaces such statement. The modifying or superseding statement need not state that it has modified or superseded a prior statement or include any other information set forth in the document that it modifies or supersedes. The making of a modifying or superseding statement shall not be deemed an admission for any purposes that the modified or superseded statement, when made, constituted a misrepresentation, an untrue statement of a material fact or an omission to state a material fact that is required to be stated or that is necessary to make a statement not misleading in light of the circumstances in which it was made. Any statement so modified or superseded shall not be deemed in its unmodified or superseded form to constitute part of this short form prospectus.

The Corporation is an “SEC issuer” as such term is defined in National Instrument 52-107 – Acceptable Accounting Principles and Auditing Standards. Effective January 1, 2011, the Corporation changed the basis of its accounting from Canadian generally accounted accounting principles (“Canadian GAAP”) to generally accepted accounting principles in the United States (“U.S. GAAP”) and follows disclosures required per Regulation S-X Rule 10-10, Interim Financial Statements provided by the U.S. Securities and Exchange Commission (“SEC”) Guidance. The Corporation’s U.S. GAAP consolidated interim financial statements in 2011 represent the financial statements for part of the period covered by the first U.S. GAAP annual financial statements for the year ended December 31, 2011.

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The Corporation’s consolidated financial statements were prepared in accordance with Canadian GAAP until December 31, 2010. Canadian GAAP differs in some areas from US GAAP as was disclosed in the reconciliation to U.S. GAAP included in the audited annual financial statements for the year ended December 31, 2010. The impact of the differences between Canadian GAAP and U.S. GAAP on the Company’s financial position, financial performance and cash flows as at and for the two years ended December 31, 2010 are provided in note 24 of the audited consolidated financial statements for the year ended December 31, 2010. The accounting policies set out in the Corporation’s interim consolidated financial statements for the period ended March 31, 2011 have been consistently applied to all the periods presented including the Second Quarter Financial Statements. The comparative figures in respect of the period ending June 30, 2010 in the Second Quarter Financial Statements have been retrospectively restated to reflect the adoption of U.S. GAAP.

There has been no significant impact of the transition to U.S. GAAP on the Corporation’s internal controls, information technology systems and financial reporting expertise requirements. No financial covenants were impacted by the Corporation’s conversion to U.S. GAAP given the few differences that exist with Canadian GAAP.

ELIGIBILITY FOR INVESTMENT

In the opinion of Blake, Cassels & Graydon LLP, counsel to the Corporation, and Cassels Brock & Blackwell LLP, counsel to the Underwriters, the Common Shares, if issued on the date hereof, would be qualified investments under the Income Tax Act (Canada) and the regulations thereunder (the “Tax Act”) for a trust governed by a registered retirement savings plan, a registered retirement income fund, a registered education savings plan, a deferred profit sharing plan, a registered disability savings plan and a tax-free savings account. Provided that the holder of a tax-free savings account or, pursuant to certain proposed amendments to the Tax Act to be effective after March 22, 2011 (the “RRSP/RRIF Proposals”), the annuitant under a registered retirement savings plan or registered retirement income fund does not hold a significant interest in the Corporation or any person or partnership that does not deal at arm’s length with the Corporation for purposes of the Tax Act, and provided that such holder or annuitant deals at arm’s length with the Corporation for purposes of the Tax Act, the Common Shares will not be a prohibited investment for a trust governed by such tax-free savings account or, pursuant to the RRSP/RRIF Proposals, such registered retirement savings plan or registered retirement income fund.

FORWARD-LOOKING STATEMENTS

This short form prospectus, and the documents incorporated herein, contain forward-looking statements within the meaning of applicable securities laws, including, among others, statements relating to the Corporation’s objectives and strategies to achieve those objectives, the Corporation’s beliefs, plans, estimates and intentions, and similar statements concerning anticipated future events, results, circumstances, performance or expectations that are not historical facts. Forward-looking statements generally can be identified by words such as “outlook”, “objective”, “may”, “will”, “expect”, “intend”, “estimate”, “anticipate”, “believe”, “should”, “plans” or “continue” or similar expressions suggesting future outcomes or events. Such forward-looking statements reflect the Corporation’s beliefs at the time such statements are made and are based on information available to management at the time such statements are made. Forward-looking statements are provided for the purpose of presenting information about management’s current expectations and plans relating to the future and readers are cautioned that such statements may not be appropriate for other purposes. These statements are not guarantees of future performance and are based on the Corporation’s estimates and assumptions that are subject to risks and uncertainties, including those described under “Risk Factors” and those discussed in the Corporation’s materials filed with the Canadian securities regulatory authorities from time to time, which could cause the actual results and performance of the Corporation to differ materially from the forward-looking statements contained in this short form prospectus, and the documents incorporated by reference herein. These risks and uncertainties include, among other things, risks related to: the Common Share price; availability of cash for distributions; liquidity; credit risk; interest rate and other debt related risks; tax risk; ability to access capital markets; dilution; government regulation; shareholder liability; potential conflicts of interest; redemption right; statutory remedies; the tax position and consequences unique to each shareholder. Material factors or assumptions that were applied in drawing a conclusion or making an estimate set out in the forward-looking statements include that the general economy remains stable; and equity and debt markets continue to provide access to capital. The

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Corporation cautions that this list of factors is not exhaustive. Although the forward-looking statements contained in this short form prospectus, and the documents incorporated herein, are based upon what the Corporation believes are reasonable assumptions, there can be no assurance that actual results will be consistent with these forward-looking statements. All forward-looking statements in this short form prospectus, and the documents incorporated herein, are qualified by these cautionary statements. The forward-looking statements are made only as of the date that such statements are made and the Corporation, except as required by applicable law, assumes no obligation to update or revise them to reflect new information or the occurrence of future events or circumstances.

ALGONQUIN POWER & UTILITIES CORP.

General

The Corporation was incorporated under the Canada Business Corporations Act on August 1, 1988 as Traduction Militech Translation Inc. Pursuant to articles of amendment dated August 20, 1990 and January 24, 2007, the Corporation amended its articles to change its name to Societe Hydrgoenique Incorporée – Hydrogenics Corporation and Hydrogenics Corporation – Corporation Hydrgenique, respectively. Pursuant to a certificate and articles of arrangement dated October 27, 2009, the Corporation, among other things, created the Common Shares and changed its name to Algonquin Power & Utilities Corp. The head and principal office of the Corporation is located at 2845 Bristol Circle, Oakville, Ontario, L6H 7H7.

The Corporation is continuing the business of APCo (formerly, Algonquin Power Income Fund). The Corporation’s principal holdings are its trust units of APCo and shares of Liberty Utilities Co.

The following chart illustrates the corporate structure of the Corporation and its primary subsidiaries and businesses:

Ian Robertson is the Chief Executive Officer, Chris Jarratt is the Vice Chairman and David Bronicheski is the Chief Financial Officer of the Corporation.

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Recent Developments

Acquisitions of Granite State and EnergyNorth

On December 9, 2010, the Corporation announced that, through a wholly owned subsidiary, it had entered into agreements to acquire all issued and outstanding shares of Granite State Electric Company (“Granite State”), a regulated electric distribution utility, and EnergyNorth Natural Gas, Inc. (“EnergyNorth”), a regulated natural gas distribution utility from National Grid USA (“National Grid”) for total consideration of U.S. $285.0 million, subject to certain working capital and other closing adjustments, as outlined in the share purchase agreements by and between National Grid and the Corporation’s wholly owned subsidiary entered into on December 8, 2010 and amended and restated on January 11, 2011 (the “Purchase Agreements”).

Granite State provides electric service to over 43,000 customers in 21 communities in New Hampshire. EnergyNorth provides natural gas services to over 83,000 customers in five counties and 30 communities in New Hampshire. Granite State and EnergyNorth are anticipated to have regulatory assets at closing of approximately U.S. $72.0 million and U.S. $178.8 million.

Closings of the transactions are subject to certain conditions including state and federal regulatory approval, and are expected to occur by the end of 2011. Financing of the acquisitions is expected to occur simultaneously with the closing of the transactions. Liberty Utilities is targeting a capital structure with not more than 50% debt to total capital, consistent with investment grade utilities.

As an element of the EnergyNorth and Granite State acquisitions and pursuant to a subscription agreement dated as of March 25, 2011, Emera has agreed to a subscribe for 12 million subscription receipts of the Corporation at a price of $5.00 per subscription receipt. Emera paid for the subscription receipts with a promissory note. The subscription receipts are exchangeable on a one-for-one basis for Common Shares, and the promissory note is due and payable, upon the satisfaction of certain conditions relating to the closing of the acquisition of Granite State and EnergyNorth.

For complete details on the Purchase Agreement(s), reference should be made to the copies of such documents filed under the Corporation’s profile on SEDAR at www.sedar.com.

The acquisition of Granite State and EnergyNorth constitutes a significant probable acquisition within the meaning of National Instrument 44-101 – Short Form Prospectus Distributions. Accordingly, historical financial statements of Granite State and EnergyNorth and pro forma financial statements giving effect to the completion of the acquisitions are included as Appendix A to this short form prospectus.

Conversion of Series 1A Convertible Debentures to Equity

On May 16, 2011 (the “Redemption Date”), the Corporation redeemed all of the issued and outstanding Series 1A Debentures. Between April 1, 2011 and the Redemption Date, $60.266 million principal amount of Series 1A Debentures was converted by debentureholders into 14,771,185 shares of the Corporation.

On May 16, 2011 the Corporation redeemed the remaining Series 1A Debentures by issuing and delivering 430,666 shares of the Corporation. As of June 30, 2011, as a result of the redemption, there were no Series 1A Debentures outstanding.

Strategic Investment Agreement with Emera

On April 29, 2011, the Corporation announced that it had entered into a strategic investment agreement (the “Strategic Agreement”) with Emera which establishes how the Corporation and Emera will work together to pursue specific strategic investments of mutual benefit.

The Strategic Agreement outlines “areas of pursuit” for each of the Corporation and Emera. For the Corporation, these include investment opportunities relating to unregulated renewable generation, small electric utilities and gas distribution utilities. For Emera, these include investment opportunities related to regulated renewable projects within its service territories and large electric utilities. These “areas of pursuit” are intended to represent investment areas in which

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there is potential overlap between the Corporation and Emera and are not exhaustive of either company’s business focus and do not limit in any way the business activities which either the Corporation or Emera can undertake. Each of the Corporation or Emera are free to undertake independently investments within their own “areas of pursuit” and outside the other party’s “areas of pursuit”. Under the Strategic Agreement, to the extent either the Corporation or Emera encounter opportunities which fall within the other’s “areas of pursuit”, they are committed to work with the other party in the development of such investment opportunities.

As an element of the Strategic Agreement, Emera’s allowed common equity interest in the Corporation will be increased from 15% to 25%. The Strategic Agreement was approved by shareholders at the annual and special meeting held on June 21, 2011.

Acquisition of 100% Ownership Interest of the California Utility

On April 29, 2011, Emera agreed to sell its 49.999% interest in California Pacific Utility Ventures, LLC (“Calpeco”), which owns a local electric distribution and generation utility in California, to the Corporation, with closing of such transaction subject to regulatory approval. The definitive terms of such sale were set out in a unit purchase agreement entered into as of September 12, 2011 between subsidiary entities of the Corporation and Emera. Calpeco acquired the California-based electricity distribution and related generation assets of NV Energy, Inc. effective January 1, 2011. As consideration, Emera will receive 8,211,000 of the Corporation’s common shares in two tranches. 4,790,000 of the shares will be issued following regulatory approval of the Calpeco ownership transfer and the balance of the shares will be issued following completion of Calpeco’s general rate case setting customer rates for the years 2012 to 2014 in its service territory, expected to be completed in the latter half of 2012.

In connection with the acquisition of Emera’s interest in Calpeco, the Corporation issued to Emera, by way of private placement, 4,790,000 A subscription receipts (the “A Subscription Receipts”) and 3,421,000 B subscription receipts (the “B Subscription Receipts”) each at a price of $4.72 per subscription receipt on September 12, 2011. Emera paid for the A Subscription Receipts and the B Subscription Receipts with promissory notes. The A Subscription Receipts are exchangeable on a one-for-one basis for Common Shares, and the promissory note with respect to the A Subscription Receipts becomes due, upon the satisfaction of certain conditions relating to the acquisition by the Corporation of Emera’s interest in Calpeco. The B Subscription Receipts are exchangeable on a one-for-one basis for Common Shares, and the promissory note with respect to the B subscription receipts becomes due, when the California Public Utilities Commission approves Calpeco’s first rate case.

Utility Acquisitions by Liberty Utilities

On May 13, 2011, the Corporation announced that, through its wholly owned subsidiaries, it had entered into an agreement with Atmos Energy Corporation (“Atmos”) to acquire its regulated natural gas distribution utility assets (the “Midwest Gas Utilities”) located in Missouri, Iowa, and Illinois. The total purchase price for the Midwest Gas Utilities is approximately U.S. $124 million, subject to certain working capital and other closing adjustments. The Corporation expects to acquire assets for rate making purposes of approximately $112 million, representing a purchase price multiple of 1.106x of the acquired rate base.

The Midwest Gas Utilities currently provide natural gas local distribution service to approximately 84,000 customers. Closing of the transaction is subject to certain conditions, including state and federal regulatory approval, and is expected to occur in 2012. Financing of the acquisitions is expected to occur simultaneously with the closing of the transaction. The Corporation will not be assuming any existing indebtedness with this transaction.

New Wind Projects under Development

On July 26, 2011, the Corporation announced that APCo had entered into a 25-year power purchase agreement with Manitoba Hydro in respect of a 16.5MW expansion of APCo’s existing St. Leon wind energy project located in the Province of Manitoba.

The expansion will be comprised of 10 Vestas V82-1.65 MW wind turbines, which already have been manufactured and are awaiting shipment to the site from a U.S. storage location. Permitting for the expansion project was completed in 2010 with construction commencing in the third quarter of 2011. The project is expected to be commissioned in the first quarter of 2012 with total estimated capital costs of approximately $29.5 million.

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In the first full year of production following commissioning, APCo anticipates generating annual gross revenues of $3.8 million. Rates paid under the power purchase agreement are subject to a partial inflation adjustment that will be applied annually.

Acquisition of an Interest in First Wind’s Northeast Projects

On April 30, 2011, the Corporation and Emera announced that they have entered into an agreement with First Wind Holdings, LLC (“First Wind”) to jointly construct, own and operate wind energy projects in the Northeast U.S.

First Wind has a 370 MW portfolio of wind energy projects in the Northeast U.S. including five operating projects and two projects near operation. These assets will become part of an operating company of which First Wind will own 51% and, Emera and the Corporation through a separate joint venture (“Northeast Wind”), will own 49% of the operating company. Emera will initially own 75% of the equity of Northeast Wind and the Corporation will own 25% of the equity. Northeast Wind expects to invest $183 million to acquire the 49% ownership interest, and an additional $150 million investment by way of a loan with a term of five years to the operating company, for a total of $333 million.

The Corporation will finance its equity investment of approximately $83.25 million in Northeast Wind, in part, through a subscription agreement with Emera to issue approximately 6.9 million shares at a price of $5.37 per share for proceeds of $37 million. Delivery of the shares and receipt of the proceeds under the subscription receipts is conditional on and is planned to occur simultaneously with the closing of the acquisition of Northeast Wind.

The Corporation and Emera will work with First Wind to grow the operating company and develop other projects in the region. The transaction provides Northeast Wind access to a pipeline of Northeast U.S. based development projects and provides the Corporation an effective way to extend its development reach into a geographic area which has historically not been included in its area of focus. Once projects in the development pipeline meet certain eligibility criteria they will transfer to the operating company.

The transaction requires certain state and federal regulatory approvals, among others, and is expected to close by the end of the year.

APCo Senior Unsecured Debentures

On July 25, 2011, APCo issued $135 million in Senior Unsecured Debentures (the “APCo Senior Unsecured Debentures”). The net proceeds from the APCo Senior Unsecured Debentures were used to repay the outstanding AirSource senior debt at the St. Leon facility, to reduce amounts outstanding under the APCo Senior Credit Facility and for general corporate purposes. The Senior Unsecured Debentures mature on July 25, 2018, and bear interest at a rate of 5.50% per annum, calculated semi-annually payable on January 25 and July 25 each year, commencing on January 25, 2012.

BUSINESS OF THE CORPORATION

Description of Business

The Corporation is engaged in the business of generating and marketing electrical energy within the independent power generation industry and is also involved in the regulated utility business in the United States. The regulated utilities include water distribution, wastewater treatment, electric distribution and with the acquisition of EnergyNorth, local gas distribution. The Corporation’s operations are aligned into two major business units: independent power generation and utilities (water, gas and electric). The independent power generation business unit develops and operates a diversified portfolio of electrical energy generation facilities and the utilities business unit provides utility services within a specified service territory.

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Independent Power Generation Business

APCo develops, owns and operates a diversified portfolio of electrical energy generation facilities. Within this business there are three distinct divisions: Renewable Energy, Thermal Energy and Development. The Renewable Energy division operates APCo’s hydroelectric and wind power facilities. The Thermal Energy division operates co-generation, energy-from-waste, and steam production facilities. The Development division seeks to deliver continuing growth to APCo through development of APCo’s greenfield power generation projects, accretive acquisitions of electrical energy generation facilities as well as development of organic growth opportunities within APCo’s existing portfolio of renewable energy and thermal energy facilities.

APCo’s Renewable Energy division generates and sells electrical energy through a diverse portfolio of clean, renewable power generation and thermal power generation facilities across North America. APCo currently owns or has interests in 43 hydroelectric facilities operating in Ontario (4), Québec (12), Newfoundland (1), New Brunswick (1) Alberta (1), New York State (13), New Hampshire (7), Vermont (1), Maine (2) and New Jersey (1) with a combined generating capacity of approximately 165 megawatts (“MW”). APCo also owns a 104 MW wind powered generating station in Manitoba and holds a 75% effective interest in a 26 MW wind powered generating station recently completed in Saskatchewan. APCo is currently constructing a 17MW expansion to its Manitoba wind powered generating station. Approximately 75% of the installed capacity of APCo’s renewable energy facilities sell their electrical output pursuant to long term power purchase agreements (“PPAs”) with major utilities and have a weighted average remaining contract life of 13 years.

APCo’s Thermal Energy division holds equity interests in one energy-from-waste facility in Ontario with an installed generating capacity of 10 MW, 4 diesel generating facilities in Maine and New Brunswick with total installed generating capacity of 34 MW and 3 natural gas-fired cogeneration facilities in each of California, Connecticut, and Ontario with an installed capacity of approximately 112 MW. In addition, APCo’s Thermal Energy division owns partnership, share and debt interests in two biomass-fired generating facilities with combined installed capacity of approximately 43 MW located in Alberta and Québec. APCo’s Thermal Energy division holds minority investments in two natural gas/wood waste-fired generating facilities with joint installed capacity of approximately 170 MW located in northern Ontario. APCo’s ownership interest in the combined installed generating capacity represents approximately 210 MW. APCo’s thermal energy facilities operate under long term PPAs with major utilities and have an average remaining contract life of 8 years.

Utilities Business

Liberty Utilities owns and operates natural gas, electricity and water/wastewater utilities through its wholly-owned rate regulated subsidiaries. The underlying business strategy is to provide quality and reliable utility services while generating stable and predictable earnings from the nationwide portfolio of moderate-sized utilities. These operations are organized to share certain common infrastructure which allows Liberty Utilities to provide best-in-class customer experience. Liberty Utilities currently serves approximately 120,000 electric and water utility customers and is the process of completing regulatory approval for utilities representing an additional 210,000 electric and natural gas customers.

DESCRIPTION OF SHARE CAPITAL

The Corporation is authorized to issue an unlimited number of Common Shares and an unlimited number of preferred shares, issuable in series. The holders of Common Shares are entitled to dividends if, as and when declared by the board of directors of the Corporation, to one vote per share at meetings of the holders of Common Shares and upon liquidation, dissolution or winding up of the Corporation to receive pro rata the remaining property and assets of the Corporation. As of the date hereof, there are 119,217,795 Common Shares and no preferred shares outstanding. There are also 27,101,131 subscription receipts of the Corporation outstanding related to three pending acquisitions. These subscription receipts may, upon the occurrence of certain events, be exchanged on a one-for-one basis for Common Shares. See “Prior Sales”.

The Corporation also has outstanding $59,967,000 aggregate principal amount of 6.35% convertible unsecured subordinated debentures due November 30, 2016 (the “Series 2A Debentures”). The principal amount is convertible into Common Shares at the option of the holder of such debentures at a price of $6.00 principal amount per Common Share. If all such principal amount were converted, an aggregate of 9,994,500 Common Shares would be issued on such conversion.

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The Corporation also has outstanding $62,685,000 aggregate principal amount of 7.00% convertible unsecured subordinated debentures due June 30, 2017 (the “Series 3 Debentures”). The principal amount is convertible into Common Shares at the option of the holder of such debentures at a price of $4.20 principal amount per Common Share. If all such principal amount were converted, an aggregate of 14,925,000 Common Shares would be issued on such conversion.

On August 11, 2011, the Corporation announced an increase in the annual dividend paid on the Common Shares of $0.02 per Common Share for a total annual dividend of $0.28 per Common Share. Commencing with the quarterly dividend payment of $0.07 per Common Share on October 17, 2011 to shareholders of record as of September 30, 2011, the Corporation currently anticipates paying an annual dividend of $0.28 per Common Share, paid quarterly at a rate of $0.07 per Common Share. However, any future determination to pay dividends will be at the discretion of the Corporation’s board of directors and will be dependent upon the Corporation’s earnings, capital requirements and financial position, as well as general economic conditions and other factors deemed relevant by the Corporation’s board of directors.

CONSOLIDATED CAPITALIZATION

The following table sets forth the consolidated capitalization of the Corporation as at the dates indicated:

			As at June 30, 2011
Item	As at December 31, 2010		before giving effect to the Offering		after giving effect to the issuance of the APCo Senior Unsecured Debentures and before giving effect to the Offering			after giving effect to the issuance of the APCo Senior Unsecured Debentures and the Offering			after giving effect to issuance of the APCo Senior Unsecured Debentures, the Offering and the acquisitions of Granite State / EnergyNorth
(in thousands of dollars, other than the number of Common Shares outstanding)
Revolving Credit Facilities(1)		64,500		70,000		3,000	(2)		3,000			21,871	(4)
Long-Term Debt, excluding Revolving Credit Facilities		195,473		258,667		325,843	(2)		325,843			470,519	(4)
Convertible Debentures		181,758		122,477		122,477			122,477			122,477
Shareholder’s Equity		795,443		884,156		884,156			966,546	(3)		1,026,546	(4)
Total		1,238,598		1,335,300		1,335,300			1,417,690			1,640,678
Common Shares		95,422,778		119,199,940		119,199,940			134,299,940	(3)		146,299,940	(4)

Notes:

(1) Revolving Credit Facilities includes the APCo Senior Credit Facility and a short term revolving credit facility at Liberty Utilities. The Liberty Utilities revolving credit facility is expected to fund short term working capital, acquisitions and significant capital requirements of the utilities group.

(2) The APCo Senior Unsecured Debentures were used to repay the outstanding AirSource senior debt at the St. Leon facility, to reduce amounts outstanding under the APCo Senior Credit Facility and for general corporate purposes.

(3) The number of Common Shares and the equity value shown after giving effect to the Offering reflect the following:

a. assumes an additional 15,100,000 shares are issued for equity of approximately $85.3 million pursuant to the Offering;

b. assumes estimated issuance costs of $4.5 million, offset by related tax benefits of $1.6 million;

c. excludes any additional equity which may be issued upon exercise of the Over-Allotment Option; and

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d. assumes that in the interim before the acquisition of Granite State and EnergyNorth are completed, the net proceeds of the Offering, before any exercise of the Over-Allotment Option, are invested in short term deposits.

(4) Assumes that the acquisition of Granite State and EnergyNorth are completed and reflect the following:

a. assumes an additional 12,000,000 shares are issued to Emera for $60.0 million pursuant to a subscription receipt agreement dated March 25, 2011;

b. assumes long term debt financing of U.S. $135 million, net of estimated finance costs of U.S. $1.2 million, converted at the exchange rate on June 30, 2011; and

c. assumes working capital of approximately U.S. $19 million is financed from a revolving credit facility at Liberty Utilities.

TRADING PRICES AND VOLUMES

Common Shares

The outstanding Common Shares are traded on the TSX under the trading symbol “AQN”. The following table sets forth the high and low price for, and the volume of trading in, the Common Shares for the periods indicated, based on information obtained from the TSX.

	Price ($)
Month	High		Low		Trading Volume
2010
September		4.75		4.21		4,087,116
October		4.91		4.57		9,675,727
November		5.04		4.61		6,705,800
December		5.10		4.64		5,076,401
2011
January		5.03		4.73		6,166,900
February		5.13		4.81		5,018,222
March		5.42		4.85		5,653,687
April		5.63		4.98		9,523,367
May		5.87		5.23		7,487,115
June		5.86		5.44		5,755,025
July		5.99		5.59		2,562,864
August		5.83		4.90		6,598,801
September		5.85		5.40		4,361,984
October (1 - 18)		5.88		5.47		3,463,670

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Series 2A Debentures

The Series 2A Debentures are traded on the TSX under the symbol “AQN.DB.A”. The following table sets forth the high and low price for, and volume of trading in, the Series 2A Debentures for the periods indicated, based on information obtained from the TSX.

	Price ($ per $100 principal amount)
Month	High		Low		Trading Volume
2010
September		106.75		104.25		308,000
October		108.00		105.00		356,000
November		107.85		104.10		440,000
December		106.50		103.50		323,000
2011
January		107.00		106.00		111,000
February		107.50		106.31		242,000
March		109.00		106.70		189,000
April		107.50		107.00		428,000
May		107.50		106.00		422,000
June		108.74		106.76		812,000
July		108.00		106.50		542,000
August		107.00		102.00		673,000
September		106.50		104.00		917,000
October (1 - 18)		105.50		103.00		494,000

Series 3 Debentures

The Series 3 Debentures are traded on the TSX under the symbol “AQN.DB.B”. The following table sets forth the high and low price for, and volume of trading in, the Series 3 Debentures for the periods indicated, based on information obtained from the TSX.

	Price ($ per $100 principal amount)
Month	High		Low		Trading Volume
2010
September		114.90		109.00		3,411,000
October		118.51		112.01		2,644,000
November		122.00		113.55		3,811,000
December		122.77		114.15		2,337,000
2011
January		121.00		115.33		4,484,000
February		125.00		118.05		1,868,000
March		130.67		120.00		2,504,000
April		135.00		121.02		1,505,000
May		139.58		127.11		2,587,000
June		140.00		131.53		2,117,000
July		144.00		135.01		500,000
August		140.00		120.00		5,257,000
September		139.10		131.00		1,467,000
October (1 - 18)		140.00		133.50		2,222,000

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PRIOR SALES

During the 12 months preceding the date of this short form prospectus, the Corporation issued the following Common Shares, debentures and securities convertible into Common Shares:

Security	Date of Issue	Total Number	Price
Subscription Receipts	March 25, 2011	12,000,000	$5.00 per subscription receipt, paid for by a promissory note. The subscription receipts are exchangeable on a one-for-one basis for Common Shares issued from treasury, and the promissory note becomes due and payable by Emera, upon the occurrence of certain conditions relating to the acquisition of Granite State and EnergyNorth from National Grid.
Subscription Receipts	August 5, 2011	6,890,131	$5.37 per subscription receipt, paid for by a promissory note. The subscription receipts are exchangeable on a one-for-one basis for Common Shares issued from treasury, and the promissory note becomes due and payable by Emera, upon the occurrence of certain conditions relating to joint venture between the Corporation and Emera, on the one hand, and First Wind, on the other hand.
Subscription Receipts	September 12, 2011	8,211,000 (consisting of 4,790,000 A Subscription Receipts and 3,421,000 B Subscription Receipts)	$4.72 per A Subscription receipt, paid for by a promissory note. $4.72 per B Subscription Receipt, paid for by a promissory note. These subscription receipts are exchangeable on a one-for-one basis for Common Shares issued from treasury, and the promissory notes become due and payable by Emera, upon the occurrence of conditions as more particularly described under “Algonquin Power & Utilities Corp. – Recent Developments – Acquisition of 100% Ownership Interest of the California Utility”.

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USE OF PROCEEDS

The aggregate net proceeds of the Offering (not including the exercise of the Over-Allotment Option), after payment of the Underwriters’ fees of approximately $3.4 million and expenses of the Offering estimated to be $1.1 million, will be approximately $80.8 million. Proceeds of approximately $75 million from the Offering will be used to fund a portion of the purchase price related to the acquisition of Granite State and EnergyNorth, approximately $5.8 million to repay existing indebtedness under the APCo Senior Credit Facility and any balance for general corporate purposes. See “Algonquin Power & Utilities Corp. – Recent Developments – Acquisitions of Granite State and EnergyNorth” for a description of such acquisitions and the regulatory approvals required to complete such acquisitions.

The Corporation intends to spend the funds available as stated in this short form prospectus. However, there may be circumstances where, for sound business reasons, a reallocation of funds may be deemed prudent or necessary.

PLAN OF DISTRIBUTION

The Underwriters have agreed with the Corporation pursuant to an underwriting agreement dated as of October 13, 2011 (the “Underwriting Agreement”) to underwrite the sale of 15,100,000 Common Shares.

Subject to the terms and conditions contained in the Underwriting Agreement, the Corporation has agreed to issue and sell and the Underwriters have agreed to purchase, on October 27, 2011, or on such other date as may be agreed upon, but in any event not later than November 1, 2011, an aggregate of 15,100,000 Common Shares at a price of $5.65 per Common Share payable in cash against delivery of the Common Shares, subject to compliance with the conditions contained in the Underwriting Agreement. In any event, the Common Shares are to be taken up by the Underwriters, if at all, on or before a date not later than 42 days after the date of the receipt for this short form prospectus. The Corporation has agreed to pay the Underwriters a fee of $0.226 per Common Share purchased under the Offering for the services provided by the Underwriters in distributing such Common Shares. The terms and the price of the Common Shares offered hereby were determined by negotiation between the Corporation and the Underwriters. The obligations of the Underwriters under the Underwriting Agreement are several (and not joint, nor joint and several) and each Underwriter may terminate its obligations at its discretion based upon the occurrence of certain stated events. The Underwriters are, however, obligated to take-up and pay for all of the Common Shares offered hereby if any are purchased under the Underwriting Agreement.

The Corporation has granted to the Underwriters the Over-Allotment Option, exercisable at their sole discretion, in whole or in part, for a period of 30 days after the closing of the Offering, to purchase up to an additional 2,265,000 Common Shares on the same terms as set forth above for the purpose of covering all of the Underwriters’ over-allocation position, if any, and for market stabilization purposes. This short form prospectus also qualifies the distribution of the Over-Allotment Option and the issuance of the Common Shares upon the exercise of the Over-Allotment Option. A purchaser who acquires Common Shares forming part of the Underwriters’ over-allocation position acquires those Common Shares under this short form prospectus, regardless of whether the over-allocation position is ultimately filled through the exercise of the Over-Allotment Option or secondary market purchases.

Subscriptions for Common Shares will be received subject to rejection or allotment in whole or in part and the right is reserved to close the subscription books at any time without notice. The Common Shares will be represented by one or more certificates in registered form to CDS or its nominee under the book-based system administered by CDS and deposited with CDS on the Closing Date. No certificates evidencing the Common Shares will be issued to subscribers except in certain limited circumstances, and registration will be made in the depository services of CDS. Subscribers for the Common Shares will receive only a customer confirmation from the Underwriters or other registered dealer who, is a CDS Participant and from or through whom a beneficial interest in the Common Shares is purchased

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Subject to applicable laws, the Underwriters may, in connection with the Offering, effect transactions intended to stabilize or maintain the market price of the Common Shares at levels other than those which might otherwise prevail in the open market. Such transactions, if commenced, may be discontinued at any time. The Underwriters propose to offer the Common Shares initially at the Offering Price. After the Underwriters have made reasonable efforts to sell all of the Common Shares by this short form prospectus at such price, the Offering Price may be decreased, and further changed from time to time, to an amount not greater than the Offering Price. Any such reduction in the offering price shall not affect the purchase price to be paid to the Corporation.

Underwriter’s Position	Maximum Size	Exercise Period	Exercise Price
Over-Allotment Option	2,265,000 Common Shares	Up to 30 days after the closing of the Offering	$5.65 per Common Share

The Underwriters may over-allocate a number of Common Shares which does not exceed the number of Common Shares issuable upon the exercise of the Over-Allotment Option, in order to hold a short position in such securities following closing of the Offering. This over-allocation position allows the Underwriters to engage in limited market stabilization to compensate for the increased liquidity in the market following the Offering. If, following the closing of the Offering, the market price of the Common Shares is below their respective offering prices, the short position created by the over-allocation position in Common Shares may be filled through purchases in the market, creating upward pressure on the price of the Common Shares. If, following the closing of the Offering, the market price of the Common Shares is above the Offering price, the over-allocation position in Common Shares may be filled through the exercise of the Over-Allotment Option in respect of the Common Shares at the Offering price.

The Common Shares offered hereby have not been and will not be registered under the U.S. Securities Act or any state securities laws, and accordingly may not be offered or sold within the United States or to U.S. Persons except in transactions exempt from the registration requirements of the U.S. Securities Act and applicable state securities laws. The Underwriting Agreement permits the Underwriters to offer and resell the Common Shares that they have acquired pursuant to the Underwriting Agreement to qualified institutional buyers in the United States through certain of their U.S. broker-dealer affiliates pursuant to and in accordance with Rule 144A under the U.S. Securities Act. Additionally, the Underwriting Agreement provides that the Underwriters will offer and sell Common Shares outside the United States only in accordance with Regulation S under the U.S. Securities Act.

Each Underwriter has agreed that, except as permitted by the Underwriting Agreement, it will not offer, sell or deliver Common Shares (i) as part of its distribution at any time or (ii) otherwise until 40 days after the later of the commencement of the Offering and the issue date of the Common Shares or to, or for the account or benefit of, a U.S. person (other than a distributor) and that it will have sent to each dealer to which it sells Common Shares during the distribution compliance period a confirmation or other notice substantially to the following effect:

“The securities covered hereby have not been registered under the U.S. Securities Act of 1933, as amended (the “U.S. Securities Act”), and may not be offered and sold within the United States or to, or for the account or benefit of, U.S. persons (i) as part of their distribution at any time or (ii) otherwise until 40 days after the later of the commencement of the offering and the closing date, except in either case in accordance with Regulation S (or Rule 144A if available) under the U.S. Securities Act. Terms used above have the meaning given to them by Regulation S.”

Until 40 days after the commencement of the Offering, any offer or sale of the Common Shares offered hereby within the United States or to a U.S. Person by any dealer (whether or not participating in the Offering) may violate the registration requirements of the U.S. Securities Act unless such offer or sale is made in accordance with an available exemption under the U.S. Securities Act.

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The Underwriting Agreement also provides that the Corporation will indemnify the Underwriters and their directors, officers, employees and agents against certain liabilities, including civil liabilities under Canadian provincial securities legislation, or will contribute to payments the Underwriters may be required to make in respect thereof.

The TSX has conditionally approved the listing of the Common Shares issuable under the Offering, including the Over-Allotment Option. Listing will be subject to the Corporation fulfilling all of the listing requirements of the TSX on or before January 11, 2012.

RISK FACTORS

An investment in the Common Shares is subject to certain risks. In addition to the risks described herein, reference is made to the section entitled “Risk Factors” beginning at page 48 of the AIF dated March 31, 2011, which is incorporated herein by reference.

Discretion in the Use of Proceeds

Management will have discretion concerning the use of proceeds of the Offering as well as the timing of their expenditures. As a result, investors will be relying on the judgment of management as to the application of the proceeds of the Offering. Management may use the net proceeds of the Offering in ways that an investor may not consider desirable. The results and effectiveness of the application of the proceeds are uncertain. If the proceeds are not applied effectively, the Corporation’s results of operations may suffer.

Future Sales or Issuances of Securities

The Corporation may sell additional Common Shares or other securities in subsequent offerings. The Corporation may also issue additional securities to finance future activities. The Corporation cannot predict the size of future issuances of securities or the effect, if any, that future issuances and sales of securities will have on the market price of the Common Shares. Sales or issuances of substantial numbers of Common Shares, or the perception that such sales could occur, may adversely affect prevailing market prices of the Common Shares. With any additional sale or issuance of Common Shares, investors will suffer dilution to their voting power and the Corporation may experience dilution in its earnings per share.

Pension

Granite State and EnergyNorth both have defined benefit pension plans. The costs of providing defined benefit pension plans are dependent upon a number of factors, such as the rates of return on plan assets, discount rates used to measure pension liabilities, actuarial gains and losses, future government regulation and our contributions made to the plans. Without sustained growth in the pension plan investments over time to increase the value of our plan assets, and depending upon the other factors impacting our costs as listed above, we could experience net asset, expense and funding volatility. This volatility could have a material effect on our earnings and cash flows.

Natural Gas Distribution

The acquisition of EnergyNorth represents the first natural gas distribution utility for the Corporation and as such presents certain risks that are specific to natural gas utilities. The more significant additional risk factors for a natural gas distribution utility include the following:

• Regulated natural gas distribution utilities are generally economically stable and are not significantly affected in the short-term by changing commodity prices. However, the businesses can be negatively affected in the long-term by sustained downturns in the economy or long-term conservation efforts, which could affect long-term demand and market prices for natural gas.

• Most revenues are based on regulated tariff rates, which include the recovery of certain fuel costs. However, lower overall economic output would cause a decline in the volume of natural gas distributed resulting in lower earnings and cash flows.

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• The lack of availability of natural gas resources may cause customers to seek alternative energy resources, which could materially adversely affect revenues, earnings and cash flows.

• The natural gas distribution business is dependent on the continued availability of natural gas production and reserves. Lower prices for natural gas over the long term could affect the long term supply of natural gas causing customers to seek alternative energy resources, thereby reducing their reliance on our services, which in turn would materially adversely affect our revenues, earnings and cash flows.

• Natural gas distribution is subject to extensive regulation that affects operations and costs.

• A significant portion of growth in the natural gas distribution business is accomplished through the construction of distribution lines as well as the expansion of existing facilities. Construction of these facilities is subject to various regulatory, development, operational and market risks, including: the ability to obtain necessary approvals and permits by regulatory agencies on a timely basis and on acceptable terms; the availability of skilled labor, equipment, and materials to complete expansion projects; potential changes in federal, state and local statutes and regulations, including environmental requirements, that may prevent a project from proceeding or increase the anticipated cost of the project; impediments on our ability to acquire rights-of-way or land rights on a timely basis and on acceptable terms; the ability to construct projects within anticipated costs, including the risk of cost overruns resulting from inflation or increased costs of equipment, materials or labor, weather, geologic conditions or other factors beyond our control, that may be material; and general economic factors that affect the demand for natural gas infrastructure. Any of these risks could prevent a project from proceeding, delay its completion or increase its anticipated cost. As a result, new facilities may not achieve their expected investment return, which could adversely affect earnings, financial position and cash flows.

• The distribution of natural gas involves numerous risks that may result in accidents or otherwise affect operations. There are a variety of hazards and operating risks inherent in natural gas distribution activities, such as leaks, explosions and mechanical problems that could cause substantial financial losses. In addition, these risks could result in significant injury, loss of human life, significant damage to property, environmental pollution and impairment of operations, any of which could result in substantial losses. Natural gas distribution lines are often located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas.

• The enactment of future climate change legislation could result in increased operating costs and delays in obtaining necessary permits for our capital projects. In the United States, climate change laws and regulations are evolving at state, regional and federal levels. Some assets and operations could be affected either directly or indirectly by eventual mandatory GHG programs; however, the timing and specific policy objectives in many jurisdictions, including at the federal level, remain uncertain.

Emera Subscription Receipts

A portion of the financing contemplated for the Corporation’s acquisition of Granite State and EnergyNorth is from the sale of Common Shares to Emera. In connection with such acquisition, the Company has issued 12,000,000 subscription receipts to Emera for an aggregate subscription price of $60 million and has in return received a promissory note from Emera as payment for the subscription receipts. The subscription receipts are exchangeable for Common Shares on a one-for-one basis, and the promissory note becomes due and payable, when all conditions to completing the acquisition (including certain regulatory approvals) have been satisfied.

The issuance of Common Shares to Emera, however, is subject to certain regulatory approvals. Failure to obtain the necessary approvals for the sale of Common Shares in a timely manner, or at all, could result in a delay in the receipt of funds from the sale of Common Shares to Emera requiring the Corporation to obtain that portion of the financing for the acquisitions from other sources which may not be on terms equivalent to the sale of common stock agreed to with Emera.

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Regulatory Approval of Transactions

The Corporation has entered into agreements with respect to the acquisitions of Granite State and EnergyNorth, the remaining interest in Calpeco, the Midwest Gas Utilities and an interest in certain of First Wind’s northeast wind energy projects, which acquisitions all require certain discrete regulatory approvals. There can be no certainty as to when or if all the regulatory approvals will be obtained and therefore whether certain of the transactions will close in a timely manner or at all. In addition there can be no certainty that the regulatory approvals will not contain conditions imposed by the regulator that are not anticipated by the Corporation at this time. If conditions imposed by the regulator for any particular acquisition are too onerous and materially affect the rates of return that are able to be earned by the Corporation from the acquisition, the Corporation may be entitled to terminate that particular purchase and sale agreement and not complete that particular acquisition. See “Algonquin Power & Utilities Corp. – Recent Developments – Acquisitions of Granite State and EnergyNorth” “– Acquisition of 100% Ownership Interest of the California Utility”, “–Utility Acquisitions by Liberty Utilities” and “– Acquisition of an Interest in First Wind’s Northeast Projects”.

RELATIONSHIP BETWEEN THE CORPORATION AND CERTAIN UNDERWRITERS

BMO Nesbitt Burns Inc., CIBC World Markets Inc., National Bank Financial Inc. and TD Securities Inc. are each, directly or indirectly, a wholly-owned or majority-owned subsidiary of a Canadian chartered bank which is a lender to APCo (the “lenders”) under the APCo Senior Credit Facility. In addition, the Canadian chartered bank affiliate of BMO Nesbitt Burns Inc. has provided APCo with a fixed for floating interest rate swap. Accordingly, the Corporation may be considered to be a connected issuer of each of these Underwriters under applicable securities legislation. The net proceeds of the Offering will be used by Algonquin to enable APCo, among other things, to repay approximately $12 million of existing indebtedness under the APCo Senior Credit Facility and for general corporate purposes.

As at October 12, 2011, approximately $12 million was owed to the lenders under the APCo Senior Credit Facility. APCo is in compliance with all material terms of the agreements governing the APCo Senior Credit Facility and none of the lenders has waived any material breach by APCo of such agreements since their execution. Neither the financial position of APCo nor the value of the security under the APCo Senior Credit Facility has changed substantially and adversely since the indebtedness under such facility was incurred. The indebtedness under the APCo Senior Credit Facility is secured by a general charge over all of the assets of APCo.

The decision to distribute the Common Shares offered hereby and the determination of the terms of the distribution were made through negotiations primarily between Algonquin and Scotia Capital Inc. and BMO Nesbitt Burns Inc. on their own behalf and on behalf of the other Underwriters. The lenders under the APCo Senior Credit Facility did not have any involvement in such decision or determination, but have been advised of the issuance and the terms thereof. As a consequence of the Offering, each of BMO Nesbitt Burns Inc., CIBC World Markets Inc., National Bank Financial Inc. and TD Securities Inc. will receive its share of the Underwriters’ fee and each of the lenders will receive a portion of the proceeds from the Offering as a repayment of outstanding indebtedness under the APCo Senior Credit Facility which will then be available to be drawn by APCo, as required. See “Use of Proceeds”.

AUDITORS AND REGISTRAR AND TRANSFER AGENT

The auditors of the Corporation are KPMG LLP, Chartered Accountants, Bay Adelaide Centre, 333 Bay Street, Suite 4600, Toronto, Ontario, M5H 2S5.

The registrar and transfer agent for the Common Shares is CIBC Mellon Trust Company at its principal office in Toronto, Ontario.

INTERESTS OF EXPERTS

Certain legal matters in connection with the Offering will be passed upon on behalf of the Corporation by Blake, Cassels & Graydon LLP and on behalf of the Underwriters by Cassels Brock & Blackwell LLP. As at the date hereof, partners and associates of Blake, Cassels & Graydon LLP, as a group, beneficially owned, directly or indirectly, less than 1% of the outstanding Common Shares, respectively, and partners and associates of Cassels Brock & Blackwell LLP, as a group, beneficially owned, directly or indirectly, less than 1% of the outstanding Common Shares, respectively.

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KPMG LLP, auditors of the Corporation, confirms that it is independent within the meaning of the Rules of Professional Conduct of the Institute of Chartered Accountants of Ontario.

PricewaterhouseCoopers LLP, auditors of Granite State and EnergyNorth, two companies that constitute a significant probable acquisition of the Corporation, confirms that it has complied with the U.S. Securities and Exchange Commission’s rules on auditor independence.

PURCHASERS’ STATUTORY RIGHTS

Securities legislation in certain of the provinces of Canada provides purchasers with the right to withdraw from an agreement to purchase securities. This right may be exercised within two business days after receipt or deemed receipt of a prospectus and any amendment. In several of the provinces, the securities legislation further provides a purchaser with remedies for rescission or, in some jurisdictions, revisions of the price or damages if the prospectus and any amendment contains a misrepresentation or is not delivered to the purchaser, provided that the remedies for rescission, revision of the price or damages are exercised by the purchaser within the time limit prescribed by the securities legislation of the purchaser’s province. The purchaser should refer to any applicable provisions of the securities legislation of the purchaser’s province for the particulars of these rights or consult with a legal advisor.

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AUDITORS’ CONSENT

To: The Directors of Algonquin Power & Utilities Corp.

We have read the short form prospectus of Algonquin Power & Utilities Corp. (the “Corporation”) dated October 20, 2011 relating to the distribution of 15,100,000 Common Shares of the Corporation. We have complied with Canadian generally accepted standards for an auditor’s involvement with offering documents.

We consent to the incorporation by reference in the above mentioned short form prospectus of our report to the shareholders of the Corporation on the consolidated balance sheets of the Corporation as at December 31, 2010 and 2009 and the consolidated statements of operations, deficit, comprehensive income/(loss) and accumulated other comprehensive income/(loss), and cash flows for the years ended December 31, 2010 and 2009. Our report is dated March 3, 2011.

	(Signed) KPMG LLP
Toronto, Canada	Chartered Accountants,
October 20, 2011	Licensed Public Accountants

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APPENDIX A

HISTORICAL FINANCIAL STATEMENTS OF GRANITE STATE AND ENERGYNORTH AND PRO FORMA FINANCIAL STATEMENTS

1. Financial statements of EnergyNorth for the years ended March 31, 2011 and March 31, 2010 (audited).

2. Financial statements of EnergyNorth for the quarters ended March 31, 2011 and March 31, 2010 (unaudited).

3. Financial statements of EnergyNorth for the quarters ended June 30, 2011 and June 30, 2010 (unaudited).

4. Financial statements of Granite State for the years ended March 31, 2011 and March 31, 2010 (audited).

5. Financial statements of Granite State for the quarters ended March 31, 2011 and March 31, 2010 (unaudited).

6. Financial statements of Granite State for the quarters ended June 30, 2011 and June 30, 2010 (unaudited).

7. Pro forma consolidated financial statements of the Corporation for the year ended December 31, 2010 and for the six months period ending June 30, 2011 (unaudited).

F-1

EnergyNorth Natural Gas, Inc.

d/b/a

National Grid NH

Financial Statements

For the years ended March 31, 2011 and March 31, 2010

ENERGYNORTH NATURAL GAS, INC.

TABLE OF CONTENTS

	Page No.
Report of Independent Auditors		2
Balance Sheets		3
March 31, 2011 and March 31, 2010
Statements of Income		4
Years Ended March 31, 2011 and March 31, 2010
Statements of Cash Flows		5
Years Ended March 31, 2011 and March 31, 2010
Statements of Comprehensive Income		6
Years Ended March 31, 2011 and March 31, 2010
Notes to Financial Statements		7

Report of Independent Auditors

To the Stockholder and Board of Directors of

EnergyNorth Natural Gas, Inc.:

In our opinion, the accompanying balance sheets and the related statements of income, comprehensive income and cash flows present fairly, in all material respects, the financial position of EnergyNorth Natural Gas, Inc. at March 31, 2011 and March 31, 2010, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes 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. We believe that our audits provide a reasonable basis for our opinion.

EnerqyNorth Natural Gas, Inc. engages in significant transactions with affiliates.

August 30, 2011

PricewaterhouseCoopers LLP, 300 Madison Avenue, New York, NY 10017

T: (646) 471 3000, F: (646) 471 8320, www.pwc.com/us

ENERGYNORTH NATURAL GAS, INC.

BALANCE SHEETS

	March 31,
(in thousands of dollars, except per share and number of shares data)	2011			2010
ASSETS
Current assets
Accounts receivable	$	29,691		$	22,397
Allowance for doubtful accounts		(4,578	)		(3,642	)
Unbilled revenues		9,475			8,098
Gas in storage, at average cost		7,670			13,495
Derivative contracts		75			2
Regulatory assets		2,625			8,879
Current deferred income tax assets		3,985			3,211
Prepaid and other current assets		299			2,708
Total current assets		49,242			55,148
Property, plant, and equipment, net		247,979			241,852
Deferred charges
Regulatory assets		68,596			60,027
Goodwill		2,115			96,818
Derivative contracts		13			—
Other deferred charges		13,642			11,424
Total deferred charges		84,366			168,269
Total assets	$	381,587		$	465,269
LIABILITIES AND CAPITALIZATION
Current liabilities
Accounts payable	$	8,633		$	9,651
Taxes accrued		675			—
Customer deposits		896			340
Interest accrued		126			429
Regulatory liabilities		75			2
Current postretirement benefits		282			275
Derivative contracts		1,188			5,891
Other current liabilities		772			571
Total current liabilities		12,647			17,159
Deferred credits and other liabilities
Regulatory liabilities		29,303			29,491
Asset retirement obligations		956			902
Deferred income tax liabilities		56,224			51,697
Postretirement benefits and other reserves		3,876			4,428
Environmental remediation costs		59,807			48,007
Derivative contracts		206			626
Other deferred liabilities		3,296			3,017
Total deferred credits and other liabilities		153,668			138,168
Capitalization
Common stock, ($25 per share, 120,000 issued and outstanding)		3,000			3,000
Additional paid-in capital		291,767			295,723
Retained earnings		(79,269	)		11,599
Accumulated other comprehensive loss		(226	)		(380	)
Total shareholder’s equity		215,272			309,942
Total liabilities and capitalization	$	381,587		$	465,269

The accompanying notes are an integral part of these financial statements.

3

ENERGYNORTH NATURAL GAS, INC.

STATEMENTS OF INCOME

	Years Ended March 31,
(in thousands of dollars)	2011			2010
Operating revenues	$	138,343		$	141,571
Operating expenses
Gas purchased for resale		85,311			94,975
Operations and maintenance		26,372			25,685
Impairment of goodwill		94,703			—
Depreciation and amortization		9,117			9,205
Other taxes		5,838			5,022
Total operating expenses		221,341			134,887
Operating income		(82,998	)		6,684
Other income and (deductions)
Interest on long-term debt		(331	)		(339	)
Other interest, including affiliate interest		(4,338	)		(5,303	)
Other income		284			930
Total other deductions		(4,385	)		(4,712	)
Income (loss) before income taxes		(87,383	)		1,972
Income taxes
Current		(519	)		(3,007	)
Deferred		4,004			4,135
Total income taxes		3,485			1,128
Net income (loss)	$	(90,868	)	$	844

The accompanying notes are an integral part of these financial statements.

4

ENERGYNORTH NATURAL GAS, INC.

STATEMENTS OF CASH FLOWS

	Years Ended March 31,
(in thousands of dollars)	2011			2010
Operating activities:
Net income	$	(90,868	)	$	844
Adjustments to reconcile net income to net cash provided by operating activities
Impairment of goodwill		94,703			—
Depreciation and amortization		9,117			9,205
Provision for deferred income taxes		4,004			4,135
Net pension and other postretirement expense		2,428			3,087
Net environmental payments		(752	)		(1,355	)
Changes in operating assets and liabilities:
Accounts receivable, net		(7,735	)		6,782
Gas in storage		5,825			612
Accounts payable and accrued expenses		(15,794	)		(16,565	)
Prepaid taxes and accruals		2,833			(2,536	)
Other, net		(3,761	)		(4,209	)
Net cash change in operating activities		—			—
Net change in cash and cash equivalents		—			—
Cash and cash equivalents, beginning of year		—			—
Cash and cash equivalents, end of year	$	—		$	—
Supplemental information:
Interest incurred	$	4,642		$	4,642
Taxes paid	$	3,605		$	12,655
Non-cash transactions:
Capital expenditures (net) funded by non-cash capital contributions	$	(13,269	)	$	(17,177	)
Derivative margin calls	$	—		$	2,490

The accompanying notes are an integral part of these financial statements.

5

ENERGYNORTH NATURAL GAS, INC.

STATEMENTS OF COMPREHENSIVE INCOME

	Years Ended March 31,
(in thousands of dollars)	2011			2010
Net income	$	(90,868	)	$	844
Other comprehensive income, net of taxes:
Unrealized (losses) gains on investments		(34	)		30
Change in pension and other postretirement obligations		118			(71	)
Reclassification adjustment for gains included in net income		70			109
Change in other comprehensive income		154			68
Total comprehensive income	$	(90,714	)	$	912
Related tax expense (benefit):
Unrealized gains (losses) on investments	$	19		$	(17	)
Change in pension and other postretirement obligations		(80	)		49
Reclassification adjustment for losses included in net income		(47	)		(74	)
Total tax benefit	$	(108	)	$	(42	)

The accompanying notes are an integral part of these financial statements.

6

NOTES TO FINANCIAL STATEMENTS

Note 1. Summary of Significant Accounting Policies

A. Nature of Operations

EnergyNorth Natural Gas, Inc. d/b/a National Grid NH (the “Company”, “we”, “us” and “our”), is a regulated natural gas utility providing natural gas distribution services to approximately 85,350 customers.

The Company is an indirect subsidiary of National Grid New England LLC and an indirectly-owned subsidiary of KeySpan Corporation (“KeySpan”). KeySpan is a wholly-owned subsidiary of National Grid USA (“NGUSA”), a public utility holding company with regulated subsidiaries engaged in the generation of electricity and the transmission, distribution and sale of both natural gas and electricity. NGUSA is an indirectly-owned subsidiary of National Grid plc, a public limited company incorporated under the laws of England and Wales.

On December 8, 2010, NGUSA and Liberty Energy Utilities Co. (“Liberty Energy”), a subsidiary of Algonquin Power & Utilities Corp., entered into a stock purchase agreement (“SPA”) which was subsequently amended and restated on January 21, 2011, pursuant to which NGUSA will sell and Liberty Energy will purchase all of the common stock of the Company. The parties have filed the necessary federal and state regulatory approvals that will be required to consummate the transaction with the Federal Energy Regulatory Commission and the New Hampshire Public Utilities Commission (“NHPUC”), respectively. The regulatory approval process is expected to be completed during the year ended March 31, 2012.

B. Basis of Presentation

The Company’s accounting policies conform to accounting principles generally accepted in the United States of America (“GAAP”), including the accounting principles for rate-regulated entities, and are in accordance with the accounting requirements and ratemaking practices of the applicable regulatory authorities.

The accounts of the Company are maintained in accordance with the Uniform System of Accounts prescribed by regulatory bodies having jurisdiction.

The preparation of 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 assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

C. Accounting for the Effects of Rate Regulation

The New Hampshire Public Utilities Commission (“NHPUC”) provides the final determination of the rates we charge our customers. In certain cases, the action of NHPUC would result in an accounting treatment different from that used by non-regulated companies to determine the rates we charge our customers. In this case, the Company is required to defer the recognition of costs (a Regulatory Asset) or the recognition of obligations (a Regulatory Liability) if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates.

In the event the Company determines that its net regulatory assets are not probable of recovery, the Company would be required to record an after-tax, non-cash charge against income for any remaining regulatory assets and liabilities, the resulting charge could be material to the Company’s reported financial condition and results of operations.

D. Revenue Recognition

Customers are generally billed on a monthly basis. Revenues include unbilled amounts related to the estimated gas usage that occurred from the most recent meter reading to the end of each month. Substantially all of the Company’s revenues are derived from sales to firm gas customers.

7

The Cost of Gas Adjustment Factor (“CGAF”) requires the Company to semi-annually adjust, or based on certain criteria, to monthly adjust rates for firm gas sales in order to track changes in the cost of gas distributed, with an annual adjustment of subsequent rates made for any over or under recovery of actual costs incurred. As a result, the cost of firm gas that has been distributed, but is unbilled at the end of a period, is deferred to the period in which the gas is billed to customers. The Company recovers the gas cost portion of bad debt write-offs through the CGAF. In addition, through a Local Distribution Adjustment Factor (“LDAF”), the Company is allowed to recover the amortization of environmental response costs associated with former manufactured gas plant (“MGP”) sites, costs related to its various energy efficiency programs and other specified costs from our firm sales and transportation customers. The Company records amounts recoverable under LDAF as revenue when billed to customers.

The gas distribution business is influenced by seasonal weather conditions. Annual revenues are principally realized during the heating season (November through April) as a result of the large proportion of heating sales in these months. Accordingly, results of operations are most favorable in the first calendar quarter of the Company’s fiscal year, followed by the fourth calendar quarter. Operating losses are generally incurred in the second and third calendar quarters.

During the year ended March 31, 2011, 60% of the Company’s revenue from the sale and delivery of gas was derived from residential customers, 38% from commercial customers and 2% from industrial customers. During the year ended March 31, 2010, 56% of the Company’s revenue from the sale and delivery of gas was derived from residential customers, 42% from commercial customers and 2% from industrial customers.

E. Goodwill

Goodwill represents the excess of purchase price of a business combination over the fair value of the tangible and intangible assets acquired, net of the fair value of liabilities assumed and the fair value of any non-controlling interest in the acquiree. In accordance with the current accounting guidance for goodwill and other intangible assets, the Company tests goodwill for impairment on an annual basis and on an interim basis when certain events or circumstances exist.

The goodwill impairment analysis is comprised of two steps. In the first step, the Company compares the fair value of each reporting unit to its carrying value. The Company considers both an income-based approach using projected discounted cash flows and a market-based approach using valuation multiples of comparable companies to determine fair value. The Company’s estimate of fair value of each reporting unit is based on a number of subjective factors including: (i) the appropriate weighting of valuation approaches (income-based approach and market-based approach), (ii) estimates of the future revenue and cash flows, (iii) discount rate for estimated cash flows, (iv) selection of peer group companies for the market-based approach, (v) assumed terminal value including the growth rate, and (vi) control premium.

If the fair value of the reporting unit exceeds the carrying value of the net assets assigned to that unit, goodwill is not considered impaired and no further analysis is required to be performed. If the carrying value of the net assets assigned to the reporting unit exceeds the fair value, then a second step is performed to determine the implied fair value of the reporting unit’s goodwill. If the carrying value of a reporting unit’s goodwill exceeds its implied fair value, then an impairment charge equal to the difference is recorded.

Prior to the year ended March 31, 2011, the Company utilized a discounted cash flow approach incorporating its most recent business plan forecasts together with a projected terminal year calculation in the performance of the annual goodwill impairment test. Critical assumptions used in the Company’s analysis included a discount rate of 5.9% and a terminal year growth rate of 2.4% based upon expected long-term average growth rates. Within its calculation of forecasted returns, the Company made certain assumptions with respect to the amount of pension and environmental costs to be recovered in future periods. Should the Company not benefit from improved rate relief in these areas, the result could be a reduction in fair value of the Company, which in turn could give rise to an impairment of goodwill. The Company’s forecasts assumed long-term recovery and rate of returns that are in line with historical levels within the utility industry. The resulting fair value of the annual analysis determined that no adjustment of the goodwill carrying value was required at March 31, 2010. For the year ended March 31, 2011, the potential sale of the Company, subject to regulatory approval was a triggering event and based on the impairment analysis performed at that time, the Company recorded an impairment charge of $94.7 million, as discussed in detail in note 4, Goodwill.

8

F. Gas in Storage

Gas in storage is recorded initially at average weighted cost and is expensed when delivered to customers as gas purchased for resale. In accordance with current accounting guidance, the Company is required to re-value storage at the lower of cost or market. However, based on the rate orders in effect as issued by the NHPUC, the Company is permitted to pass through the cost of gas purchased for resale directly to the rate payers along with any applicable authorized delivery surcharge adjustments. Therefore, the value of gas in storage never falls below the cost to the Company. Gas costs passed through to the rate payers are subject to periodic regulatory approval and are reported periodically to the NHPUC.

G. Property, Plant and Equipment

Utility gas property is stated at original cost of construction. The cost of additions to property, plant and equipment and replacements of retirement units of property are capitalized. Costs include direct material, labor, overhead and allowance for funds used during construction (“AFUDC”). Replacement of minor items of utility plant and the cost of current repairs and maintenance are charged to expense. Whenever utility plant is retired, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation.

H. Income and Other Taxes

Federal and state income taxes are recorded under the current accounting provisions for the accounting and reporting of income taxes. Income taxes have been computed utilizing the asset and liability approach that requires the recognition of deferred tax assets and liabilities for the tax consequences of temporary differences by applying enacted statutory tax rates applicable to future years to differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities.

Deferred income taxes reflect the tax effect of net operating losses, capital losses and general business credit carryforwards and the net tax effects of temporary differences between the carrying amount of assets and liabilities for financial statement and income tax purposes, as determined under enacted tax laws and rates. The financial effect of changes in tax laws or rates is accounted for in the period of enactment. Deferred investment tax credits are amortized over the useful life of the underlying property. Additionally, the Company follows the current accounting guidance relating to uncertainty in income taxes which applies to all income tax positions reflected on the Company’s balance sheets that have been included in previous tax returns or are expected to be included in future tax returns.

Other taxes in the accompanying statements of income primarily includes excise tax, property tax and payroll tax. We report our collections and payments of excise taxes on a gross basis.

I. Employee Benefits

The Company applies the provisions of the Financial Accounting Standards Board (“FASB”) accounting guidance related to the accounting for defined benefit postretirement plans which requires employers to fully recognize all postretirement plans’ funded status on the balance sheets as a net liability or asset and required an offsetting adjustment to accumulated other comprehensive income in stockholders’ equity or in the case of rate-regulated entities such as the Company in regulatory assets upon implementation. Consistent with past practice and as required by current guidance, the Company values its other postretirement assets using the year end market value of those assets. Benefit obligations are also measured at year end.

J. Derivatives

The Company participates in gas trading at National Grid. The Company employs derivative instruments to hedge a portion of its exposure to commodity price risk. Whenever hedge positions are in effect, the Company is exposed to credit risks in the event of non-performance by counter-parties to derivative contracts, as well as non-performance by the counter-parties of the transactions against which they are hedged. The Company believes the credit risk related to derivative instruments is no greater than that associated with the primary commodity contracts that they hedge.

9

Firm Gas Sales Derivative Instruments

The Company utilizes derivative financial instruments to reduce the cash flow variability associated with the purchase price for a portion of future natural gas purchases. Our strategy is to minimize fluctuations in firm gas sales prices to our regulated firm gas sales customers. Because these derivative instruments are being employed to reduce the variability of the purchase price of natural gas to be sold to regulated firm gas sales customers, the accounting for these derivative instruments is subject to the current accounting guidance on the accounting for the effects of rate regulation. Therefore, changes in the market value of these derivatives have been recorded as a regulatory asset or regulatory liability on the balance sheets. Gains or losses on the settlement of these contracts are initially deferred and then refunded to or collected from our firm gas sales customers during the appropriate winter heating season consistent with regulatory requirements.

Physically-Settled Commodity Derivative Instruments

Certain of the Company’s contracts for the physical purchase of natural gas are derivatives as defined by current accounting guidance. As such, these contracts are recorded on the balance sheets at fair market value. However, because such contracts were executed for the purchases of natural gas that is sold to regulated firm gas sales customers, and pursuant to the requirements for accounting for the effects of rate regulation, changes in the fair market value of these contracts are recorded as a regulatory asset or regulatory liability on the balance sheets.

K. Fair Value Measurements

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The following is the fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:

Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that a company has the ability to access as of the reporting date

Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data

Level 3 — unobservable inputs, such as internally-developed forward curves and pricing models for the asset or liability due to little or no market activity for the asset or liability with low correlation to observable market inputs

L. Recent Accounting Pronouncements

Prospective Accounting Pronouncements

In the preceding twelve months, the FASB has issued numerous updates to GAAP. The Company has evaluated various guidelines and has deemed them as not applicable based on its nature of operations or has implemented the new standards. A discussion of the more significant and relevant updates is as follows:

In June 2011, the FASB issued accounting guidance that eliminated the option to present the components of other comprehensive income as part of the statement of changes in stockholders’ equity. This update seeks to improve financial statement users’ ability to understand the causes of an entity’s change in financial position and results of operations. The Company is now required to either consecutively present the statement of income and statement of comprehensive income in a single continuous statement or in two separate, but consecutive statements of net income and other comprehensive income on the face of the financial statements. This update does not change the items that are reported in other comprehensive income or any reclassification of items to net income. Additionally, the update does not change an entity’s option to present components of other comprehensive income net of or before related tax effects. This guidance is effective for non-public companies for fiscal years ending after December 15, 2012, and for interim and annual periods thereafter, and it is to be applied retrospectively. Early adoption is permitted. The Company does not expect adoption of this guidance to have an impact on the Company’s financial position, results of operations or cash flows.

10

In April 2011, the FASB issued accounting guidance that substantially amended existing guidance with respect to the fair value measurement topic (“the Topic”). The guidance seeks to amend the Topic in order to achieve common fair value measurement and disclosure requirements in GAAP and International Financial Reporting Standards. Consequently, the guidance changes the wording used to describe many of the requirements in GAAP for measuring fair value and for disclosing information about fair value measurements as well as changing specific applications of the Topic. Some of the amendments clarify the FASB’s intent about the application of existing fair value measurement requirements. Other amendments change a particular principle or requirement for measuring fair value or for disclosing information about fair value measurements including, but not limited to, fair value measurement of a portfolio of financial instruments, fair value measurement of premiums and discounts and additional disclosures about fair value measurements. This guidance is effective for financial statements issued for annual periods beginning after December 15, 2011. The early adoption of this guidance for non-public companies is permitted but only for interim periods beginning after December 15, 2011. The Company is currently determining the potential impact of the guidance on its financial position, results of operations and cash flows.

In December 2010, the FASB issued an accounting update that modified the goodwill impairment procedures necessary for entities with zero or negative carrying value. The FASB created this guidance to require entities to complete Step 2 of the impairment test, which requires the entity to assess whether or not it was likely that impairment existed throughout the period. To do this, an entity should consider whether there were adverse qualitative factors throughout the period that would contribute to impairment. This update is effective for non-public companies for fiscal years and interim periods beginning after December 15, 2011. The Company does not expect the adoption of this guidance to have an impact on the Company’s financial position, results of operations or cash flows.

Recently Adopted Accounting Pronouncements

In March 2010, the FASB issued updated guidance that provides for scope exceptions applicable to financial instrument contracts with embedded credit derivative features. This FASB guidance is effective for financial statements issued for interim periods beginning after June 15, 2010. On an ongoing basis, the Company evaluates new and existing transactions and agreements to determine whether they are derivatives, or have provisions that meet the characteristics of embedded derivatives. Those transactions designated for any of the elective accounting treatments for derivatives must meet specific, restrictive criteria, both at the time of designation and on an ongoing basis. None of the financial instrument contracts or credit agreements the Company has entered were identified and designated as meeting the criteria for derivative or embedded derivative treatment. The adoption of this guidance did not have an impact on the Company’s financial position, results of operations or cash flows.

In January 2010, the FASB issued an amendment to the accounting guidance for fair value measurements that will provide for additional disclosures about (a) the different classes of assets and liabilities measured at fair value, (b) the valuation techniques and inputs used, (c) the activity in Level 3 fair value measurements, and (d) the transfers between Levels 1, 2, and 3. This FASB guidance is effective for financial statements issued for interim and annual periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years. The adoption of this guidance did not have an impact on the Company’s financial position, results of operations or cash flows.

In June 2009, the FASB issued an amendment to the accounting and disclosure requirements for the consolidation of variable interest entities. The objective of the amendment is to improve financial reporting by enterprises involved with variable interest entities and to provide more relevant and reliable information to users of financial statements. The amendment requires an enterprise to perform an analysis to determine whether the enterprise’s variable interest or interests give it a controlling financial interest in a variable interest entity. The new requirements shall be effective as of the beginning of each reporting entity’s first annual reporting period that begins after November 15, 2009. The adoption of this guidance did not have an impact on the Company’s consolidated financial statements.

In May 2009, the FASB issued accounting guidance establishing the general standards of accounting for the disclosure of events that occur after the balance sheet date but before the financial statements are issued or are available to be issued. In particular, this FASB guidance requires enhanced disclosures about (a) events or transactions that may occur for potential recognition or disclosure in the financial statements in the period after the balance sheet date, (b) circumstances under which an entity should recognize such events, and (c) date through which an entity has evaluated subsequent events, including the basis for that date, and whether that date represents the date the financial statements were issued or available to be issued. The FASB guidance is effective for financial statements issued for interim and annual periods ending after June 15, 2009. The Company adopted this standard for the reporting period beginning April 1, 2010 and noted no impact on the Company’s financial position, results of operations or cash flows due to the adoption of this standard.

11

Note 2. Rates and Regulatory

The following regulatory assets and regulatory liabilities were reflected on the balance sheets as of March 31, 2011 and March 31, 2010:

	March 31,
(in thousands of dollars)	2011			2010
Regulatory assets – current
Postretirement benefit costs	$	1,033		$	1,033
Derivative contracts		1,188			5,891
Other		404			1,955
Total current regulatory assets		2,625			8,879
Regulatory assets – non-current
Postretirement benefit costs		5,596			6,628
Environmental costs		61,462			48,893
Derivative contracts		206			626
Other		1,332			3,880
Total non-current regulatory assets		68,596			60,027
Total regulatory assets		71,221			68,906
Regulatory liabilities - current
Derivative liabilities		(75	)		(2	)
Total current regulatory liabilities		(75	)		(2	)
Regulatory liabilities - non-current
Derivative liabilities		(13	)		—
Removal costs recovered and other		(29,290	)		(29,491	)
Total non-current regulatory liabilities		(29,303	)		(29,491	)
Total regulatory liabilities		(29,378	)		(29,493	)
Net regulatory assets	$	41,843		$	39,413

The regulatory items above are not included in the utility rate base. The Company records carrying charges, as appropriate, on the regulatory items for which cash expenditures have been made and are subject to recovery or for which cash has been collected and is subject to refund. Carrying charges are not recorded on items for which expenditures have not yet been made. The Company anticipates recovering these costs in its gas rates concurrently with future cash expenditures. If recovery is not concurrent with the cash expenditures, the Company will record the appropriate level of carrying charges. Deferred gas cost credits at March 31, 2011 and March 31, 2010 were approximately $2.6 million and $1.7 million, respectively, and are included in accounts receivable on the balance sheets.

In February 2010, the Company filed a natural gas base distribution rate case with NHPUC seeking an increase in distribution rates of $11.4 million per year. In March 2011, NHPUC approved a settlement to permanently increase the gas distribution rates by approximately $6.8 million based on an implied return on equity (“ROE”) of 9.67% and an equity ratio of 50%. The March 2011 order also approved a commodity-related bad debt recovery mechanism that adjusts for fluctuations in commodity prices. Although the Company requested pension and other post-employment benefits (“OPEB”) reconciliation mechanism and a revenue decoupling mechanism as part of the February 2010 filing, the parties could not reach consensus on these mechanisms and were therefore excluded from the settlement agreement. In May 2011, the Company presented the NHPUC Staff with documentation of rate case expenses in the amount of $1.5 million associated with the February 2010 filing. The NHPUC Staff will review the Company’s documentation and make a recommendation to the NHPUC as to the amount that should be allowed for recovery.

12

Pursuant to the NHPUC order approving the Company’s merger agreement with KeySpan, the Company is permitted to seek an annual base rate adjustment to reflect the cost of replacing cast iron and bare steel mains and services to the extent such cost exceeds $0.5 million. In June 2010 and June 2011, the Commission approved base distribution rate increases of $0.5 million effective on July 1, 2010 and July 1, 2011 of each year.

Other Regulatory Matters

In November 2008, FERC commenced an audit of NGUSA, including its service companies and other affiliates in the National Grid holding company system. The audit evaluated our compliance with: 1) cross-subsidization restrictions on affiliate transactions; 2) accounting, recordkeeping and reporting requirements; 3) preservation of records requirements for holding companies and service companies; and 4) Uniform System of Accounts for centralized service companies. The final audit report from the FERC was received in February 2011. In April 2011, NGUSA replied to the FERC and outlined its plan to address the findings in the report, which we are currently in the process of implementing. None of the findings had a material impact on the financial statements of the Company.

Note 3. Employee Benefits

Summary

The Company participates with certain other KeySpan subsidiaries in a non-contributory defined benefit plan. The postretirement benefits other than pensions (“PBOP”) plan has not been merged with other KeySpan plans and therefore, continues to remain a separate plan of the Company.

The pension plan is a defined benefit plan which provides union employees with a retirement benefit and non-union employees hired before January 1, 2011 with a retirement benefit.

Supplemental nonqualified, non-contributory executive programs provide additional defined pension benefits for certain executives.

PBOPs provide health care and life insurance coverage to eligible retired employees. Eligibility is based on age and length of service requirements and in most cases, retirees must contribute to the cost of their coverage.

Plan Assets

The target asset allocation for the benefit plans at March 31, 2011 and March 31, 2010 is as follows:

	Non-union PBOP’s						Union PBOP’s
	2011			2010			2011			2010
U.S. equities		44.5	%		44.5	%		33	%		33	%
Global equities (including U.S.)		—			—			12	%		12	%
Global tactical asset allocation		—			—			16	%		16	%
Non-U.S. equities		25.5	%		25.5	%		17	%		16	%
Fixed income		30	%		30	%		22	%		20	%
Private equity		—			—			—			3	%
		100	%		100	%		100	%		100	%

13

The percentage of the fair value of total plan assets at March 31, 2011 and March 31, 2010 is as follows:

	Non-union PBOP’s						Union PBOP’s
	2011			2010			2011			2010
U.S. equities		45	%		46	%		35	%		35	%
Global equities (including U.S.)		—			—			12	%		12	%
Global tactical asset allocation		—			—			16	%		16	%
Non-U.S. equities		25	%		24	%		16	%		17	%
Fixed income		27	%		27	%		19	%		18	%
Private equity		3	%		3	%		2	%		2	%
		100	%		100	%		100	%		100	%

Key Assumptions Used

The following weighted average assumptions were used to determine the benefit obligation and net periodic cost for the fiscal years ended March 31, 2011 and March 31, 2010:

	PBOP
	Benefit obligation						Net periodic benefit cost
	2011			2010			2011			2010
Discount rate		5.90	%		6.10	%		6.10	%		7.30	%
Expected long-term rate of return on asset Union		7.75	%		8.00	%		8.00	%		8.25	%
Non-union Health		7.50	%		6.00	%		6.00	%		6.75	%
Non-union Life		8.50	%		8.00	%		8.00	%		6.75	%
Health care cost trend rate
Medical trend rate
Pre-65		8.50	%		8.50	%		8.50	%		8.50	%
Post-65		8.00	%		8.50	%		8.50	%		9.50	%
Prescription drug trend rate		8.75	%		9.25	%		9.25	%		n/a
Ultimate rate		5.00	%		5.00	%		5.00	%		5.00	%
Year ultimate rate is reached – medical
Pre-65		2018			2017			2017			2015
Post-65		2017			2017			2017			2016
Year ultimate rate is reached – prescription		2019			2019			2019			n/a

Several assumptions affect the pension and other postretirement benefit expense and measurement of their respective obligations. The following is a description of some of those assumptions:

Benefit plan investments

KeySpan manages the Plans’ investments to minimize the long-term cost of operating the Plans, with a reasonable level of risk. Risk tolerance is determined as a result of a periodic asset/liability study which analyzes the Plans’ liabilities and funded status and results in the determination of the allocation of assets across equity and fixed income. Equity investments are broadly diversified across U.S. and non-U.S. stocks, as well as across growth, value, and small and large capitalization stocks. Likewise, the fixed income portfolio is broadly diversified across the various fixed income market segments. Small investments are also approved for private equity, real estate, and infrastructure with the objective of enhancing long-term returns while improving portfolio diversification. Investment risk and return is reviewed by an investment committee on a quarterly basis.

Expected return on assets

The estimated rate of return for various passive asset classes is based both on analysis of historical rates of return and forward looking analysis of risk premiums and yields. Current market conditions, such as inflation and interest rates, are evaluated in connection with the setting of the long-term assumption. A small premium is added for active management of both equity and fixed income securities. The rates of return for each asset class are then weighted in accordance with the actual asset allocation, resulting in a long-term return on asset rate for each plan.

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Discount rate

KeySpan selects its discount rate assumption based upon rates of return on high quality corporate bond yields in the marketplace as of each measurement date (typically each March 31st). Specifically, KeySpan uses the Hewitt Top Quartile Discount Curve along with the expected future cash flows from the KeySpan retirement plans to determine the weighted average discount rate assumption.

Pension Plans

The Company participates in the pension plans with certain other KeySpan subsidiaries. Pension plan assets are commingled and cannot be allocated to an individual company. Pension costs are allocated to the Company. The KeySpan pension plans have a net underfunded obligation of $643.9 million at March 31, 2011 and $740.2 million at March 31, 2010.

Certain current year changes in the funded status of the KeySpan plan are allocated to the Company through an intercompany payable account. Gross pension expense allocated to the Company was approximately $1.5 million and $1.7 million for the years ended March 31, 2011 and March 31, 2010, respectively.

Investment valuation

Investments are reported at fair value. Fair value is the price that would be received to sell the asset or paid to transfer the liability (an exit price) in an orderly transaction between market participants at the measurement date, not the price that would be paid to acquire the asset or received to assume the liability (an entry price). The company used valuation which maximized the use of observable inputs and minimized the use of unobservable inputs.

Following is a description of the valuation methodologies used at March 31, 2011 and March 31, 2010 for plan assets measured at fair value.

Cash and cash equivalents:

Cash and cash equivalents are valued at the investment principal plus all accrued interest. Temporary cash investment and short-term investments are valued at either the investment principal plus all accrued interest or the net asset value of shares held by the Plan at year end.

Equity and Private Equity:

Common and preferred stocks, and real estate investment trusts are valued using the official close for the active market, when available, the last trade, or bid of the ask offer price reported on that active market on which the individual securities are traded, if appropriate.

Fixed income securities:

Fixed income securities, convertible securities, collateral received from securities lending (which include corporate debt securities, municipal fixed income securities, US Government and Government agency securities) are comprised of government agency securities, government mortgage-backed securities, index linked government bonds, and state and local bonds.

Preferred securities:

Mutual funds are valued at the net asset value of shares held by the Plan at year end. Commingled equity funds, commingled special equity funds, limited partnerships, real estate, venture capital and other investments are valued using evaluations (a good faith opinion as to what a buyer in the marketplace would pay for a security–typically in an institutional round lot-in a current sale), based on proprietary models, or based on the net asset value. Index funds include investments that seek to match the return performance and characteristics of a specified index. The index funds are controlled by investment managers, which balance the funds to track the specified index. Non-US equity funds are typically invested in at least 80% foreign equity securities. Registered investment companies and common and collective trusts, and pooled separate accounts are valued at the net asset value of shares held by the Plans at year end.

15

The methods described above may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. Furthermore, while Management believes its valuation methodologies are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different fair value measurement at the reporting date.

The Company’s portion of the KeySpan Master Trust Retirement Benefits Other Than Pension is approximately 0.17% of the investments shown below for the years ended March 31, 2011 and March 31, 2010. The table depicted below sets forth by level, within the fair value hierarchy, the KeySpan Master Union Trust Plan assets for retirement benefits other than pension, at fair value as of March 31, 2011 and March 31, 2010:

March 31, 2011

(in thousand dollars)	Level 1		Level 2		Level 3		Total
Asset type
Cash and Cash Equivalents	$	1,966	$	5,266	$	—	$	7,232
Equity		129,131		179,783		24,631		333,545
Fixed Income Securities		92,768		109,910		22,538		225,216
Preferred Securities		70		—		—		70
Assets at fair value	$	223,935	$	294,959	$	47,169	$	566,063

March 31, 2010

(in thousands of dollars)	Level 1		Level 2		Level 3		Total
Asset type
Cash & Cash Equivalents	$	33,142	$	545	$	—	$	33,687
Equity		106,721		143,080		12,023		261,824
Fixed Income Securities		78,830		77,748		—		156,578
Preferred Securities		68		—		—		68
Private Equity		—		9,220		36,272		45,492
Assets at fair value	$	218,761	$	230,593	$	48,295	$	497,649

The Company’s portion of the KeySpan Master Trust Retirement Benefits Other Than Pension is approximately 0.17% of the investments shown below for the years ended March 31, 2011 and March 31, 2010. The following table sets forth a summary of changes in the fair value of the retirement benefits other than pension plan’s level 3 investments for the years ended March 31, 2011 and March 31, 2010:

March 31, 2011

(in thousand dollars)	Equity			Fixed Income Securities			Total
Balance, beginning of year	$	26,219		$	22,076		$	48,295
Realized gains/(losses)		3,482			211			3,693
Unrealized gains/(losses) at reporting date		148			2,592			2,740
Purchases, sales, issuance and settlements (net)		(5,218	)		(2,341	)		(7,559	)
Balance, end of year	$	24,631		$	22,538		$	47,169

March 31, 2010

(in thousands of dollars)	Equity			Fixed Income Securities			Preferred Securities			Private Equity			Total
Balance, beginning of year	$	36,018		$	138		$	300		$	20,524		$	56,980
Realized gains (losses)		2,593			(380	)		(255	)		779			2,737
Unrealized gains (losses) at reporting date		8,531			395			—			(861	)		8,065
Purchases, sales, issuance, and settlements (net)		(35,119	)		(153	)		(45	)		15,830			(19,487	)
Balance, end of year	$	12,023		$	—		$	—		$	36,272		$	48,295

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Risks and uncertainties

The actuarial present value of the Company’s expected postretirement benefit obligations is determined by (1) estimating future annual incurred claim costs per participant based upon historical claims data, (2) adjusting such estimates for the time value of money (through discounts for interest) and the probability of payment (by means of decrements such as those for death, disability, withdrawal or retirement) between the valuation date and the expected date of payment, and (3) then applying actuarial assumptions to the result.

Contributions to the Plan and its actuarial present value are reported based on certain assumptions pertaining to interest rates, inflation rates, and employee compensation and demographics. Due to the changing nature of these assumptions, it is at least reasonably possible that changes in these assumptions will occur in the near term and, due to the uncertainties inherent in setting assumptions, that the effect of such changes could be material to the Plan’s financial statements. The underlying investments made against the Plan contributions are subject to risks and uncertainties associated with the financial and capital markets. The most significant market risks include interest rate risk, credit risk, and investment risk.

It is also at least reasonably possible that, due to the level of risk associated with certain investment securities, changes in the values of the Plan’s underlying investment securities will occur in the near term and that such changes could materially affect the amounts reported in the statements of net assets available for benefits. The diversification of funds across asset classes and investment styles and the avoidance of significant concentration of risk in one entity, industry, or country (other than the United States) inevitably enable the tactical allocations made by the Committee to meet its objectives.

Following is a description of the related risks and uncertainties for the respective Plan asset investment:

Equity investments including common and preferred stocks, and real estate investment trusts involve the risk inherent with the issuing company on the volatility of the stock price in actively traded markets. To reduce these risks, investment allocations are typically diversified across multiple stock placements and structured to avoid significant concentrations in a single company or a particular industry.

Fixed income securities, convertible securities, collateral received from securities lending are subject to risks affecting interest rates, the credit markets, the issuing company and the underlying industry or sector it belongs to. To reduce these risks, investment allocations are typically diversified across multiple placements and structured to avoid significant concentrations in a particular company or industry.

Mutual funds, commingled equity funds, commingled special equity funds, index funds, limited partnerships, real estate, venture capital and other investments, all involve risks based on losing the invested principal (or a fraction thereof) primarily due to a fall in the net asset value (NAV) of the underlying fund. Risks typically related to the volatility in the NAV include market risk, interest risk, liquidity risk, foreign exchange risk, political and economic risk, inflation risk, and market-specific risk. To reduce these risks, investment allocations are typically diversified across multiple fund placements and structured to avoid significant concentrations in a single fund or a particular fund sector.

Plan management

General oversight and fiduciary responsibility for the KeySpan Master Trust pension and retirement benefits other than pension plans (the “Plans”) sponsored by National Grid USA Service Company, Inc. rests with the Benefits Committee and Investment Committee (the “Committee”). The operation and administration of the Plans, which includes the determination of investment allocation decisions and the power to appoint and terminate investment managers for the Plans, is controlled and managed by the Committee. The Committee meets quarterly to review tactical allocations, discuss plan performance and whenever necessary, propose changes to the investment allocation of both Plans.

Tactical allocation decisions made by the Committee aim to maintain a level and form of assets that will adequately meet expected benefit obligations to participants, maximize the long-term total return on the underlying assets within a prudent level of risk, and maintain a level of volatility that is not expected to have a material impact on the Company’s expected contribution and expense or the Plans’ ability to meet its obligations. An asset/liability study is typically conducted by the investment managers and regularly reported to the Committee to determine whether the current tactical allocation model continues to represent the appropriate balance of expected risk and reward for the Plan to meet expected liabilities.

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Postretirement Health Care Benefits

The PBOP plan has not been merged with other KeySpan plans and therefore, continues to remain a separate plan of the Company.

The net periodic postretirement health care cost for the Company’s PBOP plans for the year ended March 31, 2011 and March 31, 2010 are as follows:

	Years Ended March 31,
(in thousands of dollars)	2011			2010
Service cost-benefits earned during the year	$	7		$	7
Interest cost on benefit obligation		312			343
Expected return on plan assets		(57	)		(48	)
Amortization of prior service cost		22			70
Amortization of net actuarial loss		95			113
Total health care cost	$	379		$	485

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The following table sets forth the change in benefit obligation and plan assets and reconciliation of funded status of our health care plans and amounts recorded on the balance sheets as of March 31, 2011 and March 31, 2010:

	Years Ended March 31,
(in thousands of dollars)	2011			2010
Change in benefit obligation:
Benefit obligation at beginning of year	$	(5,539	)	$	(4,214	)
Service cost		(7	)		(7	)
Interest cost		(312	)		(343	)
Amendments		—			(92	)
Actuarial gain (loss)		117			(258	)
Benefits paid		633			357
Other		—			(982	)
Benefit obligation at end of year		(5,108	)		(5,539	)
Change in plan assets:
Fair value of plan assets at beginning of year		836			267
Actual return on plan assets		137			279
Employer contributions		610			166
Benefits paid		(633	)		(357	)
Other		—			481
Fair value of plan assets at end of year		950			836
Funded status	$	(4,158	)	$	(4,703	)
Amounts recognized in the balance sheets consist of:
Current liabilities	$	(282	)	$	(275	)
Noncurrent liabilities		(3,876	)		(4,428	)
Total	$	(4,158	)	$	(4,703	)
Amounts recognized in accumulated other comprehensive income:
Net (loss)	$	(354	)	$	(647	)
Prior service cost		—			(22	)
Total	$	(354	)	$	(669	)
Estimated amount of accumulated other comprehensive income to be recognized in next fiscal year through net periodic postretirement cost:
Net loss	$	(53	)	$	(97	)
Prior service cost		(22	)		(22	)
Total	$	(75	)	$	(119	)

A one-percentage-point increase or decrease in the assumed health care trend rate would have the following effects as of March 31, 2011:

(in thousands of dollars)	One-Percentage-Point Increase		One-Percentage-Point Decrease
Service cost plus interest cost	$	8	$	(7	)
Postretirement benefit obligation	$	115	$	(106	)

The Company does not expect to make any contributions to the PBOP plans during the year ended March 31, 2012.

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The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid in the years indicated:

(in thousands of dollars)	Gross Benefit Payments
2012	$	485
2013		495
2014		496
2015		491
2016		484
Thereafter		2,226

Workforce Reduction Program

In connection with National Grid plc’s acquisition of KeySpan, National Grid plc and KeySpan offered 673 non-union employees a voluntary early retirement offer (“VERO”) in an effort to reduce the workforce. Of the employees enrolled in the VERO, none were direct employees of the Company. Eligible employees must have been working in a targeted area as of April 13, 2007 and be at least 52 years of age with seven or more years of service as of September 30, 2007. For eligible employees who have elected to accept the VERO offer, National Grid plc and KeySpan have the right to retain that employee for up to three years before VERO payments are made. An employee who accepts the VERO offer but elects to terminate employment with National Grid plc or KeySpan prior to the three year period, without consent of National Grid plc or KeySpan, forfeits all rights to VERO payments. The VERO is completed and the Company has accrued approximately $1.3 million.

Note 4. Goodwill

At March 31, 2011, and March 31, 2010, Goodwill is as follows:

	Years Ended March 31,
(in thousands of dollars)	2011			2010
Goodwill, beginning of year	$	96,818		$	96,818
Impairment of goodwill		(94,703	)		—
Goodwill, end of year	$	2,115		$	96,818

During the third quarter of fiscal year 2011, the expectation that it was more likely than not, that the Company would be sold triggered the possible impairment of goodwill since it was determined that its carrying amount will likely not be recoverable.

The Company performed a two-step approach to assess goodwill impairment which requires the Company to first compare the estimated fair value of the Company to the carrying amount of the Company’s assets and liabilities, including its goodwill. For purposes of this test, the estimated fair value was determined to be the agreed-upon purchase price stipulated within the SPA, which was less than the carrying value of the Company, triggering the need to perform the second step of the test.

The second step of the goodwill impairment test requires comparison of the implied fair value of goodwill with the carrying amount of that goodwill. The implied fair value of goodwill is determined by assigning a fair value to all assets and liabilities, including any unrecognized intangible assets, as if the Company had been acquired in a business combination. The excess of the fair value of the Company over the amount assigned to its assets and liabilities is the implied fair value of goodwill. As a result of the second step of the test, the Company concluded that there was an impairment of its goodwill, and recorded a pre-tax impairment charge of $94.7 million for the year ended March 31, 2011.

20

Note 5. Property, Plant and Equipment

At March 31, 2011 and March 31, 2010, property, plant and equipment at cost and accumulated depreciation and amortization are as follows:

	March 31,
(in thousands of dollars)	2011			2010
Plant and machinery	$	317,134		$	304,338
Land and buildings		8,844			8,736
Assets in construction		2,383			2,556
Software and other intangibles		6,564			6,564
Total		334,925			322,194
Accumulated depreciation and amortization		(86,946	)		(80,342	)
Property, plant and equipment, net	$	247,979		$	241,852

AFUDC

The Company capitalizes AFUDC as part of construction costs. AFUDC represents an allowance for the cost of funds used to finance construction and, for the Company, includes a debt component. AFUDC is capitalized in “Property, plant and equipment” with offsetting credits to “Other interest, including affiliated interest” for the debt component. The Company is permitted to recover prudently incurred capital costs through their ultimate inclusion in rate base and in the provision for depreciation. The composite AFUDC rate for March 31, 2011 and March 31, 2010 was 2.64% and 2.74%, respectively. AFUDC capitalized during the years ended March 31, 2011 and March 31, 2010 was $0.1 million and $0.2 million, respectively.

Depreciation

Depreciation is provided on a straight-line basis at rates designed to amortize the cost of depreciable property, plant and equipment over their estimated remaining useful lives. The composite depreciation rate, expressed as a percentage of the average depreciable property in service, at March 31, 2011 and March 31, 2010 is approximately 2.53% and 2.90% respectively. The cost of repair and minor replacement and renewal of property is charged to maintenance expense.

Note 6. Income Taxes

Following is a summary of the components of federal and state income tax expense (benefit):

	Years Ended March 31,
(in thousands of dollars)	2011			2010
Components of federal and state income taxes:
Current tax expense (benefit):
Federal	$	(585	)	$	(3,096	)
State		66			89
Total current tax expense (benefit)		(519	)		(3,007	)
Deferred tax expense (benefit):
Federal		3,597			3,460
State		529			797
Total deferred tax expense (benefit)		4,126			4,257
Investment tax credits (1)		(122	)		(122	)
Total income tax expense (benefit)	$	3,485		$	1,128

⁽¹⁾  Investment tax credits (“ITC”) are being deferred and amortized over the depreciable life of the property giving rise to the credits

21

Income tax expense for the years ended March 31, 2011 and March 31, 2010 varied from the amount computed by applying the statutory rate to income before income taxes. A reconciliation of expected federal income tax expense, using the federal statutory rate of 35%, to the Company’s actual income tax expense for the years ended March 31, 2011 and March 31, 2010 is presented in the following table:

	Years Ended March 31,
(in thousands of dollars)	2011			2010
Computed tax	$	(30,585	)	$	691
Increase (reduction) including those attributable to flow-through of certain tax adjustments:
Goodwill impairment		33,146			—
Audit and related reserve movements		648			—
State income tax, net of federal benefit		387			576
Investment tax credit		(122	)		(122	)
Allowance for equity funds used during construction		(22	)		(38	)
Other items - net		33			21
Total		34,070			437
Federal and state income taxes	$	3,485		$	1,128

Significant components of the Company’s net deferred tax assets and liabilities at March 31, 2011 and March 31, 2010 are presented in the following table:

	March 31,
(in thousands of dollars)	2011			2010
Reserve - environmental	$	26,472		$	20,883
Future federal benefit on state taxes		3,206			2,979
Pensions, OPEB and other employee benefits		2,731			2,977
Allowance for uncollectible accounts		1,991			1,584
Unbilled revenue		1,730			391
Deferred gas costs		40			249
Regulatory assets / liabilities - other		23			61
Other items		79			167
Total deferred tax assets (1)		36,272			29,291
Property related differences		(57,359	)		(51,852	)
Regulatory assets - environmental		(27,192	)		(21,268	)
Regulatory assets - pension and OPEB		(3,592	)		(4,288	)
Regulatory assets - property taxes		(207	)		(86	)
Total accumulated deferred tax liabilities and investment tax credit		(88,350	)		(77,494	)
Investment tax credit		(161	)		(283	)
Net accumulated deferred income tax liability and investment tax credit	$	(52,239	)	$	(48,486	)
Current portion of net deferred tax asset		3,985			3,211
Non-current portion of net deferred income tax liability and investment tax credit		(56,224	)		(51,697	)
Net accumulated deferred income tax liability and investment tax credit	$	(52,239	)	$	(48,486	)

⁽¹⁾ There is no valuation allowance for deferred tax assets at March 31, 2011. There was a valuation allowance in the amount of $0.2 million against the New Hampshire Net Operating Loss Carryforward and the Business Enterprise Tax Credit Carryforward at March 31, 2010.

22

Subsequent to the KeySpan acquisition by National Grid on August 24, 2007, KeySpan and its subsidiaries became members of the National Grid Holdings, Inc. (“NGHI”) and subsidiaries consolidated federal income tax return. The Company is a member of this consolidated group. The Company has joint and several liability for any potential assessments against the consolidated group.

As of March 31, 2011 the Company’s current federal and state income tax balance payable to its parent is $0.7 million, recorded as taxes accrued, and as of March 31, 2010, a receivable balance from its parent of $2.4 million, recorded as prepaid and other current assets in the accompanying balance sheet.

The Company adopted the provisions of the current accounting guidance which clarifies the accounting and disclosure of uncertain tax positions in the financial statements. The guidance provides that the financial effects of a tax position shall initially be recognized when it is more likely than not, based on the technical merits, that the position will be sustained upon examination, assuming the position will be audited and the taxing authority has full knowledge of all relevant information.

As of March 31, 2011 and March 31, 2010, the Company’s unrecognized tax benefits totaled $4.8 million and $4.3 million, respectively, of which none and $0.2 million would affect the effective tax rate, if recognized.

The following table reconciles the changes to the Company’s unrecognized tax benefits for the years ended March 31, 2011 and March 31, 2010:

Reconciliation of Unrecognized Tax Benefits	March 31,
(in thousands of dollars)	2011			2010
Beginning balance	$	4,372		$	3,707
Gross increases (decreases) related to prior years		284			—
Gross increases (decreases) related to current year		588			665
Settlements with tax authorities		(408	)		—
Ending balance	$	4,836		$	4,372

As of March 31, 2011 and March 31, 2010, the Company has accrued for interest related to unrecognized tax benefits of $0.1 million and $0.4 million, respectively. During fiscal years ended March 31, 2011 and March 31 2010, the Company recorded an interest income of $0.4 million and interest expense of $0.05 million, respectively. The Company recognizes accrued interest related to unrecognized tax benefits in interest expense or interest income and related penalties, if applicable, in operating expenses. No penalties were recognized during fiscal years ended March 31, 2011 and March 31, 2010.

In November 2010, KeySpan and its subsidiaries reached a settlement agreement with the Internal Revenue Service (“IRS”) on outstanding tax matters for calendar tax years 2000 through 2006. The Company was a member of the KeySpan and its subsidiaries consolidated federal income tax return for these years and was obligated to pay $0.4 million to KeySpan for its share of the settlement pursuant to the tax sharing agreement. In connection with the settlement, the Company incurred a $0.6 million tax charge for the differences between the amounts settled upon with the IRS and the tax positions previously accrued. Resolution of tax matters for these years with state and local tax authorities is outstanding. The tax returns for the short year ended August 24, 2007, as well as the fiscal years ended March 31, 2008 through March 31, 2011 remain subject to examination by the IRS.

NGHI and subsidiaries file New Hampshire Business Enterprise Tax Return for Combined Groups. The Company is a member of this consolidated group. No state income tax audits are currently in progress. New Hampshire state income tax returns remain open, subject to the statute of limitations, for tax years 2005 until current year.

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Note 7. Derivative Contracts

Physical Derivatives

Current accounting guidance for derivative instruments establishes criteria that must be satisfied in order for option contracts, forward contracts with optionality features or contracts that combine a forward contract and a purchased option contract to qualify as normal purchase and normal sales. Certain contracts for the physical purchase of natural gas do not qualify for this exception. Since these contracts are for the purchase of natural gas sold to regulated firm gas sales customers, the accounting for these contracts follows the accounting guidance for rate-regulated enterprises. The fair value of these derivatives was a liability of $0.4 million at March 31, 2011 and a liability of $0.9 million at March 31, 2010.

Financial Derivatives

The Company uses derivative financial instruments to reduce the cash flow variability associated with the purchase price for a portion of future natural gas purchases. Our strategy is to minimize fluctuations in firm gas sales prices to regulated firm gas sales customers in our service territory. The accounting for these derivative instruments follows the accounting guidance for rate-regulated enterprises. Therefore, the fair value of these derivatives is recorded as current or deferred assets and liabilities, with offsetting positions recorded as regulatory assets or regulatory liabilities on the balance sheets. As these derivative contracts are eligible for rate regulated accounting treatment, changes in fair value have no income statement impact. Gains or losses upon settlement of these contracts are initially deferred and then refunded to or collected from our firm gas sales customers consistent with regulatory requirements. The fair value of these derivative instruments was a liability of $0.9 million and $5.6 million as of March 31, 2011 and 2010, respectively.

The following are commodity volumes associated with those derivative contracts as of March 31, 2011:

(in thousands)
Physicals	Gas (dths)	4,016
	Gas swaps (dths)	2,140
Financials	Gas options (dths)	980
	Gas (dths)	7,136

The following table presents the Company’s derivative contract assets and (liabilities) on the balance sheets:

Fair Values of Derivative Instruments - Balance Sheets

	Asset Derivatives					Liability Derivatives
(in thousands of dollars)	March 31, 2011		March 31, 2010			March 31, 2011			March 31, 2010
Regulated Contracts
Gas Contracts:
Gas swaps contract - current asset	$	53		2	Gas swaps contract - current liability		(845	)		(5,538	)
Gas options contract - current asset		19		—	Gas options contract - current liability		(31	)		—
Gas purchase contract - current asset		3		—	Gas purchase contract - current liability		(312	)		(353	)
Current asset		75		2	Current liability		(1,188	)		(5,891	)
Gas swaps contract - deferred asset		12		—	Gas swaps contract - deferred liability		(73	)		(113	)
Gas options contract - deferred asset		1		—	Gas options contract - deferred liability		(5	)		—
Gas purchase contract - deferred asset		—		—	Gas purchase contract - deferred liability		(128	)		(513	)
Deferred asset		13		—	Deferred liability		(206	)		(626	)
Gas subtotal		88		2			(1,394	)		(6,517	)
Total	$	88	$	2	Total	$	(1,394	)	$	(6,517	)

24

The following table presents the regulatory (assets) and liabilities whose change in fair value exactly correspond to the related derivative contracts in the preceding table. The Company had no derivative contracts eligible for non-rate-regulated accounting treatment as of March 31, 2011 and March 31, 2010. As such, the changes in fair value of derivative contracts and their offsetting regulatory assets and liabilities had no impact on the statement of income.

Fair Values of Derivative Instruments

(in thousands of dollars)	Year to Date Movement			March 31, 2011			March 31, 2010
Regulated Contracts
Gas Contracts:
Gas swaps contract - regulatory asset	$	4,733		$	(918	)	$	(5,651	)
Gas option contract - regulatory asset		(36	)		(36	)		—
Gas purchase contract - regulatory asset		426			(440	)		(866	)
Gas swaps contract - regulatory liability		63			65			2
Gas options contract - regulatory liability		20			20			—
Gas purchase contract - regulatory liability		3			3			—
Gas subtotal		5,209			(1,306	)		(6,515	)
Total	$	5,209		$	(1,306	)	$	(6,515	)

When applicable, movements in the fair value of regulated contracts are recorded as regulated asset or liability, rather than through the statements of income.

The aggregate fair value of the Company’s derivative instruments with credit-risk-related contingent features that are in a liability position on March 31, 2011 and March 31, 2010, for which the Company does not post any collateral in the normal course of business, were $0.9 million and $6.3 million, respectively. If the Company’s credit rating were to be downgraded by one notch, it would not be required to post any additional collateral. If the Company’s credit rating were to be downgraded by three notches, it would be required to post $1.1 million and $6.5 million additional collateral to its counterparties at March 31, 2011 and March 31, 2010, respectively.

Credit and Collateral

Derivative contracts are primarily used to manage exposure to market risk arising from changes in commodity prices and interest rates. In the event of non-performance by counterparty to a derivative contract, the desired impact may not be achieved. The risk of counterparty non-performance is generally considered a credit risk and is actively managed by assessing each counterparty credit profile and negotiating appropriate levels of collateral and credit support. In instances where the counterparties’ credit quality has declined, or credit exposure exceeds certain levels, we may limit our credit exposure by restricting new transactions with counterparties, requiring additional collateral or credit support and negotiating the early termination of certain agreements. At March 31, 2011 and March 31, 2010, the Company had no collateral associated with outstanding derivative contracts.

Note 8. Fair Value Measurements

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The following is the fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:

The Company currently has no Level 1 assets or liabilities for its derivative contracts.

The Company’s Level 2 fair value derivative instruments primarily consist of over-the-counter (“OTC”) gas swaps and forward physical gas deals where market data for pricing inputs is observable. Level 2 pricing inputs are obtained from the New York Mercantile Exchange (“NYMEX”) and Intercontinental Exchange (“ICE”), except cases when ICE publishes seasonal averages or there were no transactions within last seven days. During periods prior to March 31, 2011, Level 2 pricing inputs were obtained from NYMEX and Platts, M2M (industry standard, non-exchange-based editorial commodity forward curves) when it can be verified by available market data from ICE based on transactions within last seven days. Level 2 derivative instruments may utilize discounting based on quoted

25

interest rate curve as well as have liquidity reserve calculated based on bid/ask spread. Substantially all of these price curves are observable in the marketplace throughout at least 95% of the remaining contractual quantity, or they could be constructed from market observable curves with correlation coefficients of 0.95 or higher.

Level 3 fair value derivative instruments primarily consist of our gas OTC forwards, options, and physical gas transactions where pricing inputs are unobservable, as well as other complex and structured transactions. Complex or structured transactions can introduce the need for internally-developed models based on reasonable assumptions. Industry-standard valuation techniques, such as Black-Scholes pricing model, Monte Carlo simulation, and FEA libraries are used for valuing such instruments. The value is categorized as Level 3. Level 3 is also applied in cases when forward curve is internally developed, extrapolated or derived from market observable curve with correlation coefficients less than 0.95, or optionality is present, or non-economical assumptions are made.

The internally developed forward curves have a high level of correlation with Platts M2M curves.

The following table presents assets and liabilities measured and recorded at fair value on the Company’s balance sheet on a recurring basis and their level within the fair value hierarchy as of March 31, 2011 and March 31, 2010:

Fair Value Measurement Level Summary Table

March 31, 2011

(in thousands of dollars)	Level 1		Level 2			Level 3			Total
Assets
Derivative contracts	$	—	$	65		$	23		$	88
Total assets		—		65			23			88
Liabilities
Derivative contracts		—		(920	)		(474	)		(1,394	)
Total liabilities		—		(920	)		(474	)		(1,394	)
Net (liability) balance	$	—	$	(855	)	$	(451	)	$	(1,306	)

Fair Value Measurement Level Summary Table

March 31, 2010

(in thousands of dollars)	Level 1		Level 2			Level 3			Total
Assets
Derivative contracts	$	—	$	2		$	—		$	2
Total assets		—		2			—			2
Liabilities
Derivative contracts		—		(5,651	)		(866	)		(6,517	)
Total liabilities		—		(5,651	)		(866	)		(6,517	)
Net (liability) balance	$	—	$	(5,649	)	$	(866	)	$	(6,515	)

26

Year to Date Level 3 Movement Table

The following table presents the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the year ended March 31, 2011 and March 31, 2010:

(in thousands of dollars)
Balance at March 31, 2009	$	(1,038	)
Total gains and losses included in regulatory		237
Purchases		(65	)
Balance at March 31, 2010	$	(866	)
Total gains and losses included in regulatory
Total gains and losses included in regulatory		547
Purchases		(132	)
Balance at March 31, 2011	$	(451	)
The amount of realized gains and (losses) included in net income attributed to the change in unrealized gains and (losses) related to derivative assets and liabilities at March 31, 2011	$	—

The Company had no transfers of amounts from Level 2 to Level 3 or from Level 3 to Level 2 during the years ended March 31, 2011 and March 31, 2010.

Note 9. Commitments and Contingencies

Legal Matters

The Company is subject to various legal proceedings arising out of the ordinary course of its business. Except as described below, the Company does not consider any of such proceedings, individually or in the aggregate, to be material to its business or likely to result in a material adverse effect on its results of operations, financial condition, or cash flows.

Environmental Matters

The normal ongoing operations and historic activities of the Company are subject to various federal, state and local environmental laws and regulations and are regulated by agencies such as the United States Environmental Protection Agency and the New Hampshire Department of Environmental Services (“NHDES”). Like most other industrial companies, the Company generates some hazardous wastes. Under federal and state Superfund laws, potential liability for historic contamination of property may be imposed on responsible parties jointly and severally, without fault, even if the activities were lawful when they occurred.

The NHDES has named the Company as a potentially responsible party for remediation of several sites at which hazardous waste is alleged to have been disposed as a result of historic operations of MGP and related facilities. The Company is currently investigating and remediating, as necessary, those MGP sites in accordance with plans submitted to the NHDES. The Company believes that obligations imposed on it because of those sites will not have a material impact on its results of operations or financial position.

The NHPUC has authorized the Company to recover through rates its prudently incurred expenses in investigating and remediating environmental contamination associated with its former MGP sites. Under the cost recovery mechanism, the Company amortizes the investigation and remediation expenses over a seven year period without carrying costs. The cost of seeking recovery of investigation and remediation expenses from third parties, including former owners and/or operators of the former MGP sites and obtaining insurance coverage, are also recoverable. Amounts actually recovered through such efforts are to be applied to reduce the amount that would otherwise be recoverable from the Company’s customers.

27

Currently, the Company’s rate for recovery of these environmental costs is set at $0 because the funds recovered from third parties exceed the costs being incurred by the Company. However, the credit position is expected to reverse itself during fiscal 2011, so that beginning November 1, 2011, the Company expects to begin including an amount in its local distribution adjustment clause to recoup the net cost of its investigation and remediation efforts (and associated third party claims).

We estimate the remaining cost of these MGP-related environmental cleanup activities will be $59.8 million at March 31, 2011, which amount has been accrued by us as a reasonable estimate of cost for known sites. Remediation costs, however, for each site may be materially higher than noted, depending upon changing technologies and regulatory standards, selected end use for each site, and actual environmental conditions encountered.

By rate orders, the NHPUC provided for the recovery of site investigation and remediation costs and accordingly, at March 31, 2011 and March 31, 2010, we have reflected a regulatory asset of $61.5 million for the MGP sites.

On October 8, 2010, the NHDES provided a response to National Grid’s proposed remedy at the Liberty Hill Site in New Hampshire. In its preliminary determination, NHDES recommended implementation of a more costly remedy, which could increase the cost of the cleanup by $6.0 million or more. The Company has not accepted this recommendation at the current time and continues to discuss with the NHDES. If the final determination is adopted, then this would result in an increase in environmental reserves by $6.0 million and a corresponding increase in regulatory assets of the same amount compared with the balances recorded in these financial statements.

Asset Retirement Obligations

The Company has various asset retirement obligations associated with its gas distribution facilities. These obligations have remained substantially unchanged from March 31, 2010, except for normal accretion adjustments and costs incurred. Generally, our largest asset retirement obligations relate to: (i) legal requirements to cut (disconnect from the gas distribution system), purge (clean of natural gas and PCB contaminants) and cap gas mains within our gas distribution and transmission system when mains are retired in place, or dispose of sections of gas main when removed from the pipeline system, (ii) cleaning and removal requirements associated with storage tanks containing waste oil and other waste contaminants, and (iii) legal requirements to remove asbestos upon major renovation or demolition of structures and facilities.

At March 31, 2011 and March 31, 2010 the following asset retirement obligations were recorded on the balance sheets at their estimated present values:

	March 31,
(in thousands of dollars)	2011		2010
Asbestos removal	$	79	$	75
Tanks removal and cleaning		3		3
Main cutting, purging and capping		874		824
Total asset retirement obligations	$	956	$	902

The Company recorded $0.05 million and $0.1 million of asset retirement obligation accretion expense for the years ended March 31, 2011 and March 31, 2010, respectively.

28

Fixed Charges Under Firm Contracts

We have entered into various contracts for gas delivery, storage and supply services. We are liable for these payments regardless of the level of service we require from third parties. Such charges are currently recovered from utility customers through the gas adjustment clause.

(in thousands of dollars)
Year Ended March 31,
2012	$	14,965
2013		13,653
2014		13,519
2015		13,519
2016		10,351
Thereafter		62,871
Total	$	128,878

Permit Fee Litigation

The municipalities of Concord and Manchester have adopted new onerous permit fees that are intended to recover for alleged degradation of roadways following street openings, and now charge an additional $5.00 per square foot for street opening permits in addition to typical permit fees. These permit fees have now been applied to the Company’s permit applications. The Company has estimated that these additional fees will cost the Company approximately $0.7 million per year in Concord and $0.5 million per year in Manchester. As such, the fees would increase the Company’s operations construction budget (and future rates for customers). The Company is challenging the validity of such fees. The Company believes these fees are inconsistent with the state statute and therefore invalid. The Company has filed suit against Concord in Merrimack Superior Court and Manchester in Hillsborough Superior Court (collectively, the “Courts”) and is seeking a declaratory judgment invalidating such fees. In the interim, the Company has negotiated with the City of Manchester an interim agreement whereby they are continuing to issue permits (without paying new fees) to the Company in exchange for the Company increasing its payment bond. In the City of Concord, National Grid is paying the new fees under protest with the understanding that the City will refund such payments if we are successful in the litigation. No receivable has been recorded in relation to this matter as of March 31, 2011 or March 31, 2010.

Note 10. Related Party Transactions

Intercompany Balances and Moneypool

The Company is engaged in various transactions with NGUSA, KeySpan, and its wholly-owned affiliates. Generally, the subsidiaries of KeySpan do not maintain separate cash balances. Financing for the Company’s working capital and gas inventory needs is obtained through the Company’s participation in a moneypool. In addition, all cash generated from billings is collected and held in the moneypool. Further, all payments to third parties for our payables, including labor, are made through the moneypool. All moneypool balances are maintained at the parent. The Company accounts for funds received from KeySpan as a capital contribution from KeySpan and funds paid to KeySpan as a dividend to KeySpan. All other intercompany receivable and payable accounts are accounted for in a similar manner.

The following table presents the components of the net intercompany and moneypool balances, included in additional paid-in capital and the applicable interest rates for the years ended March 31, 2011 and March 31, 2010:

	Years Ended March 31,
(in thousands of dollars)	2011			2010
Intercompany bond	$	80,000		$	80,000
Interest rate on intercompany bond		5.8	%		5.8	%
Notes payable to affiliates		29,490		$	34,985
Interest rate on notes payable to affiliates		1.2	%		0.9	%

29

Advances to/from Affiliates

NGUSA and KeySpan subsidiaries also provide the Company with various services, including executive and administrative, customer services, financial (including accounting, auditing, risk management, tax, treasury/finance), human resources (including pension funding), information technology, legal, and strategic planning. The costs of these services are charged to the Company via intercompany billings and generally settled through the moneypool on a monthly basis. The Company had a $9.9 million and $6.9 million liability for these services at March 31, 2011 and March 31, 2010, respectively which has been included in additional-paid-in capital. Management has recorded these amounts through additional paid-in capital as management does not have the history of or intention to pay off this balance within one year. All moneypool balances are maintained at the Parent.

Service Company Charges

The affiliated service companies of NGUSA provide certain services to the Company at their cost. The service company costs are generally allocated to associated companies through a tiered approach. First and foremost, costs are directly charged to the benefited company whenever practicable. Secondly, in cases where direct charging cannot be readily determined, costs are typically allocated using cost/causation principles linked to the relationship of that type of service, such as meters, square footage, number of employees, etc. Lastly, all other costs are allocated based on a general allocator. These costs include operating and capital expenditures of $4.4 million and $15.9 million for the year ended March 31, 2011, and $3.6 million and $13.2 million for the year ended March 31, 2010, respectively.

Holding Company Charges

NGUSA received charges from National Grid Commercial Holdings Limited (an affiliated company in the UK) for certain corporate and administrative services provided by the corporate functions of National Grid plc to its US subsidiaries. These charges, which are recorded on the books of NGUSA, have not been reflected on these financial statements. Were these amounts allocated to this subsidiary, the estimated effect on net income would be approximately $0.6 million and $0.4 million before taxes, and $0.4 million and $0.3 million after taxes, for the years ended March 31, 2011 and March 31, 2010, respectively.

Organization Restructuring

On January 31, 2011, National Grid plc announced substantial changes to the organization, including new global, US and UK operating models, and changes to the leadership team. The announced structure seeks to create a leaner, more-efficient business backed by streamlined operations that will help meet, more efficiently, the needs of regulators, customers and shareholders. The implementation of the new U.S. business structure commences on April 4, 2011 and targets annualized savings of $200.0 million by March 2012 primarily through the reduction of up to 1,200 positions. As of March 31, 2011, NGUSA had recorded a $66.8 million reserve for onetime employment termination benefits related to severance, payroll taxes, healthcare continuation, and outplacement services as well as consulting fees related to the restructuring program. These charges have been recorded by NGUSA and none have been allocated to the Company as at March 31, 2011. Subsequently in June 2011, we offered a voluntary severance plan to certain individuals which is expected to cost up to an additional $20 million across all entities affiliated with NGUSA.

Note 11. Subsequent Events

In accordance with current authoritative accounting guidance, the Company has evaluated for disclosure subsequent events that have occurred through August 30, 2011, the date of issuance of these financial statements. As of August 30, 2011, there were no additional subsequent events which required recognition or disclosure.

30

EnergyNorth Natural Gas, Inc.

Financial Statements

For the quarters ended March 31, 2011 and March 31, 2010

(unaudited)

ENERGYNORTH NATURAL GAS, INC.

TABLE OF CONTENTS

	Page No.
Balance Sheets		2
March 31, 2011 and March 31, 2010
Statements of Income		3
Three Months Ended March 31, 2011 and March 31, 2010
Statements of Cash Flows		4
Three Months Ended March 31, 2011 and March 31, 2010
Statements of Comprehensive Income		5
Three Months Ended March 31, 2011 and March 31, 2010
Notes to Unaudited Financial Statements		6

1

ENERGYNORTH NATURAL GAS, INC.

BALANCE SHEETS

(in thousands of dollars, except per share and number of shares data)

	March 31, 2011			March 31, 2010
ASSETS
Current assets:
Accounts receivable	$	29,691		$	22,397
Allowance for doubtful accounts		(4,578	)		(3,642	)
Unbilled revenues		9,475			8,098
Gas in storage, at average cost		7,670			13,495
Derivative contracts		75			2
Regulatory assets		2,625			8,879
Current deferred income tax assets		3,985			3,211
Prepaid and other current assets		299			2,708
Total current assets		49,242			55,148
Property, plant, and equipment, net		247,979			241,852
Deferred charges:
Regulatory assets		68,596			60,027
Goodwill		2,115			96,818
Derivative contracts		13			—
Other deferred charges		13,642			11,424
Total deferred charges		84,366			168,269
Total assets	$	381,587		$	465,269
LIABILITIES AND CAPITALIZATION
Current liabilities:
Accounts payable	$	8,633		$	9,651
Taxes accrued		675			—
Customer deposits		896			340
Interest accrued		126			429
Regulatory liabilities		75			2
Current postretirement benefits		282			275
Derivative contracts		1,188			5,891
Other current liabilities		772			571
Total current liabilities		12,647			17,159
Deferred credits and other liabilities:
Regulatory liabilities		29,303			29,491
Asset retirement obligations		956			902
Deferred income tax liabilities		56,224			51,697
Postretirement benefits and other reserves		3,876			4,428
Environmental remediation costs		59,807			48,007
Derivative contracts		206			626
Other deferred liabilities		3,296			3,017
Total deferred credits and other liabilities		153,668			138,168
Capitalization:
Common stock, $25 per share, 120,000 issued and outstanding		3,000			3,000
Additional paid-in capital		291,767			295,723
Retained (deficit) earnings		(79,269	)		11,599
Accumulated other comprehensive loss		(226	)		(380	)
Total capitalization		215,272			309,942
Total liabilities and capitalization	$	381,587		$	465,269

The accompanying notes are an integral part of these financial statements.

2

ENERGYNORTH NATURAL GAS, INC.

STATEMENTS OF INCOME

(unaudited, in thousands of dollars)

	Three Months Ended March 31,
	2011			2010
Operating revenues	$	65,891		$	58,851
Operating expenses:
Gas purchased for resale		42,367			41,889
Operations and maintenance		6,403			7,499
Depreciation and amortization		2,316			2,240
Other taxes		1,544			1,502
Total operating expenses		52,630			53,130
Operating income		13,261			5,721
Other income and (deductions):
Interest on long-term debt		(84	)		(85	)
Other interest, including affiliate interest		(775	)		(1,072	)
Other (deductions) income, net		(117	)		953
Total other deductions		(976	)		(204	)
Income before income taxes		12,285			5,517
Income tax expense		4,517			3,148
Net income	$	7,768		$	2,369

The accompanying notes are an integral part of these financial statements

3

ENERGYNORTH NATURAL GAS, INC.

STATEMENTS OF CASH FLOWS

(unaudited, in thousands of dollars)

	Three Months Ended March 31,
	2011			2010
Operating activities:
Net income	$	7,768		$	2,369
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		2,316			2,240
Net pension and other postretirement expense		317			524
Net environmental (payments) charge		(207	)		333
Changes in operating assets and liabilities:
Accounts receivable, net		(5,067	)		(2,887	)
Gas in storage		5,446			2,623
Accounts payable and accrued expenses		(7,011	)		(12,976	)
Prepaid taxes and accruals		1,322			(163	)
Other, net		(4,884	)		7,937
Net cash change in operating activities		—			—
Net change in cash and cash equivalents		—			—
Cash and cash equivalents, beginning of period		—			—
Cash and cash equivalents, end of period	$	—		$	—

The accompanying notes are an integral part of these financial statements

4

ENERGYNORTH NATURAL GAS, INC.

STATEMENTS OF COMPREHENSIVE INCOME

(unaudited, in thousands of dollars)

	Three Months Ended March 31,
	2011			2010
Net income	$	7,768		$	2,369
Other comprehensive income, net of taxes:
Unrealized (losses) gains on investments		(23	)		13
Change in pension and other postretirement obligations		57			294
Reclassification adjustment for gains (losses) included in net income		17			(111	)
Change in other comprehensive income		51			196
Total comprehensive income	$	7,819		$	2,565
Related tax expense (benefit):
Unrealized gains (losses) on investments	$	13		$	(7	)
Change in pension and other postretirement obligations		(39	)		(200	)
Reclassification adjustment for gains (losses) included in net income		(12	)		75
Total tax benefit	$	(38	)	$	(132	)

The accompanying notes are an integral part of these financial statements

5

ENERGYNORTH NATURAL GAS, INC.

NOTES TO UNAUDITED FINANCIAL STATEMENTS

Note 1. Summary of Significant Accounting Policies

A. Nature of Operations

EnergyNorth Natural Gas, Inc. (the “Company”, “we”, “us”, and “our”) is a regulated natural gas utility providing natural gas distribution services to approximately 85,350 customers in New Hampshire.

The Company is an indirect subsidiary of National Grid New England LLC and an indirectly-owned subsidiary of KeySpan Corporation (“KeySpan”). KeySpan is a wholly-owned subsidiary of National Grid USA (“NGUSA”), a public utility holding company with regulated subsidiaries engaged in the generation of electricity and the transmission, distribution and sale of both natural gas and electricity. NGUSA is an indirectly-owned subsidiary of National Grid plc, a public limited company incorporated under the laws of England and Wales.

On December 8, 2010, NGUSA and Liberty Energy Utilities Co. (“Liberty Energy”), a subsidiary of Algonquin Power & Utilities Corp., entered into a stock purchase agreement which was subsequently amended and restated on January 21, 2011, pursuant to which NGUSA will sell and Liberty Energy will purchase all of the common stock of the Company. The parties have filed the necessary federal and state regulatory approvals that will be required to consummate the transaction with the Federal Energy Regulatory Commission (“FERC”) and New Hampshire Public Utilities Commission (“NHPUC”). The regulatory approval process is expected to be completed during the year ended March 31, 2012.

The Company has evaluated subsequent events and transactions through September 28, 2011, and concluded that there were no events or transactions that require adjustment to, or disclosure in the notes to the financial statements.

B. Basis of Presentation

The accompanying financial statements are unaudited and have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The year-end balance sheet data was derived from audited financial statements, but does not include all disclosure required by GAAP. These financial statements should be read in conjunction with the year-end audited financial statements. No significant changes have been made to the Company’s accounting policies and estimates that have been disclosed in its year-end financial statements.

In the opinion of management, the financial statements as of March 31, 2011, and for the three months ended March 31, 2011 and 2010, include all adjustments (consisting of normal recurring accruals) necessary for a fair statement of the financial position, results of operations and cash flows for the periods presented. The results of operations for the three months ended March 31, 2011 and 2010, are not necessarily indicative of the results to be expected for the full year or any other period.

Management makes estimates and assumptions that affect the amounts reported in the unaudited financial statements and notes. Although these estimates are based on management’s best available information at the time, actual results could differ.

C. Regulatory Accounting

The NHPUC provide the final determination of the rates we charge our customers. In certain cases, the actions of the FERC or the NHPUC would result in an accounting treatment different from that used by non-regulated companies to determine the rates we charge our customers. In this case, the Company is required to recognize costs (a regulatory asset) or to recognize obligations (a regulatory liability) if it is probable that these amounts will be recovered or refunded through the rate-making process, which would result in a corresponding increase or decrease in future rates.

In the event the Company determines that its net regulatory assets are not probable of recovery, it would no longer apply the principles of the current accounting guidance for rate regulated enterprises and would be required to record an after-tax, non-cash charge against income for any remaining regulatory assets and liabilities. The impact could be material to the Company’s reported financial condition and results of operations.

6

D. Derivatives

The Company participates in gas trading at National Grid. The Company employs derivative instruments to hedge a portion of its exposure to commodity price risk. Whenever hedge positions are in effect, the Company is exposed to credit risks in the event of non-performance by counter-parties to derivative contracts, as well as nonperformance by the counter-parties of the transactions against which they are hedged. The Company believes the credit risk related to derivative instruments is no greater than that associated with the primary commodity contracts that they hedge.

Firm Gas Sales Derivative Instruments

The Company utilizes derivative financial instruments to reduce the cash flow variability associated with the purchase price for a portion of future natural gas purchases. Our strategy is to minimize fluctuations in firm gas sales prices to our regulated firm gas sales customers. Because these derivative instruments are being employed to reduce the variability of the purchase price of natural gas to be sold to regulated firm gas sales customers, the accounting for these derivative instruments is subject to the current accounting guidance on the accounting for the effects of rate regulation. Therefore, changes in the market value of these derivatives have been recorded as a regulatory asset or regulatory liability on the balance sheets. Gains or losses on the settlement of these contracts are initially deferred and then refunded to or collected from our firm gas sales customers during the appropriate winter heating season consistent with regulatory requirements.

Physically-Settled Commodity Derivative Instruments

Certain of the Company’s contracts for the physical purchase of natural gas are derivatives as defined by current accounting guidance. As such, these contracts are recorded on the balance sheets at fair market value. However, because such contracts were executed for the purchases of natural gas that is sold to regulated firm gas sales customers, and pursuant to the requirements for accounting for the effects of rate regulation, changes in the fair market value of these contracts are recorded as a regulatory asset or regulatory liability on the balance sheets.

E. Fair Value Measurements

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The following is the fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:

Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that a company has the ability to access as of the reporting date.

Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data.

Level 3 — unobservable inputs, such as internally-developed forward curves and pricing models for the asset or liability due to little or no market activity for the asset or liability with low correlation to observable market inputs.

F. Recent Accounting Pronouncements

In June 2011, the Financial Accounting Standards Board (“FASB”) issued accounting guidance that eliminated the option to present the components of other comprehensive income as part of the statement of changes in stockholders’ equity. This update seeks to improve financial statement users’ ability to understand the causes of an entity’s change in financial position and results of operations. The Company is now required to either present the statement of income and statement of comprehensive income in a single continuous statement or in two separate, but consecutive statements of income and comprehensive income. This update does not change the items that are reported in other comprehensive income or any reclassification of items to net income. Additionally, the update does not change an entity’s option to present components of other comprehensive income net of or before related tax effects. This guidance is effective for non-public companies for fiscal years ending after December 15, 2012, and for interim and annual periods thereafter, and it is to be applied retrospectively. Early adoption is permitted. The Company does not expect adoption of this guidance to have an impact on the Company’s financial position, results of operations or cash flows.

7

In April 2011, the FASB issued accounting guidance that substantially amended existing guidance with respect to the fair value measurement topic (“the Topic”). The guidance seeks to amend the Topic in order to achieve common fair value measurement and disclosure requirements in GAAP and International Financial Reporting Standards. Consequently, the guidance changes the wording used to describe many of the requirements in GAAP for measuring fair value and for disclosing information about fair value measurements as well as changing specific applications of the Topic. Some of the amendments clarify the FASB’s intent about the application of existing fair value measurement requirements. Other amendments change a particular principle or requirement for measuring fair value or for disclosing information about fair value measurements including, but not limited to, fair value measurement of a portfolio of financial instruments, fair value measurement of premiums and discounts and additional disclosures about fair value measurements. This guidance is effective for financial statements issued for annual periods beginning after December 15, 2011. The early adoption of this guidance for non-public companies is permitted but only for interim periods beginning after December 15, 2011. The Company is currently determining the potential impact of the guidance on its financial position, results of operations and cash flows.

Note 2. Rates and Regulatory

Rate Matters

In February 2010, the Company filed a natural gas base distribution rate case with NHPUC seeking an increase in distribution rates of $11.4 million per year. In March 2011, NHPUC approved a settlement to increase the gas distribution rates by approximately $6.8 million based on an implied return on equity (“ROE”) of 9.67% and an equity ratio of 50%. The March 2011 order also approved a commodity-related bad debt recovery mechanism that adjusts for fluctuations in commodity prices. Although the Company requested pension and other post-employment benefits (“OPEB”) reconciliation mechanism and a revenue decoupling mechanism as part of the February 2010 filing, the parties could not reach consensus on these mechanisms and were therefore excluded from the settlement agreement. In May 2011, the Company presented the NHPUC Staff with documentation of rate case expenses in the amount of $1.5 million associated with the February 2010 filing. The NHPUC Staff will review the Company’s documentation and make a recommendation to the NHPUC as to the amount that should be allowed for recovery.

Pursuant to the NHPUC order approving the Company’s merger agreement with KeySpan, the Company is permitted to seek an annual base rate adjustment to reflect the cost of replacing cast iron and bare steel mains and services to the extent such cost exceeds $0.5 million. In June 2010 and June 2011, the Commission approved base distribution rate increases of $0.5 million effective on July 1, 2010 and July 1, 2011 of each year.

Other Regulatory Matters

In November 2008, FERC commenced an audit of NGUSA, including its service companies and other affiliates in the National Grid holding company system. The audit evaluated our compliance with: 1) cross-subsidization restrictions on affiliate transactions; 2) accounting, recordkeeping and reporting requirements; 3) preservation of records requirements for holding companies and service companies; and 4) Uniform System of Accounts for centralized service companies. The final audit report from the FERC was received in February 2011. In April 2011, NGUSA replied to the FERC and outlined its plan to address the findings in the report, which we are currently in the process of implementing. None of the findings had a material impact on the financial statements of the Company.

Note 3. Employee Benefits

The Company participates with certain other KeySpan subsidiaries in a non-contributory defined benefit pension plan (“Pension Plan”). The postretirement benefits other than pensions plan (“PBOP”, together with Pension Plan, the “Plan”) have not been merged with other KeySpan plans and therefore, continue to remain a separate plan of the Company. The Pension Plan is a non-contributory, tax-qualified defined benefit plan which provides all employees with a minimum retirement benefit. Supplemental nonqualified, non-contributory executive retirement programs provide additional defined pension benefits for certain executives. PBOPs provide health care and life insurance coverage to eligible retired employees. Eligibility is based on age and length of service requirements and, in most cases, retirees must contribute to the cost of their coverage.

8

Pension Plan assets are commingled and cannot be allocated to an individual company. Pension Plan costs are allocated to the Company. Certain current year changes in the funded status of the KeySpan plan are allocated to the Company through an intercompany payable account.

The net Pension Plan expense allocated to the Company for each of the three months ended March 31, 2011 and March 31, 2010 was $0.7 million, respectively. The net PBOP expense allocated to the Company for each of the three months ended March 31, 2011 and March, 2010 was $0.3 million, respectively. These Pension and PBOP costs are included as operations and maintenance expenses in the accompanying financial statements.

The Pension Plan obligation offset by related regulatory pension asset of $4.7 million and $3.8 million are included as part of additional paid-in capital in the accompanying balance sheets at March 31, 2011 and March 31, 2010, respectively.

Workforce Reduction Program

In connection with National Grid plc’s acquisition of KeySpan, National Grid plc and KeySpan offered 673 non-union employees a voluntary early retirement offer (“VERO”) in an effort to reduce the workforce. The VERO was completed and the Company accrued $1.3 million which has been deferred for recovery from gas sales customers as part of the synergy savings and cost to achieve calculations.

Note 4. Derivatives

Physical Derivatives

Current accounting guidance for derivative instruments establishes criteria that must be satisfied in order for option contracts, forward contracts with optionality features or contracts that combine a forward contract and a purchased option contract to qualify as normal purchase and normal sales. Certain contracts for the physical purchase of natural gas do not qualify for this exception. Since these contracts are for the purchase of natural gas sold to regulated firm gas sales customers, the accounting for these contracts follows the accounting guidance for rate-regulated enterprises. The fair value of these derivatives was a liability of $0.4 million and $0.9 million at March 31, 2011 and March 31, 2010, respectively.

Financial Derivatives

The Company uses derivative financial instruments to reduce the cash flow variability associated with the purchase price for a portion of future natural gas purchases. Our strategy is to minimize fluctuations in firm gas sales prices to regulated firm gas sales customers in our service territory. The accounting for these derivative instruments follows the accounting guidance for rate-regulated enterprises. Therefore, the fair value of these derivatives is recorded as current or deferred assets and liabilities, with offsetting positions recorded as regulatory assets or regulatory liabilities on the balance sheets. As these derivative contracts are eligible for rate regulated accounting treatment, changes in fair value have no income statement impact. Gains or losses upon settlement of these contracts are initially deferred and then refunded to or collected from our firm gas sales customers consistent with regulatory requirements. The fair value of these derivative instruments was a liability of $0.9 million and $5.6 million as of March 31, 2011 and March 31, 2010, respectively.

The following are commodity volumes associated with those derivative contracts as of March 31, 2011:

(in thousands)
Physicals	Gas (dths)	4,016
	Gas swaps (dths)	2,140
Financials	Gas options (dths)	980
	Gas (dths)	7,136

9

The following table presents the Company’s derivative contract assets and (liabilities) on the balance sheets:

Fair Values of Derivative Instruments - Balance Sheets

	Asset Derivatives					Liability Derivatives
(in thousands of dollars)	March 31, 2011		March 31, 2010			March 31, 2011			March 31, 2010
Regulated Contracts
Gas Contracts:
Gas swaps contract - current asset	$	53		2	Gas swaps contract - current liability		(845	)		(5,538	)
Gas options contract - current asset		19		—	Gas options contract - current liability		(31	)		—
Gas purchase contract - current asset		3		—	Gas purchase contract - current liability		(312	)		(353	)
Current asset		75		2	Current liability		(1,188	)		(5,891	)
Gas swaps contract - deferred asset		12		—	Gas swaps contract - deferred liability		(73	)		(113	)
Gas options contract - deferred asset		1		—	Gas options contract - deferred liability		(5	)		—
Gas purchase contract - deferred asset		—		—	Gas purchase contract - deferred liability		(128	)		(513	)
Deferred asset		13		—	Deferred liability		(206	)		(626	)
Gas subtotal		88		2			(1,394	)		(6,517	)
Total	$	88	$	2	Total	$	(1,394	)	$	(6,517	)

The Company had no non-regulated derivative contracts as of March 31, 2011 and March 31, 2010. The change in fair value of the regulated contracts exactly corresponds to offsetting regulatory assets and liabilities. As a result, the changes in fair value of derivative contracts and their offsetting regulatory assets and liabilities had no income statement impact. The following table presents the regulatory assets and liabilities of the Company’s derivative contracts:

Fair Values of Derivative Instruments

(in thousands of dollars)	Year to Date Movement			March 31, 2011			March 31, 2010
Regulated Contracts
Gas Contracts:
Gas swaps contract - regulatory asset	$	4,733		$	(918	)	$	(5,651	)
Gas option contract - regulatory asset		(36	)		(36	)		—
Gas purchase contract - regulatory asset		426			(440	)		(866	)
Gas swaps contract - regulatory liability		63			65			2
Gas options contract - regulatory liability		20			20			—
Gas purchase contract - regulatory liability		3			3			—
Gas subtotal		5,209			(1,306	)		(6,515	)
Total	$	5,209		$	(1,306	)	$	(6,515	)

The aggregate fair value of the Company’s derivative instruments with credit-risk-related contingent features that are in a liability position on March 31, 2011 and March 31, 2010, for which the Company does not post any collateral in the normal course of business, were $0.9 million and $6.3 million, respectively. If the Company’s credit rating were to be downgraded by one notch, it would not be required to post any additional collateral. If the Company’s credit rating were to be downgraded by three notches, it would be required to post $1.1 million and $6.5 million additional collateral to its counterparties at March 31, 2011 and March 31, 2010.

Credit and Collateral

Derivative contracts are primarily used to manage exposure to market risk arising from changes in commodity prices and interest rates. In the event of non-performance by counterparty to a derivative contract, the desired impact may not be achieved. The risk of counterparty non-performance is generally considered a credit risk and is actively managed by assessing each counterparty credit profile and negotiating appropriate levels of collateral and credit support. In instances where the counterparties’ credit quality has declined, or credit exposure exceeds certain levels, we may limit our credit exposure by restricting new transactions with counterparties, requiring additional collateral or credit support and negotiating the early termination of certain agreements. At March 31, 2011 and March 31, 2010, the Company had no collateral associated with outstanding derivative contracts.

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Note 5. Fair Value Measurements

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The following is the fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:

The Company had no Level 1 assets or liabilities for its derivative contracts at March 31, 2011 and March 31, 2010.

The Company’s Level 2 fair value derivative instruments primarily consist of over-the-counter (“OTC”) gas swaps and forward physical gas deals where market data for pricing inputs is observable. Level 2 pricing inputs are obtained from the New York Mercantile Exchange (“NYMEX”) and Intercontinental Exchange (“ICE”), except cases when ICE publishes seasonal averages or there were no transactions within last seven days. During periods prior to March 31, 2011, Level 2 pricing inputs were obtained from NYMEX and Platts M2M (industry standard, non-exchange-based editorial commodity forward curves) when it can be verified by available market data from ICE based on transactions within last seven days. Level 2 derivative instruments may utilize discounting based on quoted interest rate curve as well as have liquidity reserve calculated based on bid/ask spread. Substantially all of these price curves are observable in the marketplace throughout at least 95% of the remaining contractual quantity, or they could be constructed from market observable curves with correlation coefficients of 0.95 or higher.

Level 3 fair value derivative instruments primarily consist of our gas OTC forwards, options, and physical gas transactions where pricing inputs are unobservable, as well as other complex and structured transactions. Complex or structured transactions can introduce the need for internally-developed models based on reasonable assumptions. Industry-standard valuation techniques, such as Black-Scholes pricing model, Monte Carlo simulation, and FEA libraries are used for valuing such instruments. The value is categorized as Level 3. Level 3 is also applied in cases when forward curve is internally developed, extrapolated or derived from market observable curve with correlation coefficients less than 0.95, or optionality is present, or non-economical assumptions are made.

The following table presents assets and liabilities measured and recorded at fair value on the Company’s balance sheet on a recurring basis and their level within the fair value hierarchy as of March 31, 2011 and March 31, 2010:

(in thousands of dollars)	March 31, 2011
Derivative contracts	Level 1		Level 2			Level 3			Total
Assets	$	—	$	65		$	23		$	88
Liabilities		—		(920	)		(474	)		(1,394	)
Total derivative net liabilities	$	—	$	(855	)	$	(451	)	$	(1,306	)
(in thousands of dollars)	March 31, 2010
Derivative contracts	Level 1		Level 2			Level 3			Total
Assets	$	—	$	2		$	—		$	2
Liabilities		—		(5,651	)		(866	)		(6,517	)
Total derivative net liabilities	$	—	$	(5,649	)	$	(866	)	$	(6,515	)

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Year to Date Level 3 Movement Table

The following table presents the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the periods ended March 31, 2011 and March 31, 2010:

(in thousands of dollars)
Balance at March 31, 2009	$	(1,038	)
Total gains and losses included in regulatory assets and liabilites		237
Purchases		(65	)
Balance at March 31, 2010	$	(866	)
Total gains and losses included in regulatory assets and liabilites		547
Purchases		(132	)
Balance at March 31, 2011	$	(451	)
The amount of realized gains and (losses) included in net income attributed to the change in unrealized gains and (losses) related to derivative assets and liabilities at March 31, 2011	$	—

The Company had no transfers of amounts from Level 2 to Level 3 or from Level 3 to Level 2 during the three months ended March 31, 2011 and March 31, 2010.

Note 6. Income Taxes

The Company’s effective tax rate for the three months ended March 31, 2011 and March 31, 2010 was 36.8% and 57.1%, respectively. Included in taxes for the twelve months ended March 31, 2011 is a release of a valuation allowance against the New Hampshire Net Operating Loss and Business Enterprise Tax Credit carryforwards of $0.2 million. Excluding the impact of this annual benefit on the quarterly effective tax rate, the Company’s effective tax rate for the three months ended March 31, 2011 would be 39.0% . Included in taxes for the twelve months ended March 31, 2010 is a valuation allowance against the New Hampshire Net Operating Loss and Business Enterprise Tax Credit carryforwards of $0.1 million and New Hampshire Net Operating Loss carryforward limitation of $0.4 million. Excluding the impact of these annual charges on the quarterly effective tax rate, the Company’s effective tax rate for the three months ended March 31, 2010 would be 33.2% . Also included in taxes for the three months ended March 31, 2010 is a deferred tax charge related to provisions in the Patient Protection Act of 2010 which increased quarterly effective tax rate by 0.1% .

Note 7. Commitments and Contingencies

Legal Matters

The Company is subject to various legal proceedings arising out of the ordinary course of its business. Except as described below, the Company does not consider any of such proceedings to be material, individually or in the aggregate, to its business or likely to result in a material adverse effect on its results of operations, financial condition, or cash flows.

Environmental Matters

The normal ongoing operations and historic activities of the Company are subject to various federal, state and local environmental laws and regulations. Like many other industrial companies, the Company generates hazardous waste. Under federal and state Superfund laws, potential liability for the historic contamination of property may be imposed on responsible parties jointly and severally, without fault, even if the activities were lawful when they occurred.

The New Hampshire Department of Environmental Services (“NHDES”) has named the Company as a potentially responsible party for remediation of several sites at which hazardous waste is alleged to have been disposed as a result of historic operations of Manufacturing Gas Plant (“MGP”) and related facilities. The Company is currently investigating and remediating, as necessary, those MGP sites in accordance with plans submitted to the NHDES. The Company believes that obligations imposed on it because of those sites will not have a material impact on its financial condition.

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Note 8. Related Party Transactions

Intercompany Moneypool

The Company participates with NGUSA and certain affiliates in a system moneypool. Generally, the subsidiaries of KeySpan do not maintain separate cash balances. Financing for the Company’s working capital and gas inventory needs is obtained through the Company’s participation in a moneypool. In addition, all cash generated from billings is collected and held in the moneypool. Further, all payments to third parties for our payables, including labor, are made through the moneypool. All moneypool balances are maintained at the parent. The Company accounts for funds received from KeySpan as a capital contribution from KeySpan and funds paid to KeySpan as a dividend to KeySpan. All other intercompany receivable and payable accounts are accounted for in a similar manner.

The following table presents the components of the net intercompany bond and moneypool balances, included in additional paid-in capital and the applicable interest rates at March 31, 2011 and March 31, 2010:

	March 31,
(in thousands of dollars)	2011			2010
Intercompany bond	$	80,000		$	80,000
Interest rate on intercompany bond		5.8	%		5.8	%
Notes payable to affiliates - Moneypool	$	29,490		$	34,985
Interest rate on notes payable to affiliates		1.2	%		0.9	%

Accounts receivable from/payable to affiliates

Additionally, the Company engages in various transactions with NGUSA and its affiliates. Certain activities and costs, such as executive and administrative, financial (including accounting, auditing, risk management, tax and treasure/finance), human resources, information technology, legal and strategic planning are shared between the companies and allocated to each company appropriately. In addition, the Company has a tax sharing agreement with National Grid Holdings Inc. (“NGHI”), a NGUSA affiliate, in filing consolidated tax returns. The Company’s share of the tax liability is allocated resulting in a payment to or refund from NGHI. The Company had net accounts payable to affiliates of $9.9 million and $6.9 million at March 31, 2011 and 2010, respectively, for those services which are included in additional paid-in capital in the accompanying balance sheets.

Service Company Charges

The affiliated service companies of NGUSA provide certain services to the Company at their cost. The service company costs are generally allocated to associated companies through a tiered approach. First and foremost, costs are directly charged to the benefited company whenever practicable. Secondly, in cases where direct charging cannot be readily determined, costs are typically allocated using cost/causation principles linked to the relationship of that type of service, such as meters, square footage, number of employees, etc. Lastly, all other costs are allocated based on a general allocator. These costs include operating and capital expenditures of approximately $0.7 million and $2.7 million for the three months ended March 31, 2011 and approximately $1.0 million and $3.6 million for the three months ended March 31, 2010, respectively.

13

Organization Restructuring

On January 31, 2011, National Grid plc announced substantial changes to the organization, including new global, US and UK operating models, and changes to the leadership team. The announced structure seeks to create a leaner, more-efficient business backed by streamlined operations that will help meet, more efficiently, the needs of regulators, customers and shareholders. The implementation of the new U.S. business structure commenced on April 4, 2011 and targets annualized savings of $200 million by March 2012 primarily through the reduction of approximately 1,200 positions. As of March 31, 2011, NGUSA had recorded a $66.8 million reserve for one-time employment termination benefits related to severance, payroll taxes, healthcare continuation, outplacement services as well as consulting fees related to the restructuring program. During the quarter ended June 30, 2011, NGUSA reduced this reserve by $15.1 million due to payment of one-time employment termination benefits which was allocated to various affiliated entities, the Company’s portion of which is $0.1 million. In June 2011, we offered a voluntary severance plan to certain individuals which is expected to cost up to an additional $20 million across all entities affiliated with NGUSA.

14

EnergyNorth Natural Gas, Inc.

Financial Statements

For the quarters ended June 30, 2011 and June 30, 2010

(unaudited)

ENERGYNORTH NATURAL GAS, INC.

TABLE OF CONTENTS

	Page No.
Balance Sheets June 30, 2011 and March 31, 2011		2
Statements of Loss Three Months Ended June 30, 2011 and June 30, 2010		3
Statements of Cash Flows Three Months Ended June 30, 2011 and June 30, 2010		4
Statements of Comprehensive Loss Three Months Ended June 30, 2011 and June 30, 2010		5
Notes to Unaudited Financial Statements		6

1

ENERGYNORTH NATURAL GAS, INC.

BALANCE SHEETS

(in thousands of dollars, except per share and number of shares data)

	June 30, 2011			March 31, 2011
	(unaudited)
ASSETS
Current assets:
Accounts receivable	$	23,579		$	29,691
Allowance for doubtful accounts		(4,558	)		(4,578	)
Unbilled revenues		1,964			9,475
Gas in storage, at average cost		4,453			7,670
Derivative contracts		35			75
Regulatory assets		3,258			2,625
Current deferred income tax assets		3,985			3,985
Prepaid and other current assets		1,762			299
Total current assets		34,478			49,242
Property, plant, and equipment, net		248,839			247,979
Deferred charges:
Regulatory assets		67,571			68,596
Goodwill		2,115			2,115
Derivative contracts		15			13
Other deferred charges		13,461			13,642
Total deferred charges		83,162			84,366
Total assets	$	366,479		$	381,587
LIABILITIES AND CAPITALIZATION
Current liabilities:
Accounts payable	$	5,061		$	8,633
Taxes accrued		628			675
Customer deposits		955			896
Interest accrued		126			126
Regulatory liabilities		35			75
Current postretirement benefits		282			282
Derivative contracts		2,225			1,188
Other current liabilities		562			772
Total current liabilities		9,874			12,647
Deferred credits and other liabilities:
Regulatory liabilities		28,777			29,303
Asset retirement obligations		971			956
Deferred income tax liabilities		57,722			56,224
Postretirement benefits and other reserves		3,653			3,876
Environmental remediation costs		59,319			59,807
Derivative contracts		92			206
Other deferred liabilities		3,184			3,296
Total deferred credits and other liabilities		153,718			153,668
Capitalization:
Common stock, $25 per share, 120,000 issued and outstanding		3,000			3,000
Additional paid-in capital		279,631			291,767
Accumulated deficit		(79,529	)		(79,269	)
Accumulated other comprehensive loss		(215	)		(226	)
Total capitalization		202,887			215,272
Total liabilities and capitalization	$	366,479		$	381,587

The accompanying notes are an integral part of these financial statements.

2

ENERGYNORTH NATURAL GAS, INC.

STATEMENTS OF LOSS

(unaudited, in thousands of dollars)

	Three Months Ended June 30,
	2011			2010
Operating revenues	$	27,783		$	18,973
Operating expenses:
Gas purchased for resale		15,926			11,103
Operations and maintenance		7,298			8,877
Depreciation and amortization		2,330			2,252
Other taxes		1,415			1,230
Total operating expenses		26,969			23,462
Operating income (loss)		814			(4,489	)
Other income and (deductions):
Interest on long-term debt		(84	)		(85	)
Other interest, including affiliate interest		(1,270	)		(1,203	)
Other income		65			119
Total other deductions		(1,289	)		(1,169	)
Loss before income taxes		(475	)		(5,658	)
Income tax benefit		(215	)		(2,082	)
Net loss	$	(260	)	$	(3,576	)

The accompanying notes are an integral part of these financial statements

3

ENERGYNORTH NATURAL GAS, INC.

STATEMENTS OF CASH FLOWS

(unaudited, in thousands of dollars)

	Three Months Ended June 30,
	2011			2010
Operating activities:
Net loss	$	(260	)	$	(3,576	)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		2,330			2,252
Net pension and other postretirement expense		58			122
Net environmental payments		(82	)		(56	)
Changes in operating assets and liabilities:
Accounts receivable, net		13,603			15,765
Gas in storage		3,217			(705	)
Accounts payable and accrued expenses		(7,326	)		(9,407	)
Prepaid taxes and accruals		(1,512	)		2,015
Other, net		(10,028	)		(6,410	)
Net cash change in operating activities		—			—
Net change in cash and cash equivalents		—			—
Cash and cash equivalents, beginning of period		—			—
Cash and cash equivalents, end of period	$	—		$	—

The accompanying notes are an integral part of these financial statements

4

ENERGYNORTH NATURAL GAS, INC.

STATEMENTS OF COMPREHENSIVE LOSS

(unaudited, in thousands of dollars)

	Three Months Ended June 30,
	2011			2010
Net loss	$	(260	)	$	(3,576	)
Other comprehensive loss, net of taxes:
Change in pension and other postretirement obligations		13			17
Reclassification adjustment for losses included in net loss		(2	)		(3	)
Change in other comprehensive income		11			14
Total comprehensive loss	$	(249	)	$	(3,562	)
Related tax expense (benefit):
Change in pension and other postretirement obligations		(9	)		(11	)
Reclassification adjustment for losses included in net loss		1			2
Total tax benefit	$	(8	)	$	(9	)

The accompanying notes are an integral part of these financial statements

5

ENERGYNORTH NATURAL GAS, INC.

NOTES TO UNAUDITED FINANCIAL STATEMENTS

Note 1. Summary of Significant Accounting Policies

A. Nature of Operations

EnergyNorth Natural Gas, Inc. (the “Company”, “we”, “us”, and “our”) is a regulated natural gas utility providing natural gas distribution services to approximately 85,350 customers in New Hampshire.

The Company is an indirect subsidiary of National Grid New England LLC and an indirectly-owned subsidiary of KeySpan Corporation (“KeySpan”). KeySpan is a wholly-owned subsidiary of National Grid USA (“NGUSA”), a public utility holding company with regulated subsidiaries engaged in the generation of electricity and the transmission, distribution and sale of both natural gas and electricity. NGUSA is an indirectly-owned subsidiary of National Grid plc, a public limited company incorporated under the laws of England and Wales.

On December 8, 2010, NGUSA and Liberty Energy Utilities Co. (“Liberty Energy”), a subsidiary of Algonquin Power & Utilities Corp., entered into a stock purchase agreement which was subsequently amended and restated on January 21, 2011, pursuant to which NGUSA will sell and Liberty Energy will purchase all of the common stock of the Company. The parties have filed the necessary federal and state regulatory approvals that will be required to consummate the transaction with the Federal Energy Regulatory Commission (“FERC”) and New Hampshire Public Utilities Commission (“NHPUC”). The regulatory approval process is expected to be completed during the year ended March 31, 2012.

The Company has evaluated subsequent events and transactions through September 28, 2011, and concluded that there were no events or transactions that require adjustment to, or disclosure in the notes to the financial statements.

B. Basis of Presentation

The accompanying financial statements are unaudited and have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The year-end balance sheet data was derived from audited financial statements, but does not include all disclosure required by GAAP. These financial statements should be read in conjunction with the year-end audited financial statements. No significant changes have been made to the Company’s accounting policies and estimates that have been disclosed in its year-end financial statements.

In the opinion of management, the financial statements as of June 30, 2011, and for the three months ended June 30, 2011 and 2010, include all adjustments (consisting of normal recurring accruals) necessary for a fair statement of the financial position, results of operations and cash flows for the periods presented. The results of operations for the three months ended June 30, 2011 and 2010, are not necessarily indicative of the results to be expected for the full year or any other period.

Management makes estimates and assumptions that affect the amounts reported in the unaudited financial statements and notes. Although these estimates are based on management’s best available information at the time, actual results could differ.

C. Regulatory Accounting

The NHPUC provide the final determination of the rates we charge our customers. In certain cases, the actions of the FERC or the NHPUC would result in an accounting treatment different from that used by non-regulated companies to determine the rates we charge our customers. In this case, the Company is required to recognize costs (a regulatory asset) or to recognize obligations (a regulatory liability) if it is probable that these amounts will be recovered or refunded through the rate-making process, which would result in a corresponding increase or decrease in future rates.

In the event the Company determines that its net regulatory assets are not probable of recovery, it would no longer apply the principles of the current accounting guidance for rate regulated enterprises and would be required to record an after-tax, non-cash charge against income for any remaining regulatory assets and liabilities. The impact could be material to the Company’s reported financial condition and results of operations.

6

D. Derivatives

The Company participates in gas trading at National Grid. The Company employs derivative instruments to hedge a portion of its exposure to commodity price risk. Whenever hedge positions are in effect, the Company is exposed to credit risks in the event of non-performance by counter-parties to derivative contracts, as well as nonperformance by the counter-parties of the transactions against which they are hedged. The Company believes the credit risk related to derivative instruments is no greater than that associated with the primary commodity contracts that they hedge.

Firm Gas Sales Derivative Instruments

The Company utilizes derivative financial instruments to reduce the cash flow variability associated with the purchase price for a portion of future natural gas purchases. Our strategy is to minimize fluctuations in firm gas sales prices to our regulated firm gas sales customers. Because these derivative instruments are being employed to reduce the variability of the purchase price of natural gas to be sold to regulated firm gas sales customers, the accounting for these derivative instruments is subject to the current accounting guidance on the accounting for the effects of rate regulation. Therefore, changes in the market value of these derivatives have been recorded as a regulatory asset or regulatory liability on the balance sheets. Gains or losses on the settlement of these contracts are initially deferred and then refunded to or collected from our firm gas sales customers during the appropriate winter heating season consistent with regulatory requirements.

Physically-Settled Commodity Derivative Instruments

Certain of the Company’s contracts for the physical purchase of natural gas are derivatives as defined by current accounting guidance. As such, these contracts are recorded on the balance sheets at fair market value. However, because such contracts were executed for the purchases of natural gas that is sold to regulated firm gas sales customers, and pursuant to the requirements for accounting for the effects of rate regulation, changes in the fair market value of these contracts are recorded as a regulatory asset or regulatory liability on the balance sheets.

E. Fair Value Measurements

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The following is the fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:

Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that a company has the ability to access as of the reporting date.

Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data.

Level 3 — unobservable inputs, such as internally-developed forward curves and pricing models for the asset or liability due to little or no market activity for the asset or liability with low correlation to observable market inputs.

F. Recent Accounting Pronouncements

In June 2011, the Financial Accounting Standards Board (“FASB”) issued accounting guidance that eliminated the option to present the components of other comprehensive income as part of the statement of changes in stockholders’ equity. This update seeks to improve financial statement users’ ability to understand the causes of an entity’s change in financial position and results of operations. The Company is now required to either present the statement of income and statement of comprehensive income in a single continuous statement or in two separate, but consecutive statements of income and comprehensive income. This update does not change the items that are reported in other comprehensive income or any reclassification of items to net income. Additionally, the update does not change an entity’s option to present components of other comprehensive income net of or before related tax effects. This guidance is effective for non-public companies for fiscal years ending after December 15, 2012, and for interim and annual periods thereafter, and it is to be applied retrospectively. Early adoption is permitted. The Company does not expect adoption of this guidance to have an impact on the Company’s financial position, results of operations or cash flows.

7

In April 2011, the FASB issued accounting guidance that substantially amended existing guidance with respect to the fair value measurement topic (“the Topic”). The guidance seeks to amend the Topic in order to achieve common fair value measurement and disclosure requirements in GAAP and International Financial Reporting Standards. Consequently, the guidance changes the wording used to describe many of the requirements in GAAP for measuring fair value and for disclosing information about fair value measurements as well as changing specific applications of the Topic. Some of the amendments clarify the FASB’s intent about the application of existing fair value measurement requirements. Other amendments change a particular principle or requirement for measuring fair value or for disclosing information about fair value measurements including, but not limited to, fair value measurement of a portfolio of financial instruments, fair value measurement of premiums and discounts and additional disclosures about fair value measurements. This guidance is effective for financial statements issued for annual periods beginning after December 15, 2011. The early adoption of this guidance for non-public companies is permitted but only for interim periods beginning after December 15, 2011. The Company is currently determining the potential impact of the guidance on its financial position, results of operations and cash flows.

Note 2. Rates and Regulatory

Rate Matters

In February 2010, the Company filed a natural gas base distribution rate case with NHPUC seeking an increase in distribution rates of $11.4 million per year. In March 2011, NHPUC approved a settlement to increase the gas distribution rates by approximately $6.8 million based on an implied return on equity (“ROE”) of 9.67% and an equity ratio of 50%. The March 2011 order also approved a commodity-related bad debt recovery mechanism that adjusts for fluctuations in commodity prices. Although the Company requested pension and other post-employment benefits (“OPEB”) reconciliation mechanism and a revenue decoupling mechanism as part of the February 2010 filing, the parties could not reach consensus on these mechanisms and were therefore excluded from the settlement agreement. In May 2011, the Company presented the NHPUC Staff with documentation of rate case expenses in the amount of $1.5 million associated with the February 2010 filing. The NHPUC Staff will review the Company’s documentation and make a recommendation to the NHPUC as to the amount that should be allowed for recovery.

Pursuant to the NHPUC order approving the Company’s merger agreement with KeySpan, the Company is permitted to seek an annual base rate adjustment to reflect the cost of replacing cast iron and bare steel mains and services to the extent such cost exceeds $0.5 million. In June 2010 and June 2011, the Commission approved base distribution rate increases of $0.5 million effective on July 1, 2010 and July 1, 2011 of each year.

Other Regulatory Matters

In November 2008, FERC commenced an audit of NGUSA, including its service companies and other affiliates in the National Grid holding company system. The audit evaluated our compliance with: 1) cross-subsidization restrictions on affiliate transactions; 2) accounting, recordkeeping and reporting requirements; 3) preservation of records requirements for holding companies and service companies; and 4) Uniform System of Accounts for centralized service companies. The final audit report from the FERC was received in February 2011. In April 2011, NGUSA replied to the FERC and outlined its plan to address the findings in the report, which we are currently in the process of implementing. None of the findings had a material impact on the financial statements of the Company.

Note 3. Employee Benefits

The Company participates with certain other KeySpan subsidiaries in a non-contributory defined benefit pension plan (“Pension Plan”). The postretirement benefits other than pensions plan (“PBOP”, together with Pension Plan, the “Plan”) have not been merged with other KeySpan plans and therefore, continue to remain a separate plan of the Company. The Pension Plan is a non-contributory, tax-qualified defined benefit plan which provides all employees with a minimum retirement benefit. Supplemental nonqualified, non-contributory executive retirement programs provide additional defined pension benefits for certain executives. PBOPs provide health care and life insurance coverage to eligible retired employees. Eligibility is based on age and length of service requirements and, in most cases, retirees must contribute to the cost of their coverage.

8

Pension Plan assets are commingled and cannot be allocated to an individual company. Pension Plan costs are allocated to the Company. Certain current year changes in the funded status of the KeySpan plan are allocated to the Company through an intercompany payable account.

The net Pension Plan expense allocated to the Company for the three months ended June 30, 2011 and June 30, 2010 was $0.5 million and $0.4 million, respectively. The net PBOP expense allocated to the Company for each of the three months ended June 30, 2011 and June 30, 2010 was $0.3 million. These Pension and PBOP costs are included as operations and maintenance expenses in the accompanying financial statements.

The Pension Plan obligation offset by related regulatory pension asset of $5.4 million and $3.8 million are included as part of additional paid-in capital in the accompanying balance sheets at June 30, 2011 and March 31, 2011, respectively.

Workforce Reduction Program

In connection with National Grid plc’s acquisition of KeySpan, National Grid plc and KeySpan offered 673 non-union employees a voluntary early retirement offer (“VERO”) in an effort to reduce the workforce. The VERO was completed and the Company accrued $1.3 million which has been deferred for recovery from gas sales customers as part of the synergy savings and cost to achieve calculations.

Note 4. Derivatives

Physical Derivatives

Current accounting guidance for derivative instruments establishes criteria that must be satisfied in order for option contracts, forward contracts with optionality features or contracts that combine a forward contract and a purchased option contract to qualify as normal purchase and normal sales. Certain contracts for the physical purchase of natural gas do not qualify for this exception. Since these contracts are for the purchase of natural gas sold to regulated firm gas sales customers, the accounting for these contracts follows the accounting guidance for rate-regulated enterprises. The fair value of these derivatives was a liability of $0.9 million and $0.4 million at June 30, 2011 and March 31, 2011, respectively.

Financial Derivatives

The Company uses derivative financial instruments to reduce the cash flow variability associated with the purchase price for a portion of future natural gas purchases. Our strategy is to minimize fluctuations in firm gas sales prices to regulated firm gas sales customers in our service territory. The accounting for these derivative instruments follows the accounting guidance for rate-regulated enterprises. Therefore, the fair value of these derivatives is recorded as current or deferred assets and liabilities, with offsetting positions recorded as regulatory assets or regulatory liabilities on the balance sheets. As these derivative contracts are eligible for rate regulated accounting treatment, changes in fair value have no income statement impact. Gains or losses upon settlement of these contracts are initially deferred and then refunded to or collected from our firm gas sales customers consistent with regulatory requirements. The fair value of these derivative instruments was a liability of $1.3 million and $0.9 million as of June 30, 2011 and March 31, 2011, respectively.

The following are commodity volumes associated with those derivative contracts as of June 30, 2011:

(in thousands)
Physicals	Gas (dths)	4,226
	Gas swaps (dths)	3,040
Financials	Gas options (dths)	1,180
Total	Gas (dths)	8,446

9

The following table presents the Company’s derivative contract assets and (liabilities) on the balance sheets:

Fair Values of Derivative Instruments - Balance Sheets

	Asset Derivatives					Liability Derivatives
(in thousands of dollars)	June 30, 2011		March 31, 2011			June 30, 2011			March 31, 2011
Regulated Contracts
Gas Contracts:
Gas swaps contract - current asset	$	30		53	Gas swaps contract - current liability		(1,267	)		(845	)
Gas options contract - current asset		5		19	Gas options contract - current liability		(73	)		(31	)
Gas purchase contract - current asset		—		3	Gas purchase contract - current liability		(885	)		(312	)
Current asset		35		75	Current liability		(2,225	)		(1,188	)
Gas swaps contract - deferred asset		15		12	Gas swaps contract - deferred liability		(28	)		(73	)
Gas options contract - deferred asset		—		1	Gas options contract - deferred liability		—			(5	)
Gas purchase contract - deferred asset		—		—	Gas purchase contract - deferred liability		(64	)		(128	)
Deferred asset		15		13	Deferred liability		(92	)		(206	)
Gas subtotal		50		88			(2,317	)		(1,394	)
Total	$	50	$	88	Total	$	(2,317	)	$	(1,394	)

The Company had no non-regulated derivative contracts as of June 30, 2011 and March 31, 2011. The change in fair value of the regulated contracts exactly corresponds to offsetting regulatory assets and liabilities. As a result, the changes in fair value of derivative contracts and their offsetting regulatory assets and liabilities had no income statement impact. The following table presents the regulatory assets and liabilities of the Company’s derivative contracts:

Fair Values of Derivative Instruments

	Year to Date			June 30,			March 31,
(in thousands of dollars)	Movement			2011			2011
Regulated Contracts
Gas Contracts:
Gas swaps contract - regulatory asset	$	(377	)	$	(1,295	)	$	(918	)
Gas option contract - regulatory asset		(37	)		(73	)		(36	)
Gas purchase contract - regulatory asset		(509	)		(949	)		(440	)
Gas swaps contract - regulatory liability		(20	)		45			65
Gas options contract - regulatory liability		(14	)		6			20
Gas purchase contract - regulatory liability		(3	)		—			3
Total	$	(960	)	$	(2,266	)	$	(1,306	)

The aggregate fair value of the Company’s derivative instruments with credit-risk-related contingent features that are in a liability position on June 30, 2011 and March 31, 2011, for which the Company does not post any collateral in the normal course of business, were $1.4 million and $0.9 million, respectively. If the Company’s credit rating were to be downgraded by one notch, it would not be required to post any additional collateral. If the Company’s credit rating were to be downgraded by three notches, it would be required to post $1.6 million and $1.1 million additional collateral to its counterparties at June 30, 2011 and March 31, 2011.

Credit and Collateral

Derivative contracts are primarily used to manage exposure to market risk arising from changes in commodity prices and interest rates. In the event of non-performance by counterparty to a derivative contract, the desired impact may not be achieved. The risk of counterparty non-performance is generally considered a credit risk and is actively managed by assessing each counterparty credit profile and negotiating appropriate levels of collateral and credit support. In instances where the counterparties’ credit quality has declined, or credit exposure exceeds certain levels, we may limit our credit exposure by restricting new transactions with counterparties, requiring additional collateral or credit support and negotiating the early termination of certain agreements. At June 30, 2011 and March 31, 2011, the Company had no collateral associated with outstanding derivative contracts.

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Note 5. Fair Value Measurements

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The following is the fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:

The Company had no Level 1 assets or liabilities for its derivative contracts at June 30, 2011 and March 31, 2011.

The Company’s Level 2 fair value derivative instruments primarily consist of over-the-counter (“OTC”) gas swaps and forward physical gas deals where market data for pricing inputs is observable. Level 2 pricing inputs are obtained from the New York Mercantile Exchange (“NYMEX”) and Intercontinental Exchange (“ICE”), except cases when ICE publishes seasonal averages or there were no transactions within last seven days. During periods prior to March 31, 2011, Level 2 pricing inputs were obtained from NYMEX and Platts M2M (industry standard, non-exchange-based editorial commodity forward curves) when it can be verified by available market data from ICE based on transactions within last seven days. Level 2 derivative instruments may utilize discounting based on quoted interest rate curve as well as have liquidity reserve calculated based on bid/ask spread. Substantially all of these price curves are observable in the marketplace throughout at least 95% of the remaining contractual quantity, or they could be constructed from market observable curves with correlation coefficients of 0.95 or higher.

Level 3 fair value derivative instruments primarily consist of our gas OTC forwards, options, and physical gas transactions where pricing inputs are unobservable, as well as other complex and structured transactions. Complex or structured transactions can introduce the need for internally-developed models based on reasonable assumptions. Industry-standard valuation techniques, such as Black-Scholes pricing model, Monte Carlo simulation, and FEA libraries are used for valuing such instruments. The value is categorized as Level 3. Level 3 is also applied in cases when forward curve is internally developed, extrapolated or derived from market observable curve with correlation coefficients less than 0.95, or optionality is present, or non-economical assumptions are made.

The following table presents assets and liabilities measured and recorded at fair value on the Company’s balance sheet on a recurring basis and their level within the fair value hierarchy as of June 30, 2011 and March 31, 2011:

(in thousands of dollars)			June 30, 2011
Derivative contracts	Level 1		Level 2			Level 3			Total
Assets	$	—	$	45		$	6		$	51
Liabilities		—		(1,294	)		(1,023	)		(2,317	)
Total derivative net liabilities	$	—	$	(1,249	)	$	(1,017	)	$	(2,266	)
(in thousands of dollars)			March 31, 2011
Derivative contracts	Level 1		Level 2			Level 3			Total
Assets	$	—	$	65		$	23		$	88
Liabilities		—		(920	)		(474	)		(1,394	)
Total derivative net liabilities	$	—	$	(855	)	$	(451	)	$	(1,306	)

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Year to Date Level 3 Movement Table

The following table presents the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the periods ended June 30, 2011 and March 31, 2011:

(in thousands of dollars)
Balance at March 31, 2010	$	(866	)
Total gains and losses included in regulatory assets and liabilities		547
Purchases		(132	)
Balance at March 31, 2011	$	(451	)
(in thousands of dollars)
Balance at June 30, 2010	$	(800	)
Total gains and losses included in regulatory assets and liabilities		524
Purchases		(741	)
Balance at June 30, 2011	$	(1,017	)
The amount of realized gains and (losses) included in net income attributed to the change in unrealized gains and (losses) related to derivative assets and liabilities at June 30, 2011	$	—

The Company had no transfers of amounts from Level 2 to Level 3 or from Level 3 to Level 2 during the three months ended June 30, 2011 and June 30, 2010.

Note 6. Income Taxes

The Company’s effective tax rate for the three months ended June 30, 2011 and June 30, 2010 was 45.3% and 36.8%, respectively. Included in taxes for the twelve months ended March 31, 2011 is a release of a valuation allowance against the New Hampshire Net Operating Loss and Business Enterprise Tax Credit carryforwards of $0.2 million. Excluding the impact of this annual benefit on the quarterly effective tax rate, the Company’s effective tax rate for the three months ended June 30, 2010 would be 39.0% .

Note 7. Commitments and Contingencies

Legal Matters

The Company is subject to various legal proceedings arising out of the ordinary course of its business. Except as described below, the Company does not consider any of such proceedings to be material, individually or in the aggregate, to its business or likely to result in a material adverse effect on its results of operations, financial condition, or cash flows.

Environmental Matters

The normal ongoing operations and historic activities of the Company are subject to various federal, state and local environmental laws and regulations. Like many other industrial companies, the Company generates hazardous waste. Under federal and state Superfund laws, potential liability for the historic contamination of property may be imposed on responsible parties jointly and severally, without fault, even if the activities were lawful when they occurred.

The New Hampshire Department of Environmental Services (“NHDES”) has named the Company as a potentially responsible party for remediation of several sites at which hazardous waste is alleged to have been disposed as a result of historic operations of Manufactured Gas Plant (“MGP”) and related facilities. The Company is currently investigating and remediating, as necessary, those MGP sites in accordance with plans submitted to the NHDES. The Company believes that obligations imposed on it because of those sites will not have a material impact on its financial condition.

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Note 8. Related Party Transactions

Intercompany Moneypool

The Company participates with NGUSA and certain affiliates in a system moneypool. Generally, the subsidiaries of KeySpan do not maintain separate cash balances. Financing for the Company’s working capital and gas inventory needs is obtained through the Company’s participation in a moneypool. In addition, all cash generated from billings is collected and held in the moneypool. Further, all payments to third parties for our payables, including labor, are made through the moneypool. All moneypool balances are maintained at the parent. The Company accounts for funds received from KeySpan as a capital contribution from KeySpan and funds paid to KeySpan as a dividend to KeySpan. All other intercompany receivable and payable accounts are accounted for in a similar manner.

The following table presents the components of the intercompany bond and moneypool balances, included in additional paid-in capital and the applicable interest rates at June 30, 2011 and March 31, 2011:

	June 30,			March 31,
(in thousands of dollars)	2011			2011
Intercompany bond	$	80,000		$	80,000
Interest rate on intercompany bond		5.8	%		5.8	%
Notes payable to affiliates - Moneypool	$	22,197		$	29,490
Interest rate on notes payable to affiliates		1.0	%		1.2	%

Accounts receivable from/payable to affiliates

Additionally, the Company engages in various transactions with NGUSA and its affiliates. Certain activities and costs, such as executive and administrative, financial (including accounting, auditing, risk management, tax and treasure/finance), human resources, information technology, legal and strategic planning are shared between the companies and allocated to each company appropriately. In addition, the Company has a tax sharing agreement with National Grid Holdings Inc. (“NGHI”), a NGUSA affiliate, in filing consolidated tax returns. The Company’s share of the tax liability is allocated resulting in a payment to or refund from NGHI. The Company had a net accounts payable to affiliates of $5.8 million and $9.9 million at June 30, 2011 and March 31, 2011, respectively, for those services which are included in additional paid-in capital in the accompanying balance sheets.

Service Company Charges

The affiliated service companies of NGUSA provide certain services to the Company at their cost. The service company costs are generally allocated to associated companies through a tiered approach. First and foremost, costs are directly charged to the benefited company whenever practicable. Secondly, in cases where direct charging cannot be readily determined, costs are typically allocated using cost/causation principles linked to the relationship of that type of service, such as meters, square footage, number of employees, etc. Lastly, all other costs are allocated based on a general allocator. These costs include operating and capital expenditures of approximately $1.0 million and $3.7 million for the three months ended June 30, 2011 and approximately $0.1 million and $0.5 million for the three months ended June 30, 2010, respectively.

Organization Restructuring

On January 31, 2011, National Grid plc announced substantial changes to the organization, including new global, US and UK operating models, and changes to the leadership team. The announced structure seeks to create a leaner, more-efficient business backed by streamlined operations that will help meet, more efficiently, the needs of regulators, customers and shareholders. The implementation of the new U.S. business structure commenced on April 4, 2011 and targets annualized savings of $200 million by March 2012 primarily through the reduction of approximately 1,200

13

positions. As of March 31, 2011, NGUSA had recorded a $66.8 million reserve for one-time employment termination benefits related to severance, payroll taxes, healthcare continuation, outplacement services as well as consulting fees related to the restructuring program. During the quarter ended June 30, 2011, NGUSA reduced this reserve by $15.1 million due to payment of one-time employment termination benefits which was allocated to various affiliated entities, the Company’s portion of which is $0.1 million. In June 2011, we offered a voluntary severance plan to certain individuals which is expected to cost up to an additional $20 million across all entities affiliated with NGUSA.

14

Granite State Electric Company

Financial Statements

For the years ended March 31, 2011 and March 31, 2010

GRANITE STATE ELECTRIC COMPANY

TABLE OF CONTENTS

	Page No.
Report of Independent Auditors		2
Balance Sheets March 31, 2011 and March 31, 2010		3
Statements of Operation Years Ended March 31, 2011 and March 31, 2010		5
Statements of Cash Flows Years Ended March 31, 2011 and March 31, 2010		6
Statements of Comprehensive Income Years Ended March 31, 2011 and March 31, 2010		7
Statements of Capitalization March 31, 2011 and March 31, 2010		8
Notes to Financial Statements		9

1

Report of Independent Auditors

To the Stockholder and Board of Directors of

Granite State Electric Company:

In our opinion, the accompanying balance sheets and related statements of operations, of comprehensive income, of capitalization and of cash flows present fairly, in all material respects, the financial position of Granite State Electric Company (the “Company”) at March 31, 2011 and 2010, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes 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. We believe that our audits provide a reasonable basis for our opinion.

June 29, 2011

PricewaterhouseCoopers LLP, 300 Madison Avenue, New York, NY 10017

T: (646) 471 3000, F: (646) 471 8320, www.pwc.com/us

2

GRANITE STATE ELECTRIC COMPANY

BALANCE SHEETS

	March 31,
(in thousands of dollars)	2011			2010
ASSETS
Current assets
Cash and cash equivalents	$	220		$	587
Restricted cash		3,277			3,070
Accounts receivable		10,101			9,767
Allowance for doubtful accounts		(558	)		(489	)
Accounts receivable from affiliates, net		—			365
Intercompany moneypool		7,500			—
Unbilled revenues		1,037			830
Materials and supplies, at average cost		499			449
Current deferred income tax assets		1,390			1,245
Prepaid and other current assets		1,942			7,132
Total current assets		25,408			22,956
Property, plant and equipment, net		83,775			81,172
Deferred charges
Regulatory assets		5,105			4,000
Goodwill		19,352			19,352
Other deferred charges		1,191			1,099
Total deferred charges		25,648			24,451
Total assets	$	134,831		$	128,579

The accompanying notes are an integral part of these financial statements.

3

GRANITE STATE ELECTRIC COMPANY

BALANCE SHEETS

	March 31,
(in thousands of dollars, except per share and number of shares data)	2011			2010
LIABILITIES AND CAPITALIZATION
Current liabilities
Accounts payable	$	6,983		$	7,145
Accounts payable to affiliates, net		2,017			—
Taxes accrued		332			63
Customer deposits		545			349
Interest accrued		492			583
Intercompany moneypool		—			1,575
Other current liabilities		3,777			1,761
Total current liabilities		14,146			11,476
Deferred credits and other liabilities
Regulatory liabilities		8,785			8,657
Deferred income tax liabilities		13,239			10,802
Postretirement benefits and other reserves		6,457			8,768
Other deferred liabilities		4,810			3,828
Total deferred credits and other liabilities		33,291			32,055
Capitalization
Common stock, par value $100 per share, issued and outstanding 60,400 shares		6,040			6,040
Additional paid-in capital		40,054			40,054
Retained earnings		33,009			32,317
Accumulated other comprehensive losses		(6,709	)		(8,363	)
Total shareholders’ equity		72,394			70,048
Long-term debt		15,000			15,000
Total capitalization		87,394			85,048
Total liabilities and capitalization	$	134,831		$	128,579

The accompanying notes are an integral part of these financial statements.

4

GRANITE STATE ELECTRIC COMPANY

STATEMENTS OF OPERATIONS

	Years Ended March 31
(in thousands of dollars)	2011			2010
Operating revenues	$	82,841		$	80,713
Operating expenses
Electricity purchased		44,367			44,367
Operations and maintenance		27,919			26,569
Depreciation and amortization		4,858			4,599
Other taxes		3,023			2,700
Total operating expenses		80,167			78,235
Operating income		2,674			2,478
Other deductions
Interest on long-term debt		(1,133	)		(1,133	)
Other interest, including affiliate interest		(10	)		(132	)
Other deductions		(82	)		(130	)
Total other deductions		(1,225	)		(1,395	)
Income taxes
Current		(537	)		(4,620	)
Deferred		1,294			6,015
Total income taxes		757			1,395
Net income (loss)	$	692		$	(312	)

The accompanying notes are an integral part of these financial statements

5

GRANITE STATE ELECTRIC COMPANY

STATEMENTS OF CASH FLOWS

	Years Ended March 31
(in thousands of dollars)	2011			2010
Operating activities
Net income (loss)	$	692		$	(312	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		4,858			4,599
Provision for deferred income taxes		1,294			6,015
Other non-cash items		1,282			1,361
Net pension and other postretirement expense		383			(140	)
Changes in operating assets and liabilities:
Accounts receivable, net		(759	)		(1,197	)
Materials and supplies		(50	)		(120	)
Accounts payable and accrued expenses		(385	)		(310	)
Prepaid taxes and accruals		5,470			(5,923	)
Accounts receivable and payable affiliate, net		2,382			—
Other, net		615			350
Net cash provided by operating activities		15,782			4,323
Investing activities
Capital expenditures		(6,007	)		(6,756	)
Changes in intercompany moneypool		(7,500	)		5,375
Restricted cash		(207	)		(3,000	)
Other, including cost of removal		(860	)		(1,448	)
Net cash used in investing activities		(14,574	)		(5,829	)
Financing activities
Changes in intercompany moneypool		(1,575	)		1,575
Net cash (used in) provided by financing activities		(1,575	)		1,575
Net (decrease) increase in cash and cash equivalents		(367	)		69
Cash and cash equivalents, beginning of year		587			518
Cash and cash equivalents, end of year	$	220		$	587
Supplementary information:
Interest paid	$	1,157		$	1,274
Taxes refunded	$	5,884		$	—
Capital related accruals included in accounts payable	$	132		$	318

The accompanying notes are an integral part of these financial statements

6

GRANITE STATE ELECTRIC COMPANY

STATEMENTS OF COMPREHENSIVE INCOME

	Years Ended March 31
(in thousands of dollars)	2011			2010
Net income (loss)	$	692		$	(312	)
Other comprehensive income (loss), net of taxes
Unrealized gains on investments		40			115
Change in pension and other postretirement obligations		1,643			451
Reclassification adjustment for losses included in net income		(29	)		(19	)
Change in other comprehensive income		1,654			547
Total comprehensive income		2,346			235
Related tax expense (benefit)
Unrealized losses on investments		(27	)		(77	)
Change in pension and other postretirement obligations		(1,095	)		(301	)
Reclassification adjustment for gains included in net income		19			13
Total tax benefit	$	(1,103	)	$	(365	)

The accompanying notes are an integral part of these financial statements

7

GRANITE STATE ELECTRIC COMPANY

STATEMENTS OF CAPITALIZATION

	March 31,
	2011			2010		2011			2010
(in thousands of dollars, except per share and number of shares data)	Shares Issued and Outstanding					Amounts
Shareholders’ equity
Common stock, $100 par value		60,400			60,400	$	6,040		$	6,040
Additional paid-in capital							40,054			40,054
Retained earnings							33,009			32,317
Accumulated other comprehensive loss							(6,709	)		(8,363	)
Total shareholder’ equity						$	72,394		$	70,048
	Interest rates			Maturity Date		Amounts
Long-term debt
Unsecured Notes
7.37% Unsecured Note 2023		7.37	%		November 1, 2023	$	5,000		$	5,000
7.94% Unsecured Note 2025		7.94	%		July 1, 2025		5,000			5,000
7.30% Unsecured Note 2028		7.30	%		June 15, 2028		5,000			5,000
Total long-term debt							15,000			15,000
Total capitalization						$	87,394		$	85,048

The accompanying notes are an integral part of these financial statements

8

NOTES TO FINANCIAL STATEMENTS

Note 1. Summary of Significant Accounting Policies

A. Nature of Operations

Granite State Electric Company (the “Company”, “we”, “us”, and “our”) is an electric retail distribution company providing electric service to approximately 43,000 customers in 21 communities in New Hampshire. The properties of the Company consist principally of substations and distribution lines interconnected with transmission and other facilities of New England Power Company (“NEP”), a wholly owned subsidiary of National Grid USA (“NGUSA”).

The Company is a wholly-owned subsidiary of NGUSA, a public utility holding company with regulated subsidiaries engaged in the generation of electricity and the transmission, distribution and sale of both natural gas and electricity. NGUSA is an indirectly-owned subsidiary of National Grid plc, a public limited company incorporated under the laws of England and Wales.

On December 8, 2010, NGUSA and Liberty Energy Utilities Co. (“Liberty Energy”), a subsidiary of Algonquin Power & Utilities Corp., entered into a stock purchase agreement which was subsequently amended and restated on January 21, 2011, pursuant to which National Grid will sell and Liberty Energy will purchase all of the common stock of the Company. The parties have filed the necessary federal and state regulatory approvals that will be required to consummate the transaction. The regulatory approval process is expected to be completed during the year ended March 31, 2012.

B. Basis of Presentation

The Company’s accounting policies conform to accounting principles generally accepted in the United States of America (“GAAP”), including the accounting principles for rate-regulated entities, and are in accordance with the accounting requirements and ratemaking practices of the applicable regulatory authorities.

The accounts of the Company are maintained in accordance with the Uniform System of Accounts prescribed by the regulatory bodies having jurisdiction.

The preparation of 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 assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.

C. Accounting for the Effects of Rate Regulation

The Federal Energy Regulatory Commission (“FERC”) and the New Hampshire Public Utilities Commission (“NHPUC”) provide the final determination of the rates we charge our customers. In certain cases, the actions of the FERC or the NHPUC would result in an accounting treatment different from that used by non-regulated companies to determine the rates we charge our customers. In this case, the Company is required to defer the recognition of costs (a regulatory asset) or the recognition of obligations (a regulatory liability) if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates.

In the event the Company determines that its net regulatory assets are not probable of recovery, the Company would be required to record an after-tax, non-cash charge against income for any remaining regulatory assets and liabilities. The resulting charge could be material to the Company’s reported financial condition and results of operations.

D. Revenue Recognition

Customers are generally billed on a monthly basis. Revenues include unbilled amounts related to the estimated electric usage that occurred from the most recent meter reading to the end of each month.

Revenues are based on billing rates authorized by the NHPUC. The Company records revenues in an amount management believes to be recoverable pursuant to provisions of approved tariffs, settlement agreements and state legislation. The Company defers for future recovery from or refunds to electric customers the difference between revenue and expenses from, default service, transmission service, and contract termination charges (“CTC”). The Company also records the distribution component of revenue for electricity delivered but not yet billed.

9

During each of the years ended March 31, 2011 and March 31, 2010, 46% of the Company’s revenue from the sale and delivery of electricity was derived from residential customers, 47% from commercial customers, and 7% from industrial customers, respectively.

E. Property, Plant and Equipment

Property, plant, and equipment are stated at original cost. The cost of additions to property, plant and equipment and replacements of retired units of property are capitalized. Costs include direct material, labor, overhead and allowance for funds used during construction (“AFUDC”). Replacement of minor items of property, plant, and equipment and the cost of current repairs and maintenance are charged to expense. Whenever property, plant, and equipment is retired, its original cost, together with cost of removal, less salvage, is charged to accumulated depreciation.

F. Goodwill

Goodwill represents the excess of purchase price of a business combination over the fair value of tangible and intangible assets acquired, net of the fair value of liabilities assumed and the fair value of any non-controlling interest in the acquisition. The Company tests goodwill for impairment on an annual basis and, on an interim basis, when certain events or circumstances exist.

The goodwill impairment analysis is comprised of two steps. In the first step, the Company compares the fair value of each reporting unit to its carrying value. The Company can consider both an income-based approach using projected discounted cash flows and a market-based approach using valuation multiples of comparable companies to determine fair value. The Company’s estimate of fair value of each reporting unit is based on a number of subjective factors including: (i) the appropriate weighting of valuation approaches (income-based approach and market-based approach), (ii) estimates of the future revenue and cash flows, (iii) discount rate for estimated cash flows, (iv) selection of peer group companies for the market-based approach, (v) required levels of working capital, (vi) assumed terminal value, (vii) the time horizon of cash flow forecasts and (viii) control premium.

If the fair value of the reporting unit exceeds the carrying value of the net assets assigned to that unit, goodwill is not considered impaired and no further analysis is required to be performed. If the carrying value of the net assets assigned to the reporting unit exceeds the fair value, then a second step is performed to determine the implied fair value of the reporting unit’s goodwill. If the carrying value of a reporting unit’s goodwill exceeds its implied fair value, then an impairment charge equal to the difference is recorded.

The Company utilizes a discounted cash flow approach incorporating its most recent business plan forecasts together with a projected terminal year calculation in the performance of the annual goodwill impairment test. Critical assumptions used in the Company’s analysis include a discount rate of 5.9% and a terminal year growth rate of 2.4% based upon expected long-term average growth rates. Within its calculation of forecasted returns, the Company made certain assumptions with respect to the amount of pension and environmental costs to be recovered in future periods. Should the Company not continue to receive the same level of recovery in these areas, the result could be a reduction in fair value of the Company, which in turn could give rise to an impairment of goodwill. Our forecasts assume long-term recovery and rate of returns that are in line with historical levels within the utility industry. The resulting fair value of the annual analysis determined that no adjustment of the goodwill carrying value was required.

G. Cash and Cash Equivalents

The Company classifies short-term investments that are highly liquid and have maturities of three months or less at the date of purchase as cash equivalents. These short-term investments are carried at cost which approximates fair value.

H. Restricted Cash

At March 31, 2011 and 2010, $3.3 million and $3.1 million, respectively, was required by the Independent System Operator (“ISO”) to be on deposit.

10

I. Income Taxes

Federal and state income taxes are recorded under the current accounting provisions for the accounting and reporting of income taxes. Income taxes have been computed utilizing the asset and liability approach that requires the recognition of deferred tax assets and liabilities for the tax consequences of temporary differences by applying enacted statutory tax rates applicable to future years to differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities.

Deferred income taxes reflect the tax effect of net operating losses, capital losses and general business credit carryforwards and the net tax effects of temporary differences between the carrying amount of assets and liabilities for financial statement and income tax purposes, as determined under enacted tax laws and rates. The financial effect of changes in tax laws or rates is accounted for in the period of enactment. Deferred investment tax credits are amortized over the useful life of the underlying property. Additionally, the Company follows the current accounting guidance relating to uncertainty in income taxes which applies to all income tax positions reflected on the Company’s Balance Sheets that have been included in previous tax returns or are expected to be included in future tax returns.

J. Comprehensive Income (Loss)

Comprehensive income (loss) is the change in the equity of a company, not including those changes that result from shareholder transactions. While the primary component of comprehensive income (loss) is reported net income or loss, the other primary component of comprehensive income (loss) is unrealized gains (losses) associated with certain investments held as available for sale and changes in pension and other postretirement obligations

K. Employee Benefits

The Company follows the provisions of the Financial Accounting Standards Board (“FASB”) accounting guidance related to the accounting for defined benefit pension and postretirement plans which requires employers to fully recognize all postretirement plans’ funded status on the Balance Sheets as a net liability or asset and required an offsetting adjustment to accumulated other comprehensive income in shareholders’ equity upon implementation or, in the case of regulated enterprises, to regulatory assets or liabilities. Consistent with past practice and as required by the guidance, the Company values its pension and postretirement benefits other than pensions (PBOP) assets using the year-end market value of those assets. Benefit obligations are also measured at year-end.

L. Fair Value Measurements

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The following is the fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:

Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that a company has the ability to access as of the reporting date.

Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data.

Level 3 — unobservable inputs, such as internally-developed forward curves and pricing models for the asset or liability due to little or no market activity for the asset or liability with low correlation to observable market inputs.

M. Materials and Supplies

Materials and supplies are stated primarily at the lower of cost or market value under the average cost method. The Company’s policy is to write off obsolete materials and supplies.

11

N. Recent Accounting Pronouncements

Prospective Accounting Pronouncements

In the preceding twelve months, the FASB has issued numerous updates to GAAP. The Company has evaluated various guidelines and has deemed them as not applicable based on its nature of operations or has implemented the new standards. A discussion of the more significant and relevant updates is as follows:

In June 2011, the FASB issued accounting guidance that eliminated the option to present the components of other comprehensive income as part of the statement of changes in stockholders’ equity. This update seeks to improve financial statement users’ ability to understand the causes of an entity’s change in financial position and results of operations. The Company is now required to consecutively present the statement of income and statement of comprehensive income and also present reclassification adjustments from other comprehensive income to net income on the face of the financial statements. This update does not change the items that are reported in other comprehensive income or any reclassification of items to net income. Additionally, the update does not change an entity’s option to present components of other comprehensive income net of or before related tax effects. This guidance is effective for public companies for fiscal years, and interim periods within that year, beginning after December 15, 2011, and it is to be applied retrospectively. Early adoption is permitted. The Company does not expect adoption of this guidance to have an impact on the Company’s financial position, results of operations or cash flows.

In April 2011, the FASB issued accounting guidance that substantially amended existing guidance with respect to the fair value measurement topic (“the Topic”). The guidance seeks to amend the Topic in order to achieve common fair value measurement and disclosure requirements in GAAP and International Financial Reporting Standards. Consequently, the guidance changes the wording used to describe many of the requirements in GAAP for measuring fair value and for disclosing information about fair value measurements as well as changing specific applications of the Topic. Some of the amendments clarify the FASB’s intent about the application of existing fair value measurement requirements. Other amendments change a particular principle or requirement for measuring fair value or for disclosing information about fair value measurements including, but not limited to, fair value measurement of a portfolio of financial instruments, fair value measurement of premiums and discounts and additional disclosures about fair value measurements. This guidance is effective for financial statements issued for interim and annual periods beginning after December 15, 2011. The early adoption of this guidance is not permitted and can only be applied prospectively. The Company is currently determining the potential impact of the guidance on its financial position, results of operations and cash flows.

In March 2011, the FASB issued updated guidance over the agreements between two entities to transfer financial assets. Prior to this update, an entity could recognize this transfer when it was deemed that the transferee had effective control over the transferred asset, specifically whether the entity has the ability to repurchase substantially the same asset based on the transferor’s collateral. This accounting update evaluates the effectiveness of the entity’s control by focusing on the transferor’s contractual rights and obligations as opposed to the entity’s ability to perform on those rights and obligations. This update also eliminates the requirement to demonstrate that the transferor possesses adequate collateral to fund substantially all the cost of purchasing replacement financial assets. This guidance is treated prospectively and effective for annual or interim reporting periods beginning on or after December 15, 2011. The Company does not expect adoption of this guidance to have an impact on the Company’s financial position, results of operations or cash flows.

In December 2010, the FASB issued an accounting update that modified the goodwill impairment procedures necessary for entities with zero or negative carrying value. The FASB created this guidance to require entities to complete Step 2 of the impairment test, which requires the entity to assess whether or not it was likely that impairment existed throughout the period. To do this, an entity should consider whether there were adverse qualitative factors throughout the period that would contribute to impairment. This update is effective for fiscal years and interim periods beginning after December 15, 2011. The Company does not expect adoption of this guidance to have an impact on the Company’s financial position, results of operations or cash flows.

Recently Adopted Accounting Pronouncements

In March 2010, the FASB issued updated guidance that provides for scope exceptions applicable to financial instrument contracts with embedded credit derivative features. This FASB guidance is effective for financial statements issued for interim periods beginning after June 15, 2010. On an ongoing basis, the Company evaluates new and existing transactions and agreements to determine whether they are derivatives, or have provisions that meet the characteristics of embedded derivatives. Those transactions designated for any of the elective accounting treatments for derivatives must meet specific, restrictive criteria, both at the time of designation and on an ongoing basis. None of the financial instrument contracts or credit agreements the Company has entered were identified and designated as meeting the criteria for derivative or embedded derivative treatment. The adoption of this guidance did not have an impact on the Company’s financial position, results of operations or cash flows.

12

In February 2010, the FASB issued an amendment to certain recognition and disclosure requirements for events that occur after the Balance Sheet date but before the financial statements are issued or are available to be issued. The amendment applies to both issued financial statements and financial statements revised as a result of either a correction of an error or retrospective application of GAAP. The new provisions require non-public entities to disclose both the date that the financial statements were issued, or available to be issued, and the date the revised financial statements were issued or available to be issued. The amendment is effective for interim or annual periods ending after June 15, 2010. The adoption of this guidance did not have an impact on the Company’s financial position, results of operations or cash flows.

In January 2010, the FASB issued an amendment to the accounting guidance for fair value measurements that will provide for additional disclosures about (a) the different classes of assets and liabilities measured at fair value, (b) the valuation techniques and inputs used, (c) the activity in Level 3 fair value measurements, and (d) the transfers between Levels 1, 2, and 3. This FASB guidance is effective for financial statement issued for interim and annual periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years. The adoption of this guidance did not have an impact on the Company’s financial position, results of operations or cash flows.

In June 2009, the FASB issued an amendment to the accounting and disclosure requirements for transfers and servicing of financial assets and extinguishment of liabilities. The objective of the amendment is to improve the relevance, representational faithfulness, and comparability of the information that a reporting entity provides in its financial statements about a transfer of financial assets; and effects of a transfer on its financial position, financial performance and cash flows; and transferor’s continuing involvement, if any, in transferred financial assets. The new provisions must be applied as of the beginning of each reporting entity’s first annual reporting period beginning after November 15, 2009 and are to be applied to transfers occurring on or after the date of adoption. The adoption of this guidance did not have an impact on the Company’s financial position, results of operations or cash flows.

In June 2009, the FASB issued an amendment to the accounting and disclosure requirements for the consolidation of variable interest entities. The objective of the amendment is to improve financial reporting by enterprises involved with variable interest entities and to provide more relevant and reliable information to users of financial statements. The amendment requires an enterprise to perform an analysis to determine whether the enterprise’s variable interest or interests give it a controlling financial interest in a variable interest entity. The new requirements shall be effective as of the beginning of each reporting entity’s first annual reporting period that begins after November 15, 2009. The adoption of this guidance did not have an impact on the Company’s financial position, results of operations or cash flows.

In May 2009, the FASB issued accounting guidance establishing the general standards of accounting for the disclosure of events that occur after the balance sheet date but before the financial statements are issued or are available to be issued. In particular, this FASB guidance requires enhanced disclosures about (a) events or transactions that may occur for potential recognition or disclosure in the financial statements in the period after the balance sheet date, (b) circumstances under which an entity should recognize such events, and (c) date through which an entity has evaluated subsequent events, including the basis for that date, and whether that date represents the date the financial statements were issued or available to be issued. The FASB guidance is effective for financial statements issued for interim and annual periods ending after June 15, 2009. The Company adopted this standard for the reporting period beginning April 1, 2010 and noted no impact on the Company’s financial position, results of operations or cash flows due to the adoption of this standard.

O. Reclassifications

Certain amounts from prior years have been reclassified in the accompanying financial statements to conform to the current year presentation. For the year ended March 31, 2010, a portion of the Company’s negative accounts payable balance was reclassified as a component of accounts receivable on the balance sheet. This reclassification had no effect on the Company’s results of operations and cash flows.

13

Note 2. Rates and Regulatory

The following table presents the Company’s regulatory assets and regulatory liabilities at March 31, 2011 and 2010:

	March 31,
(in thousands of dollars)	2011			2010
Regulatory assets - current
Rate adjustment mechanisms, included in accounts receivable	$	1,716		$	2,155
Regulatory liabilities - current
Rate adjustment mechanisms, included in other current liabilities		(1,957	)		(4	)
Total current regulatory assets		(241	)		2,151
Regulatory assets - non-current
Storm cost deferrals		4,752			3,380
Other		353			620
Total regulatory assets non-current		5,105			4,000
Regulatory liabilities - non-current
Regulatory tax liability		(2,479	)		(2,430	)
Postretirement benefits		(1,643	)		(1,816	)
Cost of removal		(4,663	)		(4,411	)
Total regulatory liabilities non-current		(8,785	)		(8,657	)
Total non-current regulatory liabilities, net		(3,680	)		(4,657	)
Net regulatory liabilities	$	(3,921	)	$	(2,506	)

The regulatory items above are not included in the utility rate base.

Rate Matters

In July 2007, the NHPUC approved a settlement agreement related to issues surrounding the merger of NGUSA and KeySpan Corporation (“KeySpan”) which also contained a five year distribution rate plan for the Company, effective January 1, 2008. During the rate plan, distribution rates are frozen except for rate adjustments in the event of certain uncontrollable exogenous events and annual rate adjustments related to specific Reliability Enhancement and Vegetation Management Plans (“REP/VMP”). In June 2010, the NHPUC approved the Company’s recent REP/VMP rate adjustment effective July 1, 2010 of $1.1 million; the Company’s fourth REP/VMP rate adjustment, which would result in incremental revenue of $1.7 million effective July 2011, is currently pending before the NHPUC. The rate plan also includes an earnings sharing mechanism based on an imputed capital structure of 50% debt and 50% equity and a return on equity (“ROE”) of 11%. Earnings above 11% are shared equally between customers and the Company. The rate plan also establishes a storm contingency fund and customer service commitments by the Company.

In April 2010, the Company filed a request with the NHPUC for a temporary increase in funding to its storm contingency fund of $0.7 million annually over 3 years to replenish the Company’s newly formed fund after the devastating ice storm in December 2008. An initial rate adjustment was approved by the NHPUC to increase funding by $0.4 million annually effective July 1, 2010. The approval of the remaining balance of $0.3 million in funding will occur in conjunction with the NHPUC’s review of costs related the two additional storms described below.

In April 2011, the Company filed its storm fund report with the NHPUC regarding a February 2010 winter storm having approximately $1.7 million in restoration costs. In March 2011, the Company experienced another significant storm event for which the costs have not yet been finalized. The Company will be seeking to recover its costs through its storm contingency fund.

14

Other Regulatory Matters

In November 2008, FERC commenced an audit of NGUSA, including its service companies and other affiliates in the National Grid holding company system. The audit evaluated our compliance with: 1) cross-subsidization restrictions on affiliate transactions; 2) accounting, recordkeeping and reporting requirements; 3) preservation of records requirements for holding companies and service companies; and 4) Uniform System of Accounts for centralized service companies. The final audit report from the FERC was received in February 2010. In April 2011, NGUSA replied to the FERC and outlined its plan to address the findings in the report, which we are currently in the process of implementing. None of the findings had a material impact on the financial statements of the Company.

Note 3. Employee Benefits

Summary

The Company participates with certain other NGUSA subsidiaries in a non-contributory defined benefit pension plan and a postretirement benefits other than pensions (“PBOP”) plan (the “Plans”).

The pension plan is a non-contributory, tax-qualified defined benefit plan which provides all employees with a minimum retirement benefit.

Supplemental nonqualified, non-contributory executive retirement programs provide additional defined pension benefits for certain executives.

PBOPs provide health care and life insurance coverage to eligible retired employees. Eligibility is based on age and length of service requirements and, in most cases, retirees must contribute to the cost of their coverage.

Pension Benefits

The Company participates in the pension plans with certain other NGUSA subsidiaries. Pension plan assets are commingled and cannot be allocated to an individual company. Pension costs are allocated to the Company. At March 31, 2011 and March 31, 2010, the pension plans of NGUSA have a net underfunded obligation of $354.8 million and $420.7 million, respectively. The Company’s net periodic pension cost for the year ended March 31, 2011 and 2010 was $0.8 million and $0.6 million, respectively.

Defined Contribution Plan

The Company has a defined contribution pension plan (employee savings fund plan) that covers substantially all employees. Employer matching contributions of $0.1 million was expensed for each of the years ended March 31, 2011 and March 31, 2010.

Postretirement Benefits Other Than Pension Benefits

The Company participates in the PBOP plans with certain other NGUSA subsidiaries. PBOP costs are allocated to the Company. The PBOP plans of NGUSA have a net underfunded obligation of $401.6 million and $477.3 million as of March 31, 2011 and March 31, 2010, respectively. The Company’s net periodic postretirement benefit cost for each of the years ended March 31, 2011 and March 31, 2010 was $0.6 million.

Health Care Reform Act

In March 2010, the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010 became law. These laws included provisions that resulted in the repeal, with effect from 2012, of the deduction for federal income tax purposes of the portion of the cost of an employer’s retiree prescription drug coverage for which the employer received a benefit under the Medicare Prescription Drug Improvement and Modernization Act of 2003. The consequential reduction in the deferred tax asset balance resulted in a net charge to the income statement of approximately $0 and $0.4 million for the years ended March 31, 2011 and March 31, 2010, respectively.

15

Workforce Reduction Program

In connection with National Grid plc’s acquisition of KeySpan, National Grid plc and KeySpan offered 673 non-union employees a voluntary early retirement offer (“VERO”) in an effort to reduce the workforce. Eligible employees must have been working in a targeted area as of April 13, 2007 and be at least 52 years of age with seven or more years of service as of September 30, 2007. For eligible employees who have elected to accept the VERO offer, National Grid plc and KeySpan had the right to retain that employee for up to three years before VERO payments are made. An employee who accepted the VERO offer but elects to terminate employment with National Grid plc or KeySpan prior to the three year period, without consent of National Grid plc or KeySpan, forfeits all rights to VERO payments. The VERO is completed and the Company has accrued $0.7 million which has been deferred for recovery from electric sales customers as part of the synergy savings and cost to achieve calculations.

Note 4. Debt

Short-term Debt

The Company has regulatory approval from the NHPUC to issue up to $10.0 million of short-term debt. The company had no short-term debt outstanding to third parties at March 31, 2011 or 2010.

Long-term Debt

At March 31, 2011 and 2010, the Company had outstanding $15.0 million of unsecured long-term notes. The interest rates on these unsecured notes range from 7.30% to 7.94% and the maturity dates extend from November 2023 to June 2028. These unsecured notes have certain restrictive covenants and acceleration clauses. These covenants stipulate that note holders may declare the debt to be due and payable if total debt becomes greater than 70% of total capitalization. At March 31, 2011 and 2010, the total long-term debt was 17% and 18% of total capitalization, respectively.

Note 5. Property, Plant and Equipment

At March 31, 2011 and March 31, 2010, property, plant and equipment at cost and accumulated depreciation and amortization are as follows:

	March 31,
(in thousands of dollars)	2011			2010
Plant and machinery	$	123,794		$	119,077
Land and buildings		6,887			6,570
Assets in construction		1,686			1,369
Software and other intangibles		25			25
Total		132,392			127,041
Accumulated depreciation and amortization		(48,617	)		(45,869	)
Property, plant and equipment, net	$	83,775		$	81,172

AFUDC

The Company capitalizes AFUDC as part of construction costs. AFUDC represents an allowance for the cost of funds used to finance construction and includes a debt component and an equity component. AFUDC is capitalized in “ Property, plant and equipment “ with offsetting cash credits to “Other interest, including affiliates interest” for the debt component and to “Other deductions” for the equity component. This method is in accordance with an established rate-making practice under which a utility is permitted to earn a return on, and the recovery of, prudently incurred capital costs through its ultimate inclusion in rate base and in the provision for depreciation. The composite AFUDC rates were 6.6% and 9.2% for the years ended March 31, 2011 and 2010, respectively. AFUDC capitalized during the years ended March 31, 2011 and March 31, 2010 was $0.06 million and $0.1 million, respectively.

Depreciation

Depreciation expense is determined using the straight-line method. The depreciation rates are based on periodic studies of the estimated useful lives of the assets and the estimated cost to remove them, net of salvage value. The Company performs depreciation studies to determine service lives of classes of property and adjusts the depreciation rates when necessary.

16

The provisions for depreciation, as a percentage of weighted average depreciable property, and the weighted average service life, in years, for each asset category for the years ended March 31, 2011 and 2010 are presented in the table below:

	2011					2010
	Provision			Service Life		Provision			Service Life
Asset Category:
Electric		3.7	%		27		3.6	%		27

Note 6. Income Taxes

Following is a summary of the components of federal and state income tax expense (benefit):

	Years Ended March 31,
(in thousands of dollars)	2011			2010
Components of federal and state income taxes:
Current tax expense (benefit):
Federal	$	(1,120	)	$	(4,475	)
State		583			(145	)
Total current tax benefit		(537	)		(4,620	)
Deferred tax expense (benefit):
Federal		1,464			4,772
State		(129	)		1,288
Total deferred tax expense		1,335			6,060
Investment tax credits (1)		(41	)		(45	)
Total income tax expense	$	757		$	1,395

⁽¹⁾  Investment tax credits (ITC) are being deferred and amortized over the depreciable life of the property giving rise to the credits

Income tax expense for the years ended March 31, 2011 and March 31, 2010 varied from the amount computed by applying the statutory rate to income before income taxes. A reconciliation of expected federal income tax expense, using the federal statutory rate of 35%, to the Company’s actual income tax expense for the years ended March 31, 2011 and March 31, 2010 is presented in the following table:

	Years Ended March 31,
(in thousands of dollars)	2011			2010
Computed tax	$	507		$	379
Increase (reduction) including those attributable to flow-through of certain tax adjustments:
State income tax, net of federal benefit		295			743
Investment tax credit		(41	)		(45	)
Medicare charge, including the Patient Protection and Affordable Care Act effect, net		—			320
Other items - net		(4	)		(2	)
Total	$	250		$	1,016
Federal and state income taxes	$	757		$	1,395

17

Significant components of the Company’s net deferred tax assets and liabilities at March 31, 2011 and March 31, 2010 are presented in the following table:

	March 31,
(in thousands of dollars)	2011			2010
Pensions, other post-employment benefits (“OPEB”), and other employee benefits	$	3,364		$	4,841
Regulatory liabilities - other		1,895			1,383
Unbilled revenue		1,055			1,287
Future federal benefit on state taxes		735			705
Other items		317			360
Total deferred tax assets(1)		7,366			8,576
Property related differences		(16,981	)		(15,558	)
Regulatory assets - storm costs		(2,071	)		(1,435	)
Other items		—			(936	)
Total deferred tax liabilities		(19,052	)		(17,929	)
Net accumulated deferred income tax liability		(11,686	)		(9,353	)
Deferred investment tax credit		(163	)		(204	)
Net accumulated deferred income tax liability and investment tax credit		(11,849	)		(9,557	)
Current portion of net deferred tax asset		1,390			1,245
Non-current portion of net deferred income tax liability and investment tax credit	$	(13,239	)	$	(10,802	)

⁽¹⁾  There were no valuation allowances for deferred tax assets at March 31, 2011 or 2010.

The Company is a member of the National Grid Holdings Inc. (“NGHI”) and subsidiaries consolidated federal income tax return. The Company has joint and several liabilities for any potential assessments against the consolidated group.

The Company adopted the provisions of the FASB guidance which clarifies the accounting and disclosures of uncertain tax positions in the financial statements. The guidance provides that the financial effects of a tax position shall initially be recognized when it is more likely than not, based on the technical merits, that the position will be sustained upon examination, assuming the position will be audited and the taxing authority has full knowledge of all relevant information.

As of March 31, 2011 and March 31, 2010, the Company’s unrecognized tax benefits totaled $3.4 million and $3.6 million, respectively, each of which $0.4 million would affect the effective tax rate, if recognized.

The unrecognized tax benefits are included in “other deferred liabilities” on the balance sheets.

The following table reconciles the changes to the Company’s unrecognized tax benefits for the years ended March 31, 2011 and March 31, 2010:

Reconciliation of Unrecognized Tax Benefits	Years Ended March 31,
(in thousands of dollars)	2011			2010
Beginning balance	$	3,638		$	1,351
Gross decrease related to prior year		(285	)		—
Gross increases related to current year		172			2,287
Settlements with tax authorities		(118	)		—
Ending balance	$	3,407		$	3,638

As of March 31, 2011 and March 31, 2010, the Company has accrued for interest related to unrecognized tax benefits of $0.1 million and $0.2 million, respectively. During the years ended March 31, 2011 and March 31, 2010, the Company recorded interest income of $0.03 million and interest expense of $0.02 million, respectively. The Company recognizes accrued interest related to unrecognized tax benefits in interest expense or interest income and related penalties, if applicable, in operating expenses. No penalties were recognized during the years ended March 31, 2011 and March 31, 2010.

18

Federal income tax returns have been examined and all issues have been agreed with the Internal Revenue Service (“IRS”) and the NGHI consolidated filing group through March 31, 2004. During the year ended March 31, 2011, the NGHI consolidated group reached an agreement with the IRS that contained a settlement of the majority of the income tax issues related to the years ended March 31, 2005 through March 31, 2007 as well as an acknowledgment that certain discrete items remained disputed.

The Company is in the process of appealing certain disputed issues with the IRS Office of Appeals relating to its tax returns for March 31, 2005 through March 31, 2007. The Company does not anticipate a change in its unrecognized tax positions in next twelve months as a result of the appeals. However, the Company’s tax sharing agreement may result in a change to allocated tax as a result of current and future audits or appeals. The years ended March 31, 2008 through March 31, 2011 remain subject to examination by the IRS.

The Company participates with certain other NGHI subsidiaries in filing a unitary New Hampshire business profits tax return. The New Hampshire unitary returns have been amended for all agreed IRS adjustments. There is currently no ongoing audit by the State of New Hampshire, although the tax returns for the years ended March 31, 2008 through March 31, 2011 are open under the statute of limitations.

Note 7. Fair Value Measurements

Available for sale securities are primarily in equities and are investments based on quoted market prices and municipal and corporate bonds based on quoted prices of similar traded assets in open markets.

The following table presents assets and liabilities measured and recorded at fair value on the Company’s Balance Sheet on a recurring basis and their level within the fair value hierarchy as of March 31, 2011:

(in thousands of dollars)	Level 1		Level 2		Level 3		Total
Assets
Available for sale securities	$	462	$	609	$	—	$	1,071
Total assets	$	462	$	609	$	—	$	1,071

Long-term debt is based on quoted market prices where available or calculated prices based on the remaining cash flows of the underlying bond discounted at the Company’s incremental borrowing rate. The Company’s Balance Sheets reflect the long term debt at carrying value. The fair value of this debt at March 31, 2011 is $19.0 million.

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Note 8. Accumulated Other Comprehensive Income (Loss)

The following table presents the components of accumulated other comprehensive income on the Company’s Balance Sheet:

(in thousands of dollars)	Unrealized Gain (Loss) on Available-for- Sale Securities			Postretirement Benefit Liability			Total Accumulated Other Comprehensive Income (Loss)
March 31, 2009 balance, net of tax	$	(31	)	$	(8,879	)	$	(8,910	)
Other comprehensive income (loss):
Unrealized gains on securities		115			—			115
Reclassification adjustment for loss		(19	)		—			(19	)
Net gain arising during period		—			90			90
Change in pension and postretirement benefits		—			361			361
March 31, 2010 balance, net of tax	$	65		$	(8,428	)	$	(8,363	)
Other comprehensive income (loss):
Unrealized gains on securities		40			—			40
Reclassification adjustment for loss		(29	)		—			(29	)
Change in pension and postretirement benefits		—			1,643			1,643
March 31, 2011 balance, net of tax	$	76		$	(6,785	)	$	(6,709	)

Note 9. Commitments and Contingencies

Purchase of Electric Power Contracts

The Company has several types of contracts for the purchase of electric power. Substantially all of these contracts require power to be delivered before the Company is obligated to make payment. The Company’s commitments under these contracts, as of March 31, 2011, are summarized in the table below:

(In thousands of dollars) Year Ended March 31,	Amount
2012	$	18,778

The Company purchases any additional energy needed to meet load requirements and can purchase the electricity from other independent power producers (“IPPs”), other utilities, other energy merchants, or the open market at market prices.

Legal Matters

The Company is subject to various legal proceedings arising out of the ordinary course of its business. Except as described below, the Company does not consider any of such proceedings to be material to its business or likely to result in a material adverse effect on its results of operations, financial condition, or cash flows.

Environmental Matters

The normal ongoing operations and historic activities of the Company are subject to various federal, state and local environmental laws and regulations. Like many other industrial companies, the Company generates hazardous waste. Under federal and state Superfund laws, potential liability for the historic contamination of property may be imposed on responsible parties jointly and severally, without fault, even if the activities were lawful when they occurred.

The Massachusetts Department of Environmental Protection has named the Company as a potentially responsible party for remediation of a site at which hazardous waste is alleged to have been disposed. The Company believes that obligations imposed on it because of environmental laws will not have a material impact on its results of operations or financial position.

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Note 10. Related Party Transactions

Moneypool

The Company participates with NGUSA and certain affiliates in a system moneypool. The moneypool is administered by the NGUSA service company as the agent for the participants. Short-term borrowing needs are met first by available funds of the moneypool participants. Borrowings from the moneypool bear interest at the higher of (i) the monthly average of the rate for high-grade, 30-day commercial paper sold through dealers by major corporations as published in the Wall Street Journal, or (ii) the monthly average of the rate then available to moneypool depositors from an eligible investment in readily marketable money market funds or the existing short-term investment accounts maintained by moneypool depositors or the NGUSA service company during the period in question. In the event neither rate is one that is permissible for a transaction because of constraints imposed by the state regulatory commission having jurisdiction over a utility participating in the transaction, the rate is adjusted to a permissible rate as determined under the requirements of the state regulatory commission. Companies that invest in the moneypool share the interest earned on a basis proportionate to their average monthly investment in the moneypool. Funds may be withdrawn from or repaid to the moneypool at any time without prior notice. The average interest rate for the moneypool was 0.27% for each of the years ended March 31, 2011 and 2010. The Company had a short-term moneypool investment of $7.5 million at March 31, 2011 and short-term moneypool borrowings of $1.6 million at March 31, 2010.

Advances to/from Affiliates

Additionally, the Company engages in various transactions with NGUSA and its affiliates. Certain activities and costs, such as executive and administrative, financial (including accounting, auditing, risk management, tax and treasure/finance), human resources, information technology, legal and strategic planning are shared between the companies and allocated to each company appropriately. In addition, the Company has a tax sharing agreement with NGHI, a NGUSA affiliate, in filing consolidated tax returns. The Company’s share of the tax liability is allocated resulting in a payment to or refund from NGHI. The Company had net accounts payable to affiliates of $2.0 million at March 31, 2011 and net accounts receivable from affiliates of $0.4 million at March 31, 2010, for those services.

Service Company Charges

The affiliated service companies of NGUSA provide certain services to the Company at their cost. The service company costs are generally allocated to associated companies through a tiered approach. First and foremost, costs are directly charged to the benefited company whenever practicable. Secondly, in cases where direct charging cannot be readily determined, costs are typically allocated using cost/causation principles linked to the relationship of that type of service, such as meters, square footage, number of employees, etc. Lastly, all other costs are allocated based on a general allocator. These costs include operating and capital expenditures of $7.4 million and $2.5 million for the year ended March 31, 2011 and $5.9 million and $2.1 million for the year ended March 31, 2010, respectively.

Holding Company Charges

NGUSA received charges from National Grid Commercial Holdings Limited (an affiliated company in the UK) for certain corporate and administrative services provided by the corporate functions of National Grid plc to its US subsidiaries. These charges, which are recorded on the books of NGUSA, have not been reflected on these financial statements. Were these amounts allocated to this subsidiary, the estimated effect on net income would be approximately $0.2 million and $0.1 million before taxes, and $0.1 million and $0.09 million after taxes, for the years ended March 31, 2011 and March 31, 2010, respectively.

Organization Restructuring

On January 31, 2011, National Grid plc announced substantial changes to the organization, including new global, US and UK operating models, and changes to the leadership team. The announced structure seeks to create a leaner, more-efficient business backed by streamlined operations that will help meet, more efficiently, the needs of regulators, customers and shareholders. The implementation of the new U.S. business structure commences on April 4, 2011 and targets annualized savings of $200 million by March 2012 primarily through the reduction of up to 1,200 positions. As of March 31, 2011, NGUSA had recorded a $66.8 million reserve for one-time employment termination benefits related to severance, payroll

21

taxes, healthcare continuation, and outplacement services as well as consulting fees related to the restructuring program. These charges have been recorded by NGUSA and none have been allocated to the Company as at March 31, 2011. Subsequently in June 2011, we offered a voluntary severance plan to certain individuals which is expected to cost up to an additional $20 million across all entities affiliated with NGUSA.

Note 11. Restrictions on Payments of Dividends

Pursuant to the provisions of the long-term note agreement, payment of dividends on common stock would not be permitted if, after giving effect to such payment of dividends, common equity becomes less than 30% of total capitalization. At March 31, 2011 and 2010, common equity was 83% and 82% of total capitalization, respectively. Under these provisions, none of the Company’s retained earnings at March 31, 2011 and March 31, 2010 were restricted as to common dividends.

Note 12. Subsequent Events

In accordance with current authoritative accounting guidance, the Company has evaluated for disclosure subsequent events that have occurred up through June 29, 2011, the date of issuance of these financial statements. As of June 29, 2011, there were no subsequent events which required recognition or disclosure.

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Granite State Electric Company

Financial Statements

For the quarters ended March 31, 2011 and March 31, 2010

(unaudited)

GRANITE STATE ELECTRIC COMPANY

TABLE OF CONTENTS

	Page No.
Balance Sheets March 31, 2011 and March 31, 2010		2
Statements of Operations Three Months Ended March 31, 2011 and March 31, 2010		4
Statements of Cash Flows Three Months Ended March 31, 2011 and March 31, 2010		5
Statements of Comprehensive Income Three Months Ended March 31, 2011 and March 31, 2010		6
Notes to Unaudited Financial Statements		7

1

GRANITE STATE ELECTRIC COMPANY

BALANCE SHEETS

(in thousands of dollars, except per share and number of shares data)

	March 31, 2011			March 31, 2010
ASSETS
Current assets:
Cash and cash equivalents	$	220		$	587
Restricted cash		3,277			3,070
Accounts receivable		10,101			9,767
Allowance for doubtful accounts		(558	)		(489	)
Accounts receivable from affiliates, net		—			365
Intercompany moneypool		7,500			—
Unbilled revenues		1,037			830
Materials and supplies, at average cost		499			449
Current deferred income tax assets		1,390			1,245
Prepaid and other current assets		1,942			7,132
Total current assets		25,408			22,956
Property, plant and equipment, net		83,775			81,172
Deferred charges and other assets:
Regulatory assets		5,105			4,000
Goodwill		19,352			19,352
Other deferred charges		1,191			1,099
Total deferred charges and other assets		25,648			24,451
Total assets	$	134,831		$	128,579

The accompanying notes are an integral part of these financial statements.

2

GRANITE STATE ELECTRIC COMPANY

BALANCE SHEETS

(in thousands of dollars, except per share and number of shares data)

	March 31, 2011			March 31, 2010
LIABILITIES AND CAPITALIZATION
Current liabilities:
Accounts payable	$	6,983		$	7,145
Accounts payable to affiliates, net		2,017			—
Taxes accrued		332			63
Customer deposits		545			349
Interest accrued		492			583
Intercompany moneypool		—			1,575
Regulatory liabilities		999			4
Other current liabilities		2,778			1,757
Total current liabilities		14,146			11,476
Deferred credits and other liabilities:
Regulatory liabilities		8,785			8,657
Deferred income tax liabilities		13,239			10,802
Postretirement benefits and other reserves		6,457			8,768
Other deferred liabilities		4,810			3,828
Total deferred credits and other liabilities		33,291			32,055
Capitalization
Shareholders’ equity:
Common stock, $100 per share, issued and outstanding 60,400 shares		6,040			6,040
Additional paid-in capital		40,054			40,054
Retained earnings		33,009			32,317
Accumulated other comprehensive loss		(6,709	)		(8,363	)
Total shareholders’ equity		72,394			70,048
Long-term debt		15,000			15,000
Total capitalization		87,394			85,048
Total liabilities and capitalization	$	134,831		$	128,579

The accompanying notes are an integral part of these financial statements.

3

GRANITE STATE ELECTRIC COMPANY

STATEMENTS OF OPERATIONS

(unaudited, in thousands of dollars)

	Three Months Ended March 31,
	2011			2010
Operating revenues	$	21,774		$	22,638
Operating expenses:
Electricity purchased for resale		11,135			11,899
Operations and maintenance		8,817			6,887
Depreciation and amortization		1,235			1,171
Other taxes		808			719
Total operating expenses		21,995			20,676
Operating (loss) income		(221	)		1,962
Other income and (deductions):
Interest on long-term debt		(283	)		(283	)
Other interest, including affiliate interest		6			(82	)
Other (deductions) income, net		(80	)		61
Total other deductions		(357	)		(304	)
(Loss) income before income taxes		(578	)		1,658
Income tax (benefit) expense		(339	)		1,442
Net (loss) income	$	(239	)	$	216

The accompanying notes are an integral part of these financial statements

4

GRANITE STATE ELECTRIC COMPANY

STATEMENTS OF CASH FLOWS

(unaudited, in thousands of dollars)

	Three Months Ended March 31,
	2011			2010
Operating activities:
Net (loss) income	$	(239	)	$	216
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation and amortization		1,235			1,171
Provision (benefit) of deferred income taxes		1,776			(938	)
Regulatory deferrals		806			(800	)
Net pension and other postretirement expense		278			98
Changes in operating assets and liabilities:
Accounts receivable, net		98			(690	)
Materials and supplies		(5	)		(53	)
Accounts payable and accrued expenses		331			621
Prepaid taxes and accruals		(1,373	)		1,555
Accounts receivable and payable affiliate, net		1,895			951
Other, net		(718	)		544
Net cash provided by operating activities		4,084			2,675
Investing activities:
Capital expenditures		(1,679	)		(2,118	)
Changes in intercompany moneypool		(2,000	)		—
Restricted cash		(1	)		—
Other, including cost of removal		(263	)		(487	)
Net cash used in investing activities		(3,943	)		(2,605	)
Financing activities:
Changes in intercompany moneypool		—			300
Net increase in cash and cash equivalents		141			370
Cash and cash equivalents, beginning of period		79			217
Cash and cash equivalents, end of period	$	220		$	587

The accompanying notes are an integral part of these financial statements

5

GRANITE STATE ELECTRIC COMPANY

STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(unaudited, in thousands of dollars)

	Three Months Ended March 31,
	2011			2010
Net (loss) income	$	(239	)	$	216
Other comprehensive income (loss), net of taxes:
Unrealized gains on investments		8			18
Change in pension and other postretirement obligations		600			(391	)
Reclassification adjustment for losses included in net income		(7	)		(6	)
Change in other comprehensive income (loss)		601			(379	)
Total comprehensive income (loss)	$	362		$	(163	)
Related tax expense (benefit):
Unrealized gains on investments	$	(5	)	$	(12	)
Change in pension and other postretirement obligations		(400	)		261
Reclassification adjustment for losses included in net income		5			4
Total tax (benefit) expense	$	(400	)	$	253

The accompanying notes are an integral part of these financial statements

6

GRANITE STATE ELECTRIC COMPANY

NOTES TO UNAUDITED FINANCIAL STATEMENTS

Note 1. Summary of Significant Accounting Policies

A. Nature of Operations

Granite State Electric Company (the “Company”, “we”, “us”, and “our”) is an electric retail distribution company providing electric service to approximately 43,000 customers in 21 communities in New Hampshire. The properties of the Company consist principally of substations and distribution lines interconnected with transmission and other facilities of New England Power Company, a wholly owned subsidiary of National Grid USA (“NGUSA”).

The Company is a wholly-owned subsidiary of NGUSA, a public utility holding company with regulated subsidiaries engaged in the generation of electricity and the transmission, distribution and sale of both natural gas and electricity. NGUSA is an indirectly-owned subsidiary of National Grid plc, a public limited company incorporated under the laws of England and Wales.

On December 8, 2010, NGUSA and Liberty Energy Utilities Co. (“Liberty Energy”), a subsidiary of Algonquin Power & Utilities Corp,, entered into a stock purchase agreement which was subsequently amended and restated on January 21,2011, pursuant to which NGUSA will sell and Liberty Energy will purchase all of the common stock of the Company. The parties have filed the necessary federal and state regulatory approvals that will be required to consummate the transaction with the Federal Energy Regulatory Commission (“FERC”) and New Hampshire Public Utilities Commission (“NHPUC”). The regulatory approval process is expected to be completed during the year ended March 31, 2012.

The Company has evaluated subsequent events and transactions through the September 22, 2011, and concluded that except as discussed in Note 8, there were no events or transactions that require adjustment to, or disclosure in the notes to, the financial statements.

B. Basis of Presentation

The accompanying financial statements are unaudited and have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The year-end balance sheet data was derived from audited financial statements, but does not include all disclosure required by GAAP. These financial statements should be read in conjunction with the year-end audited financial statements. No significant changes have been made to the Company’s accounting policies and estimates that have been disclosed in its year-end financial statements.

In the opinion of management, the financial statements as of March 31, 2011, and for the three months ended March 31, 2011 and 2010, include all adjustments (consisting of normal recurring accruals) necessary for a fair statement of the financial position, results of operations and cash flows for the periods presented. The results of operations for the three months ended March 31, 2011 and 2010, are not necessarily indicative of the results to be expected for the full year or any other period.

Management makes estimates and assumptions that affect the amounts reported in the unaudited financial statements and notes. Although these estimates are based on management’s best available information at the time, actual results could differ.

C. Regulatory Accounting

The NHPUC provide the final determination of the rates we charge our customers. In certain cases, the actions of the FERC or the NHPUC would result in an accounting treatment different from that used by non-regulated companies to determine the rates we charge our customers. In this case, the Company is required to recognize costs (a regulatory asset) or to recognize obligations (a regulatory liability) if it is probable that these amounts will be recovered or refunded through the rate-making process, which would result in a corresponding increase or decrease in future rates.

In the event the Company determines that its net regulatory assets are not probable of recovery, it would no longer apply the principles of the current accounting guidance for rate regulated enterprises and would be required to record an after-tax, non-cash charge against income for any remaining regulatory assets and liabilities. The impact could be material to the Company’s reported financial condition and results of operations.

7

D. Fair Value Measurements

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The following is the fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:

Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that a company has the ability to access as of the reporting date.

Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data.

Level 3 — unobservable inputs, such as internally-developed forward curves and pricing models for the asset or liability due to little or no market activity for the asset or liability with low correlation to observable market inputs.

E. Recent Accounting Pronouncements

In June 2011, the Financial Accounting Standards Board (“FASB”) issued accounting guidance that eliminated the option to present the components of other comprehensive income as part of the statement of changes in stockholders’ equity. This update seeks to improve financial statement users’ ability to understand the causes of an entity’s change in financial position and results of operations. The Company is now required to either present the statement of income and statement of comprehensive income in a single continuous statement or in two separate, but consecutive statements of income and comprehensive income. This update does not change the items that are reported in other comprehensive income or any reclassification of items to net income. Additionally, the update does not change an entity’s option to present components of other comprehensive income net of or before related tax effects. This guidance is effective for non-public companies for fiscal years ending after December 15, 2012, and for interim and annual periods thereafter, and it is to be applied retrospectively. Early adoption is permitted. The Company does not expect adoption of this guidance to have an impact on the Company’s financial position, results of operations or cash flows.

In April 2011, the FASB issued accounting guidance that substantially amended existing guidance with respect to the fair value measurement topic (“the Topic”). The guidance seeks to amend the Topic in order to achieve common fair value measurement and disclosure requirements in GAAP and International Financial Reporting Standards. Consequently, the guidance changes the wording used to describe many of the requirements in GAAP for measuring fair value and for disclosing information about fair value measurements as well as changing specific applications of the Topic. Some of the amendments clarify the FASB’s intent about the application of existing fair value measurement requirements. Other amendments change a particular principle or requirement for measuring fair value or for disclosing information about fair value measurements including, but not limited to, fair value measurement of a portfolio of financial instruments, fair value measurement of premiums and discounts and additional disclosures about fair value measurements. This guidance is effective for financial statements issued for annual periods beginning after December 15, 2011. The early adoption of this guidance for non-public companies is permitted but only for interim periods beginning after December 15, 2011. The Company is currently determining the potential impact of the guidance on its financial position, results of operations and cash flows.

F. Reclassifications

Except for the reclassification of approximately $1 million from other current liabilities to current regulatory liabilities at March 31, 2011, no other changes were made to prior period financial statements. This reclassification had no effect on the Company’s results of operations and cash flows.

Note 2. Rates and Regulatory

Rate Matters

In July 2007, the NHPUC approved a settlement agreement related to issues surrounding the merger of NGUSA and KeySpan Corporation (“KeySpan”), which also contained a five-year distribution rate plan for the Company, effective January 1, 2008, During the rate plan, distribution rates are frozen except for rate adjustments in the event of certain uncontrollable exogenous events and annual rate adjustments related to specific Reliability Enhancement Plan and Vegetation Management Plan (“REP/VMP”). In June 2010, the NHPUC approved the Company’s REP/VMP rate increase

8

effective July 1, 2010 of $1.1 million. In June 2011, the NHPUC approved the Company’s fourth REP/VMP rate adjustment, effective July 1, 2011, which resulted in a revenue decrease of $1.7 million. The rate plan also includes an earnings sharing mechanism based on an imputed capital structure of 50% debt and 50% equity and a return on equity of 11%. Earnings above 11% are shared equally between customers and the Company. The rate plan also establishes a storm contingency fund and customer service commitments by the Company.

In April 2010, the Company filed a request with the NHPUC for a temporary increase in funding to its storm contingency fund of $0.7 million annually over three years to replenish the Company’s newly formed fund after a major ice storm in December 2008. An initial rate adjustment was approved by the NHPUC to increase funding by $0.4 million annually effective July 1, 2010. The approval of the remaining balance of $0.3 million in annual funding will occur in conjunction with the NHPUC’s review of costs related to the two additional storms. A February 2010 winter storm having approximately $1.7 million in restoration costs was reported to the NHPUC in the Company’s April 2011 storm fund report. In March 2011, the Company experienced another significant storm event for which the company incurred approximately $1.7 million in restoration costs which as of the date of this report, has not been reported to NHPUC. The Company will be seeking to recover its costs through its storm contingency fund.

Other Regulatory Matters

In November 2008, FERC commenced an audit of NGUSA, including its service companies and other affiliates in the National Grid holding company system. The audit evaluated our compliance with: 1) cross-subsidization restrictions on affiliate transactions; 2) accounting, recordkeeping and reporting requirements; 3) preservation of records requirements for holding companies and service companies; and 4) Uniform System of Accounts for centralized service companies. The final audit report from the FERC was received in February 2011. In April 2011, NGUSA replied to the FERC and outlined its plan to address the findings in the report, which we are currently in the process of implementing. None of the findings had a material impact on the financial statements of the Company.

Note 3. Employee Benefits

The Company participates with certain other NGUSA subsidiaries in a non-contributory defined benefit pension plan (“Pension Plan”) and a pension and postretirement benefits other than pensions plan (“PBOP”, together with Pension Plan, the “Plan”). The Pension plan is a non-contributory, tax-qualified defined benefit plan which provides all employees with a minimum retirement benefit. Supplemental nonqualified, non-contributory executive retirement programs provide additional defined pension benefits for certain executives. PBOPs provide health care and life insurance coverage to eligible retired employees. Eligibility is based on age and length of service requirements and, in most cases, retirees must contribute to the cost of their coverage.

The Company participates in the Plan with certain other NGUSA subsidiaries. Plan assets are commingled and cannot be allocated to an individual company. Plan costs are allocated to the Company. The net Pension Plan expense allocated to the Company for the three months ended March 31, 2011 and March 31, 2010 was $0.3 million and $0.1 million, respectively. The net PBOP expenses allocated to the Company for the three months ended March 31, 2011 and March 31, 2010 was $0.3 million and $0.2 million, respectively. These costs are included as operations and maintenance expenses in the accompanying financial statements.

Workforce Reduction Program

In connection with National Grid plc’s acquisition of KeySpan, National Grid plc and KeySpan offered 673 non-union employees a voluntary early retirement offer (“VERO”) in an effort to reduce the workforce. The VERO was completed and the Company accrued $0.7 million which has been deferred for recovery from electric sales customers as part of the synergy savings and cost to achieve calculations.

Note 4. Income Taxes

The effective tax rate for the Company for the three months ended March 31, 2011 and March 31, 2010 was 58.63% and 86.95%, respectively. Included in taxes for both quarters was state tax expense of $0.1 million and $0.5 million, respectively, related to inter-corporate state tax sharing agreements with the Company’s parent. Excluding this charge the Company’s effective tax rate for the three months ended March 31, 2011 and March 31, 2010 would be 39.44% and 58.08%, respectively. In addition, tax expense for the three months ended March 31, 2010 included deferred tax charge related to provisions in the Patient Protection Act of 2010 which increased the tax rate by 24.55% for the quarter.

9

Note 5. Fair Value Measurements

Available for sale securities are primarily in equities and are investments based on quoted market prices and municipal and corporate bonds based on quoted prices of similar traded assets in open markets.

The following table presents assets and liabilities measured and recorded at fair value on the Company’s balance sheet on a recurring basis and their level within the fair value hierarchy as of March 31, 2011 and March 31,2010:

March 31, 2011

(in thousands of dollars)	Level 1		Level 2		Level 3		Total
Assets
Available for sale securities	$	462	$	609	$	—	$	1,071
Total assets	$	462	$	609	$	—	$	1,071

March 31, 2010

(in thousands of dollars)	Level 1		Level 2		Level 3		Total
Assets
Available for sale securities	$	437	$	579	$	—	$	1,016
Total assets	$	437	$	579	$	—	$	1,016

Note 6. Commitments and Contingencies

Legal Matters

The Company is subject to various legal proceedings arising out of the ordinary course of its business. Except as described below, the Company does not consider any of such proceedings to be material individually or in the aggregate to its business or likely to result in a material adverse effect on its results of operations, financial condition, or cash flows.

Environmental Matters

The normal ongoing operations and historic activities of the Company are subject to various federal, state and local environmental laws and regulations. Like many other industrial companies, the Company generates hazardous waste. Under federal and state Superfund laws, potential liability for the historic contamination of property may be imposed on responsible parties jointly and severally, without fault, even if the activities were lawful when they occurred.

The New Hampshire Department of Environmental Protection has named the Company as a potentially responsible party for remediation of a site at which hazardous waste is alleged to have been disposed. The Company believes that obligations imposed on it because of environmental laws will not have a material impact on its financial condition.

Note 7. Related Party Transactions

Intercompany Moneypool

The Company participates with NGUSA and certain affiliates in a system moneypool. The moneypool is administered by the NGUSA service company as the agent for the participants. Short-term borrowing needs are met first by available funds of the moneypool participants. Companies that invest in the moneypool share the interest earned on a basis proportionate to their average monthly investment in the moneypool. Interest rates associated with the moneypool are designed to approximate the cost of third-party short-term borrowings. Funds may be withdrawn from or repaid to the moneypool at any time without prior notice. The Company had a short-term moneypool investment of $7.5 million at March 31, 2011 and short-term moneypool borrowings of $1.6 million at March 31, 2010.

10

Accounts receivable from/payable to associated companies

Additionally, the Company engages in various transactions with NGUSA and its affiliates. Certain activities and costs, such as executive and administrative, financial (including accounting, auditing, risk management, tax and treasure/finance), human resources, information technology, legal and strategic planning are shared between the companies and allocated to each company appropriately. In addition, the Company has a tax sharing agreement with National Grid Holdings Inc. (“NGHI”), a NGUSA affiliate, in filing consolidated tax returns. The Company’s share of the tax liability is allocated resulting in a payment to or refund from NGHI.

The Company records short-term payables to and receivables from certain of its associates in the ordinary course of business. The amounts payable to and receivable from its associates do not bear interest. At March 31, 2011 and March 31, 2010, the Company had outstanding receivable and payable positions as follows:

	Accounts Payable To		Accounts Receivable From
	March 31, 2011		March 31, 2010
Massachsetts Electric Co.	$	894	$	1,186
New England Power Co.		336		—
Niagara Mohawk Power Corp.		—		1,118
Narragansett Electric Co.		—		(766	)
NGUSA Service Co.		259		(748	)
KeySpan Corp. Services LLC		314		—
Other, net		214		(425	)
Total	$	2,017	$	365

Service Company Charges

The affiliated service companies of NGUSA provide certain services to the Company at their cost. The service company costs are generally allocated to associated companies through a tiered approach. First and foremost, costs are directly charged to the benefited company whenever practicable. Secondly, in cases where direct charging cannot be readily determined, costs are typically allocated using cost/causation principles linked to the relationship of that type of service, such as meters, square footage, number of employees, etc. Lastly, all other costs are allocated based on a general allocator. These costs include operating and capital expenditures of $1.9 million and $0.7 million for the three months ended March 31, 2011 and $2.6 million and $0.9 million for the three months ended March 31, 2010, respectively.

Organization Restructuring

On January 31, 2011, National Grid plc announced substantial changes to the organization, including new global, US and UK operating models, and changes to the leadership team. The announced structure seeks to create a leaner, more-efficient business backed by streamlined operations that will help meet, more efficiently, the needs of regulators, customers and shareholders. The implementation of the new U.S. business structure commenced on April 4, 2011 and targets annualized savings of $200 million by March 2012 primarily through the reduction of approximately 1,200 positions. As of March 31, 2011, NGUSA had recorded $66.8 million reserve for one-time employment termination benefits related to severance, payroll taxes, healthcare continuation, outplacement services as well as consulting fees related to the restructuring program. During the quarter ended June 30, 2011, NGUSA reduced this reserve by $15.1 million due to payment of one-time employment termination benefits which was allocated to various affiliated entities, the Company’s portion of which is approximately $0.1 million. In June 2011, we offered a voluntary severance plan to certain individuals which is expected to cost up to an additional $20 million across all entities affiliated with NGUSA.

Note 8. Subsequent Event

The Company’s service territory was impacted by Hurricane Irene on August 28, 2011, which resulted in approximately 8,000 customers without electric power. The Company was involved in unprecedented restoration efforts throughout its service area which resulted in estimated storm-related cost of approximately $0.3 million for the repair and replacement of electric distribution systems damaged during the storm. The Company has the ability to recover these storm costs in its future rates.

11

Granite State Electric Company

Financial Statements

For the quarters ended June 30, 2011 and June 30, 2010

(unaudited)

GRANITE STATE ELECTRIC COMPANY

TABLE OF CONTENTS

	Page No.
Balance Sheets June 30, 2011 and March 31, 2011		2
Statements of Income Three Months Ended June 30, 2011 and June 30, 2010		4
Statements of Cash Flows Three Months Ended June 30, 2011 and June 30, 2010		5
Statements of Comprehensive Income Three Months Ended June 30, 2011 and June 30, 2010		6
Notes to Unaudited Financial Statements		7

1

GRANITE STATE ELECTRIC COMPANY

BALANCE SHEETS

(in thousands of dollars, except per share and number of shares data)

	June 30, 2011			March 31, 2011
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	374		$	220
Restricted cash		3,270			3,277
Accounts receivable		9,708			10,101
Allowance for doubtful accounts		(576	)		(558	)
Accounts receivable from affiliates, net		4			—
Intercompany moneypool		3,625			7,500
Unbilled revenues		1,060			1,037
Materials and supplies, at average cost		540			499
Current deferred income tax assets		1,166			1,390
Prepaid and other current assets		3,285			1,942
Total current assets		22,456			25,408
Property, plant and equipment, net		84,279			83,775
Deferred charges and other assets:
Regulatory assets		4,965			5,105
Goodwill		19,352			19,352
Other deferred charges		1,119			1,191
Total deferred charges and other assets		25,436			25,648
Total assets	$	132,171		$	134,831

The accompanying notes are an integral part of these financial statements.

2

GRANITE STATE ELECTRIC COMPANY

BALANCE SHEETS

(in thousands of dollars, except per share and number of shares data)

	June 30, 2011			March 31, 2011
	(unaudited)
LIABILITIES AND CAPITALIZATION
Current liabilities:
Accounts payable	$	6,272		$	6,983
Accounts payable to affiliates, net		—			2,017
Taxes accrued		703			332
Customer deposits		644			545
Interest accrued		150			492
Regulatory liabilities		560			999
Other current liabilities		2,437			2,778
Total current liabilities		10,766			14,146
Deferred credits and other liabilities:
Regulatory liabilities		8,537			8,785
Deferred income tax liabilities		13,829			13,239
Postretirement benefits and other reserves		6,335			6,457
Other deferred liabilities		4,819			4,810
Total deferred credits and other liabilities		33,520			33,291
Capitalization
Shareholders’ equity:
Common stock, $100 per share, issued and outstanding 60,400 shares		6,040			6,040
Additional paid-in capital		40,054			40,054
Retained earnings		33,403			33,009
Accumulated other comprehensive loss		(6,612	)		(6,709	)
Total shareholders’ equity		72,885			72,394
Long-term debt		15,000			15,000
Total capitalization		87,885			87,394
Total liabilities and capitalization	$	132,171		$	134,831

The accompanying notes are an integral part of these financial statements.

3

GRANITE STATE ELECTRIC COMPANY

STATEMENTS OF INCOME

(unaudited, in thousands of dollars)

	Three Months Ended June 30,
	2011			2010
Operating revenues	$	19,810		$	19,162
Operating expenses:
Electricity purchased for resale		9,892			10,721
Operations and maintenance		6,876			5,813
Depreciation and amortization		1,257			1,194
Other taxes		724			680
Total operating expenses		18,749			18,408
Operating income		1,061			754
Other income and (deductions):
Interest on long-term debt		(283	)		(283	)
Other interest, including affiliate interest		(34	)		(21	)
Other (deductions) income, net		(11	)		5
Total other deductions		(328	)		(299	)
Income before income taxes		733			455
Income tax expense		339			267
Net income	$	394		$	188

The accompanying notes are an integral part of these financial statements

4

GRANITE STATE ELECTRIC COMPANY

STATEMENTS OF CASH FLOWS

(unaudited, in thousands of dollars)

	Three Months Ended June 30,
	2011			2010
Operating activities;
Net income	$	394		$	188
Adjustments to reconcile net income to net cash (used in) provided by operating activities:
Depreciation and amortization		1,257			1,194
Benefit of deferred income taxes		767			322
Regulatory deferrals		(679	)		(928	)
Net pension and other postretirement expense		70			34
Changes in operating assets and liabilities:
Accounts receivable, net		628			(608	)
Materials and supplies		(41	)		36
Accounts payable and accrued expenses		(763	)		(782	)
Prepaid taxes and accruals		(993	)		3,511
Accounts receivable and payable affiliate, net		(2,021	)		(407	)
Other, net		(172	)		632
Net cash (used in) provided by operating activities		(1,553	)		3,192
Investing activities:
Capital expenditures		(1,619	)		(1,728	)
Changes in intercompany moneypool		3,875			(75	)
Restricted cash		7			—
Other, including cost of removal		(556	)		(80	)
Net cash provided by (used in) investing activities		1,707			(1,883	)
Financing activities:
Changes in intercompany moneypool		—			(1,575	)
Net increase (decrease) in cash and cash equivalents		154			(266	)
Cash and cash equivalents, beginning of period		220			587
Cash and cash equivalents, end of period	$	374		$	321

The accompanying notes are an integral part of these financial statements

5

GRANITE STATE ELECTRIC COMPANY

STATEMENTS OF COMPREHENSIVE INCOME

(unaudited, in thousands of dollars)

	Three Months Ended June 30,
	2011			2010
Net income	$	394		$	188
Other comprehensive income (loss), net of taxes:
Unrealized losses on investments		(6	)		(15	)
Change in pension and other postretirement obligations		114			123
Reclassification adjustment for losses included in net income		(11	)		(7	)
Change in other comprehensive income		97			101
Total comprehensive income	$	491		$	289
Related tax expense (benefit):
Unrealized losses on investments	$	4		$	10
Change in pension and other postretirement obligations		(76	)		(82	)
Reclassification adjustment for losses included in net income		7			5
Total tax benefit	$	(65	)	$	(67	)

The accompanying notes are an integral part of these financial statements

6

GRANITE STATE ELECTRIC COMPANY

NOTES TO UNAUDITED FINANCIAL STATEMENTS

Note 1. Summary of Significant Accounting Policies

A. Nature of Operations

Granite State Electric Company (the “Company”, “we”, “us”, and “our”) is an electric retail distribution company providing electric service to approximately 43,000 customers in 21 communities in New Hampshire. The properties of the Company consist principally of substations and distribution lines interconnected with transmission and other facilities of New England Power Company, a wholly owned subsidiary of National Grid USA (“NGUSA”).

The Company is a wholly-owned subsidiary of NGUSA, a public utility holding company with regulated subsidiaries engaged in the generation of electricity and the transmission, distribution and sale of both natural gas and electricity. NGUSA is an indirectly-owned subsidiary of National Grid pic, a public limited company incorporated under the laws of England and Wales.

On December 8, 2010, NGUSA and Liberty Energy Utilities Co. (“Liberty Energy”), a subsidiary of Algonquin Power & Utilities Corp., entered into a stock purchase agreement which was subsequently amended and restated on January 21, 2011, pursuant to which NGUSA will sell and Liberty Energy will purchase all of the common stock of the Company. The parties have filed the necessary federal and state regulatory approvals that will be required to consummate the transaction with the Federal Energy Regulatory Commission (“FERC”) and New Hampshire Public Utilities Commission (“NHPUC”). The regulatory approval process is expected to be completed during the year ended March 31, 2012.

The Company has evaluated subsequent events and transactions through the September 22, 2011, and concluded that except as discussed in Note 8, there were no events or transactions that require adjustment to, or disclosure in the notes to, the financial statements.

B. Basis of Presentation

The accompanying financial statements are unaudited and have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The year-end balance sheet data was derived from audited financial statements, but does not include all disclosure required by GAAP. These financial statements should be read in conjunction with the year-end audited financial statements. No significant changes have been made to the Company’s accounting policies and estimates that have been disclosed in its year-end financial statements.

In the opinion of management, the financial statements as of June 30, 2011, and for the three months ended June 30, 2011 and 2010, include all adjustments (consisting of normal recurring accruals) necessary for a fair statement of the financial position, results of operations and cash flows for the periods presented. The results of operations for the three months ended June 30, 2011 and 2010, are not necessarily indicative of the results to be expected for the full year or any other period.

Management makes estimates and assumptions that affect the amounts reported in the unaudited financial statements and notes. Although these estimates are based on management’s best available information at the time, actual results could differ.

C. Regulatory Accounting

The NHPUC provide the final determination of the rates we charge our customers. In certain cases, the actions of the FERC or the NHPUC would result in an accounting treatment different from that used by non-regulated companies to determine the rates we charge our customers. In this case, the Company is required to recognize costs (a regulatory asset) or to recognize obligations (a regulatory liability) if it is probable that these amounts will be recovered or refunded through the rate-making process, which would result in a corresponding increase or decrease in future rates.

In the event the Company determines that its net regulatory assets are not probable of recovery, it would no longer apply the principles of the current accounting guidance for rate regulated enterprises and would be required to record an after-tax, non-cash charge against income for any remaining regulatory assets and liabilities. The impact could be material to the Company’s reported financial condition and results of operations.

7

D. Fair Value Measurements

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The following is the fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:

Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that a company has the ability to access as of the reporting date.

Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data.

Level 3 — unobservable inputs, such as internally-developed forward curves and pricing models for the asset or liability due to little or no market activity for the asset or liability with low correlation to observable market inputs.

E. Recent Accounting Pronouncements

In June 2011, the Financial Accounting Standards Board (“FASB”) issued accounting guidance that eliminated the option to present the components of other comprehensive income as part of the statement of changes in stockholders’ equity. This update seeks to improve financial statement users’ ability to understand the causes of an entity’s change in financial position and results of operations. The Company is now required to either present the statement of income and statement of comprehensive income in a single continuous statement or in two separate, but consecutive statements of income and comprehensive income. This update does not change the items that are reported in other comprehensive income or any reclassification of items to net income. Additionally, the update does not change an entity’s option to present components of other comprehensive income net of or before related tax effects. This guidance is effective for non-public companies for fiscal years ending after December 15, 2012, and for interim and annual periods thereafter, and it is to be applied retrospectively. Early adoption is permitted. The Company does not expect adoption of this guidance to have an impact on the Company’s financial position, results of operations or cash flows.

In April 2011, the FASB issued accounting guidance that substantially amended existing guidance with respect to the fair value measurement topic (“the Topic”). The guidance seeks to amend the Topic in order to achieve common fair value measurement and disclosure requirements in GAAP and International Financial Reporting Standards. Consequently, the guidance changes the wording used to describe many of the requirements in GAAP for measuring fair value and for disclosing information about fair value measurements as well as changing specific applications of the Topic. Some of the amendments clarify the FASB’s intent about the application of existing fair value measurement requirements. Other amendments change a particular principle or requirement for measuring fair value or for disclosing information about fair value measurements including, but not limited to, fair value measurement of a portfolio of financial instruments, fair value measurement of premiums and discounts and additional disclosures about fair value measurements. This guidance is effective for financial statements issued for annual periods beginning after December 15, 2011. The early adoption of this guidance for non-public companies is permitted but only for interim periods beginning after December 15, 2011. The Company is currently determining the potential impact of the guidance on its financial position, results of operations and cash flows.

F. Reclassifications

Except for the reclassification of approximately $1 million from other current liabilities to current regulatory liabilities at March 31, 2011, no other changes were made to prior period financial statements. This reclassification had no effect on the Company’s results of operations and cash flows.

Note 2. Rates and Regulatory

Rate Matters

In July 2007, the NHPUC approved a settlement agreement related to issues surrounding the merger of NGUSA and KeySpan Corporation (“KeySpan”), which also contained a five-year distribution rate plan for the Company, effective January 1, 2008. During the rate plan, distribution rates are frozen except for rate adjustments in the event of certain uncontrollable exogenous events and annual rate adjustments related to specific Reliability Enhancement Plan and Vegetation Management Plan (“REP/VMP”). In June 2010, the NHPUC approved the Company’s REP/VMP rate increase

8

effective July 1, 2010 of $1.1 million. In June 2011, the NHPUC approved the Company’s fourth REP/VMP rate adjustment, effective July 1, 2011, which resulted in a revenue decrease of $1.7 million. The rate plan also includes an earnings sharing mechanism based on an imputed capital structure of 50% debt and 50% equity and a return on equity of 11%. Earnings above 11% are shared equally between customers and the Company. The rate plan also establishes a storm contingency fund and customer service commitments by the Company.

In April 2010, the Company filed a request with the NHPUC for a temporary increase in funding to its storm contingency fund of $0.7 million annually over three years to replenish the Company’s newly formed fund after a major ice storm in December 2008. An initial rate adjustment was approved by the NHPUC to increase funding by $0.4 million annually effective July 1, 2010. The approval of the remaining balance of $0.3 million in annual funding will occur in conjunction with the NHPUC’s review of costs related to the two additional storms. A February 2010 winter storm having approximately $1.7 million in restoration costs was reported to the NHPUC in the Company’s April 2011 storm fund report. In March 2011, the Company experienced another significant storm event for which the company incurred approximately $1.7 million in restoration costs which as of the date of this report, has not been reported to NHPUC. The Company will be seeking to recover its costs through its storm contingency fund.

Other Regulatory Matters

In November 2008, FERC commenced an audit of NGUSA, including its service companies and other affiliates in the National Grid holding company system. The audit evaluated our compliance with: 1) cross-subsidization restrictions on affiliate transactions; 2) accounting, recordkeeping and reporting requirements; 3) preservation of records requirements for holding companies and service companies; and 4) Uniform System of Accounts for centralized service companies. The final audit report from the FERC was received in February 2011. In April 2011, NGUSA replied to the FERC and outlined its plan to address the findings in the report, which we are currently in the process of implementing. None of the findings had a material impact on the financial statements of the Company.

Note 3. Employee Benefits

The Company participates with certain other NGUSA subsidiaries in a non-contributory defined benefit pension plan (“Pension Plan”) and a pension and postretirement benefits other than pensions plan (“PBOP”, together with Pension Plan, the “Plan”). The Pension plan is a non-contributory, tax-qualified defined benefit plan which provides all employees with a minimum retirement benefit. Supplemental nonqualified, non-contributory executive retirement programs provide additional defined pension benefits for certain executives. PBOPs provide health care and life insurance coverage to eligible retired employees. Eligibility is based on age and length of service requirements and, in most cases, retirees must contribute to the cost of their coverage.

The Company participates in the Plan with certain other NGUSA subsidiaries. Plan assets are commingled and cannot be allocated to an individual company. Plan costs are allocated to the Company. The net Pension Plan expense allocated to the Company for each of the three months ended June 30, 2011 and June 30, 2010 was $0.2 million. The net PBOP expenses allocated to the Company for each of the three months ended June 30, 2011 and June 30, 2010 was $0.2 million. These costs are included as operations and maintenance expenses in the accompanying financial statements.

Workforce Reduction Program

In connection with National Grid pic’s acquisition of KeySpan, National Grid pic and KeySpan offered 673 non-union employees a voluntary early retirement offer (“VERO”) in an effort to reduce the workforce. The VERO was completed and the Company accrued $0.7 million which has been deferred for recovery from electric sales customers as part of the synergy savings and cost to achieve calculations.

Note 4. Income Taxes

The effective tax rate for the Company for the three months ended June 30, 2011 and June 30, 2010 was 46.20% and 58.63%, respectively. Included in taxes for both quarters was state tax expense of $13,000 and $0.1 million, respectively, related to inter-corporate state tax sharing agreements with the Company’s parent. Excluding this charge the Company’s effective tax rate for the three months ended June 30, 2011 and June 30, 2010 would be 44.41% and 44.38%, respectively.

9

Note 5. Fair Value Measurements

Available for sale securities are primarily in equities and are investments based on quoted market prices and municipal and corporate bonds based on quoted prices of similar traded assets in open markets.

The following table presents assets and liabilities measured and recorded at fair value on the Company’s balance sheet on a recurring basis and their level within the fair value hierarchy as of June 30, 2011 and March 31, 2011:

June 30, 2011

(in thousands of dollars)	Level 1		Level 2		Level 3		Total
Assets
Available for sale securities	$	469	$	637	$	—	$	1,106
Total assets	$	469	$	637	$	—	$	1,106

March 31, 2011

(in thousands of dollars)	Level 1		Level 2		Level 3		Total
Assets
Available for sale securities	$	462	$	609	$	—	$	1,071
Total assets	$	462	$	609	$	—	$	1,071

Note 6. Commitments and Contingencies

Legal Matters

The Company is subject to various legal proceedings arising out of the ordinary course of its business. Except as described below, the Company does not consider any of such proceedings to be material individually or in the aggregate to its business or likely to result in a material adverse effect on its results of operations, financial condition, or cash flows.

Environmental Matters

The normal ongoing operations and historic activities of the Company are subject to various federal, state and local environmental laws and regulations. Like many other industrial companies, the Company generates hazardous waste. Under federal and state Superfund laws, potential liability for the historic contamination of property may be imposed on responsible parties jointly and severally, without fault, even if the activities were lawful when they occurred.

The New Hampshire Department of Environmental Protection has named the Company as a potentially responsible party for remediation of a site at which hazardous waste is alleged to have been disposed. The Company believes that obligations imposed on it because of environmental laws will not have a material impact on its financial condition.

Note 7. Related Party Transactions

Intercompany Moneypool

The Company participates with NGUSA and certain affiliates in a system moneypool. The moneypool is administered by the NGUSA service company as the agent for the participants. Short-term borrowing needs are met first by available funds of the moneypool participants. Companies that invest in the moneypool share the interest earned on a basis proportionate to their average monthly investment in the moneypool. Interest rates associated with the moneypool are designed to approximate the cost of third-party short-term borrowings. Funds may be withdrawn from or repaid to the moneypool at any time without prior notice. At June 30, 2011 and March 31, 2011, the Company had a short-term moneypoo! investment of $3.6 million and $7.5 million, respectively.

Accounts receivable from/payable to affiliates

Additionally, the Company engages in various transactions with NGUSA and its affiliates. Certain activities and costs, such as executive and administrative, financial (including accounting, auditing, risk management, tax and treasure/finance), human resources, information technology, legal and strategic planning are shared between the companies and allocated to

10

each company appropriately. In addition, the Company has a tax sharing agreement with National Grid Holdings Inc. (“NGHI”), a NGUSA affiliate, in filing consolidated tax returns. The Company’s share of the tax liability is allocated resulting in a payment to or refund from NGHI.

The Company records short-term payables to and receivables from certain of its associates in the ordinary course of business. The amounts payable to and receivable from its associates do not bear interest. At June 30, 2011 and March 31, 2011, the Company had outstanding receivable and payable positions as follows:

	Accounts Receivable From			Accounts Payable To
	June 30, 2011			March 31, 2011
Massachsetts Electric Co.	$	226		$	894
New England Power Co.		(463	)		336
Niagara Mohawk Power Corp.		282			—
NGUSA Service Co.		266			259
Key Span Corp. Services LLC		(153	)		314
Other affiliates, net		(154	)		214
	$	4		$	2,017

Service Company Charges

The affiliated service companies of NGUSA provide certain services to the Company at their cost. The service company costs are generally allocated to associated companies through a tiered approach. First and foremost, costs are directly charged to the benefited company whenever practicable. Secondly, in cases where direct charging cannot be readily determined, costs are typically allocated using cost/causation principles linked to the relationship of that type of service, such as meters, square footage, number of employees, etc. Lastly, all other costs are allocated based on a general allocator. These costs include operating and capital expenditures of $0.3 million and approximately $0.1 million for the three months ended June 30, 2011 and $1.6 million and $0.5 million for the three months ended June 30, 2010, respectively.

Organization Restructuring

On January 31, 2011, National Grid plc announced substantial changes to the organization, including new global, US and UK operating models, and changes to the leadership team. The announced structure seeks to create a leaner, more-efficient business backed by streamlined operations that will help meet, more efficiently, the needs of regulators, customers and shareholders. The implementation of the new U.S. business structure commenced on April 4, 2011 and targets annualized savings of $200 million by March 2012 primarily through the reduction of approximately 1,200 positions. As of March 31, 2011, NGUSA had recorded $66.8 million reserve for one-time employment termination benefits related to severance, payroll taxes, healthcare continuation, outplacement services as well as consulting fees related to the restructuring program. During the quarter ended June 30, 2011, NGUSA reduced this reserve by $15.1 million due to payment of one-time employment termination benefits which was allocated to various affiliated entities, the Company’s portion of which is approximately $0.1 million. In June 2011, we offered a voluntary severance plan to certain individuals which is expected to cost up to an additional $20 million across all entities affiliated with NGUSA.

Note 8. Subsequent Event

The Company’s service territory was impacted by Hurricane Irene on August 28, 2011, which resulted in approximately 8,000 customers without electric power. The Company was involved in unprecedented restoration efforts throughout its service area which resulted in estimated storm-related cost of approximately $0.3 million for the repair and replacement of electric distribution systems damaged during the storm. The Company has the ability to recover these storm costs in its future rates.

11

Pro forma consolidated financial statements of

ALGONQUIN POWER & UTILITIES CORP.

(Unaudited)

For the year ended December 31, 2010 and

For the six months period ending June 30, 2011

1

Algonquin Power & Utilities Corp

Unaudited Pro Forma Consolidated Statement of Financial Position

June 30, 2011

(in thousands of Canadian dollars)

	APUC			EnergyNorth note 4 (n)			Granite State note 4 (n)			Pro Forma Adjustments note 4			Pro forma Consolidated
Assets
Currents assets:
Cash		8,652			—			361						9,013
Short term investments		10,479			—			—			—			10,479
Accounts receivable, net		35,006			20,240			13,330			(3,500	)(a)		65,076
Due from related parties		2,077			—			—			—			2,077
Gas and propane in storage, at average cost					4,295			—			—			4,295
Prepaid expenses		3,478			1,699			3,168			—			8,346
Supplies and consumables inventory		2,058			—			521			—			2,579
Current portion of deferred tax asset		12,929			3,844			1,125			—			17,897
Current portion of derivative assets		232			34			—			—			266
Current portion of notes receivable		457			—			—			—			457
Regulatory assets					3,142			—			—			3,142
Prepaid income taxes					—			—			—			—
Total current assets		75,368			33,254			18,505			(3,500	)		123,627
Long-term investments and notes receivable		40,662			—			—			—			40,662
Deferred non-current income tax asset		73,271			—			—			1,400	(i)		74,671
Property, plant and equipment		890,562			240,005			81,287			—			1,211,854
Intangible assets		70,211			—			—			—			70,211
Goodwill		10,186			2,040			18,665			(125	)(b)		30,766
Restricted cash		3,657			—			3,154			—			6,811
Deferred financing costs		7,156			—			—			1,200	(c)		8,356
Derivative assets		786			14			—			—			800
Regulatory assets		4,136			65,172			4,789			17,462	(d)		91,559
Other assets		1,697			12,983			1,079			(3,513	)(a)		12,247
Total assets		1,177,692			353,469			127,479			12,925			1,671,565
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable		6,449			4,881			6,049			—			17,380
Accrued liabilities		28,877			122			145			6,200	(c),(i),(l)		35,343
Due to related parties		1,637			—			—			—			1,637
Dividends payable		7,749			—			—			—			7,749
Current portion of long-term liabilities		1,522			—			—			—			1,522
Current portion of other long-term liabilities		1,697			—			—			—			1,697
Current portion of post retirement benefit obligation					272			—			—			272
Current portion of derivative instruments		1,982			2,146			—			—			4,128
Current income tax liability		681			—			—			—	(f)		681
Current portion of deferred credit		10,011			—			—			—			10,011
Deferred income tax liability		733			—			—			—			733
Current portion of Regulatory liabilities					34			540			—			574
Other liabilities					2,069			3,650			—			5,719
Total current liabilities		61,338			9,523			10,384			6,200			87,445
Long-term liabilities		327,145			—			14,468			149,079	(e)		490,691
Convertible debentures		122,477			—			—			—			122,477
Other long-term liabilities		80,340			4,007			4,648			(2,917	)(f)		86,079
Postretirement benefits obligation					3,523			6,110			6,860	(d)		16,494
Other regulatory liabilities		18,329			27,755			8,234			—			54,318
Deferred non-current income tax liability		81,868			55,673			13,338			(11,716	)(d),(g)		139,163
Derivative instruments		3,349			89			—			—			3,438
Deferred credit		29,690			—			—			—			29,690
Other reserves and deferred credits					—			—			—			—
Asset retirement obligations					57,213			—			—			57,213
Environmental liabilities					—			—			—			—
Stockholders’ equity:
Shareholders’ capital		884,156			2,894			5,826			123,681	(h),(i)		1,016,556
Additional paid-in capital					269,704			38,632			(308,336	)(h)		—
(Deficit) / Retained earnings		(360,708	)		(76,706	)		32,217			43,489	(h)		(361,708	)
Accumulated other comprehensive (loss)		(106,520	)		(207	)		(6,377	)		6,585	(h)		(106,520	)
Total Stockholders’ equity		416,928			195,685			70,298			(134,582	)		548,328
Non-controlling interest		36,228									—			36,228
Total stockholders’ equity		453,156			195,685			70,298			(134,582	)		584 556
Total liabilities and shareholders equity		1,177,692			353,469			127,479			12,925			1,671,565

2

Algonquin Power & Utilities Corp

Unaudited Pro Forma Consolidated Statement of Operations

For the year ended December 31, 2010

(in thousands of Canadian dollars)

	APUC			EnergyNorth note 4 (o)			Granite State note 4 (o)			Pro Forma Adjustments note 4			Pro forma Consolidated
Revenue
Energy sales		132,726			—			—			—			132,726
Utility energy sales and distribution					140,663			84,230			—			224,892
Waste disposal fees		9,039			—			—			—			9,039
Water reclamation and distribution		37,786			—			—			—			37,786
Other revenue		3,331			—			—			—			3,331
		182,882			140,663			84,230			—			407,774
Expenses
Operating and administrative expenses		112,737			113,556			73,581			—			299,874
Amortization of property, plant and equipment		36,429			9,270			4,939			—			50,638
Amortization of intangible assets		10,144			—			—			—			10,144
Gain on foreign exchange		(528	)		—			—			—			(528	)
Taxes, other than income taxes					5,936			3,074			—			9,010
Total operating expenses		158,782			128,761			81,594			—			369,138
Operating Income		24,100			11,901			2,635			—			38,637
Interest expense		24,849			4,747			1,162			8,247	(k)		39,006
Interest, dividend and other income		(4,962	)		(289	)		—			—			(5,251	)
Impairment loss of property, plant and equipment		2,492			—			—			—			2,492
Impairment of goodwill		—			96,291			—			(96,291	)(j)		—
Acquisition costs		3,014			—			—			(1,888	)(l)		1,126
(Gain)/loss on derivative financial instruments		1,103			—			—			—			1,103
		26,496			100,749			1,162			(89,932	)		38,476
Earnings/(loss) from operations before income taxes, non-controlling interest		(2,396	)		(88,848	)		1,473			89,932			161
Income tax expense (recovery)
Current		(69	)		(528	)		(546	)					(1,143	)
Deferred		(20,721	)		4,071			1,316			(4,193	)(m)		(19,527	)
		(20,790	)		3,543			770			(4,193	)		(20,670	)
Less: Non-controlling interest in earnings of subsidiaries		444												444
Net earnings		17,950			(92,392	)		704			94,125			20,387
Basic net earnings per share		0.19												0.17
Diluted net earnings per share		0.19												0.17

3

Algonquin Power & Utilities Corp

Unaudited Interim Pro Forma Consolidated Statement of Operations

Six month period ended June 30, 2011

(in thousands of Canadian dollars)

	APUC			EnergyNorth note 4 (o)			Granite State note 4 (o)			Pro Forma Adjustment note 4			Pro forma Consolidated
Revenue
Energy sales		67,881			—			—			—			67,881
Utility energy sales and distribution		39,419			91,508			40,622			—			171,549
Waste disposal fees		8,286			—			—			—			8,286
Water reclamation and distribution		21,266			—			—			—			21,266
Other revenue		1,683			—			—			—			1,683
		138,535			91,508			40,622			—			270,665
Expenses
Operating and administrative expenses		86,059			70,329			35,960			—			192,348
Amortization of property, plant and equipment		19,658			4,539			2,434			—			26,631
Amortization of intangible assets		3,363			—			—			—			3,363
Gain/loss on foreign exchange		98			—			—			—			98
Taxes, other than income taxes					2,891			1,497			—			4,387
Total operating expenses		109,178			77,758			39,891			—			226,827
Operating Income		29,357			13,749			732			—			43,838
Interest expense		15,441			2,162			580			4,124	(k)		22,307
Interest, dividend and other income		(2,653	)		51			—			—			(2,602	)
Acquisition costs		1,014			—			—			(400	)(l)		614
(Gain)/loss on derivative financial instruments		531			—			—			—			531
		14,333			2,213			580			3,724			20,849
Earnings/(loss) from operations before income taxes, non-controlling interest		15,024			11,537			151			(3,724	)		22,989
Income tax expense (recovery)
Current		645			(2,539	)		(2,484	)					(4,378	)
Deferred		(614	)		6,741			2,484			(2,314	)(m)		6,297
		31			4,203			—			(2,314	)		1,919
Less: Net earnings attributable to non controlling interest		2,647									—			2,647
Net earnings		12,346			7,334			151			(1,409	)		18,422
Basic net earnings per share		0.11												0.14
Diluted net earnings per share		0.11												0.14

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Algonquin Power & Utilities Corp.

Notes to Unaudited Pro Forma Consolidated Financial Statements

1. Basis of Presentation

The Unaudited Pro Forma Consolidated Financial Statements have been prepared in connection with the probable acquisitions of Granite State Electric Company (“Granite State”) and EnergyNorth Natural Gas, Inc (“EnergyNorth”) (collectively “GS-EN”) by Algonquin Power & Utilities Corp (“APUC”). The Unaudited Pro Forma Balance Sheet as at June 30, 2011 gives effect to the probable acquisitions as if they were completed on June 30, 2011. The Unaudited Pro Forma Consolidated Statements of Income for the year ended December 31, 2010 and the six months ended June 30, 2011, give effect to the probable acquisitions as if they were completed on January 1, 2010.

The unaudited pro forma financial statements have been presented for illustrative purposes only and are not necessarily indicative of results of operations and financial position that would have been achieved had the pro forma events taken place on the dates indicated, or the future consolidated results of operations or financial position of the consolidated company. Future results may vary significantly from the pro form results presented.

The unaudited pro forma consolidated financial statements and accompanying notes have been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”) consistent with the significant accounting policies set out in APUC’s unaudited interim consolidated financial statements for the six months period ended June 30, 2011. Granite State and EnergyNorth financial statements are also prepared under U.S. GAAP and therefore the significant accounting policies of those companies are not expected to be materially different from APUC. Upon completion of the acquisition, further review of Granite State and EnergyNorth accounting policies may impact the actual financial statements of APUC.

In preparing the unaudited pro forma financial statements, the following historical information was used:

• The audited consolidated financial statements of APUC for the year ended December 31, 2010 reconciled to U.S. GAAP in accordance with note 24, available on SEDAR and incorporated by reference in this document;

• The unaudited interim consolidated financial statements of APUC for the six months period ended June 30, 2011, available on SEDAR and incorporated by reference in this document;

• The audited financial statements of Granite State for the year ended March 31, 2011, included in this document;

• The audited financial statements of EnergyNorth for the year ended March 31, 2011, included in this document;

• The unaudited interim consolidated financial statements of Granite State for the three month periods ended March 31, 2011 and June 30, 2011, included in this document;

• The unaudited interim consolidated financial statements of EnergyNorth for the three month periods ended March 31, 2011 and June 30, 2011, included in this document;

5

APUC’s consolidated financial statements were prepared in accordance with Canadian Generally Accepted Accounting Principles (“Canadian GAAP”) until December 31, 2010. Canadian GAAP differs in some areas from U.S. GAAP as was disclosed in the reconciliation to U.S. GAAP included in note 24 of the audited annual financial statements for the year ended December 31, 2010. The unaudited pro forma financial statements were prepared using APUC’s results of operations for the year ended December 31, 2010 reconciled to U.S. GAAP.

Due to the fact that the reporting period end dates of APUC and GS-EN’s fiscal years differ, the pro forma results for the six months period ended June 30, 2011 were constructed using the three month period ended March 31, 2010 of Granite State and EnergyNorth combined with the respective three month period ended June 30, 2011.

The historical consolidated financial information has been adjusted in the unaudited pro forma financial statements to give effect to pro forma events that are: (i) directly attributable to the acquisition; (ii) factually supportable; and (iii) with respect to the unaudited pro forma statements of income, expected to have a continuing impact on the combined results of APUC and GS-EN. As such, the impact from acquisition related expenses is not included in the accompanying unaudited pro forma statements of income. However, the impact of these expenses is reflected in the unaudited pro forma balance sheet as a decrease to retained earnings.

The unaudited pro forma financial statements do not reflect any cost savings (or associated costs to achieve such savings) from operating efficiencies, synergies or other restructuring that could result from the acquisition. Further, the unaudited pro forma financial statements do not reflect the effect of any regulatory actions that may impact the unaudited pro forma financial statements when the acquisition is completed.

Assumptions and estimates underlying the unaudited pro forma adjustments are described in the accompanying notes, which should be read in connection with the unaudited pro forma financial statements. The pro forma adjustments and allocations of the purchase consideration of GS-EN are based on estimates of the fair value of assets acquired and liabilities to be assumed as well as the planned funding of the probable acquisition. The final allocations will be completed after assets and liability valuations are finalized as of the date of the completion of the acquisition, which is expected to occur in the fall of 2011. Any final adjustments may change the allocation of purchase price which could affect the fair value assigned to assets and liabilities in these unaudited pro forma consolidated financial statements.

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2. Nature of transaction

On December 8th, 2010, Liberty Energy Utilities Co. (“Liberty Energy”), APUC’s regulated utility subsidiary, entered into agreements to acquire all issued and outstanding shares of EnergyNorth, a regulated natural gas utility and Granite State, a regulated electric distribution utility for total consideration of approximately $274,883 (US$285,000), plus working capital and subject to final closing adjustments.

Closings of the transactions are subject to certain conditions including state and federal regulatory approval, and are expected to occur in the fall of 2011. Financing of the acquisitions is expected to occur simultaneously with the closing of the transactions.

3. Preliminary Purchase Price

The following table summarizes the preliminary determination of the fair value of the assets acquired and liabilities assumed as at June 30, 2011:

	EnergyNorth			Granite State			Total
Working capital		19,887			6,650			26,537
Property, plant and equipment		240,005			81,287			321,292
Regulatory assets		71,411			16,013			87,424
Other assets		10,526			39			10,565
Goodwill		20,580			—			20,580
Long-term debt		—			(14,468	)		(14,468	)
Long-term liabilities		(72,734	)		(6,801	)		(79,535	)
Deferred income tax liability, net		(52,006	)		(321	)		(52,327	)
Regulatory liabilities		(27,755	)		(8,234	)		(35,989	)
Total net assets acquired	$	209,914		$	74,165		$	284,079

The acquisition is expected to be funded as follows:

	Total
Debt financing (US$135,000)	$	130,208
Share issuance to Emera		60,000
Additional share issuance		75,000
Senior unsecured revolving credit facility (US$19,566)		18,871
Total acquisition cost	$	284,079

7

Preliminary purchase consideration

The purchase agreements provide for consideration approximating $274,883 (US$285,000) subject to a purchase price adjustment for assumed debt, acquired working capital and changes in capital expenditures and regulated assets at the acquisition date. For purposes of the pro forma statements, the post-closing adjustment is assumed to increase the purchase consideration by $9,196 (US$9,535). Financing of the acquisitions is expected to occur in the fall of 2011, simultaneously with the closing of the transactions. Liberty Energy is targeting a capital structure of 52.5% debt to total capitalization consistent with investment grade regulated utilities.

For purposes of these pro forma statements, the Company expects to issue debt financing of approximately $130,208 (US$135,000) at an assumed interest rate of 6%, net of estimated financing costs of $1,200

In connection with these acquisitions, Emera Inc. (“Emera”) has agreed to a treasury subscription of subscription receipts convertible into 12.0 million APUC common shares upon closing of the transactions for proceeds of $60,000. The issuance of these subscription receipts is subject to regulatory approval. In addition, the Company expects to use $75,000 of the $85,315 in share proceeds offered through this prospectus to finance the acquisitions. The pro forma financial statements reflect the issuance of 13.3 million common shares from this offering, based on an offering price of $5.65 per share for gross proceeds of $75,000. Costs associated with this portion of the equity issuance are estimated to be $4,000. Additional proceeds of $10,315 from this offering representing approximately 1.8 million shares are expected to be used for general corporate purposes. These 1.8 million shares are excluded from the pro forma statements and pro forma earnings per share calculation.

The Company expects to finance the price adjustment arising mainly out of the assumed working capital, through a new senior unsecured revolving credit facility at an expected rate of LIBOR + 1.75%.

A 1/8% change in assumed interest rates would change pre-tax interest expense by approximately $163 and $81 for the year ended December 31, 2010 and the six month period ended June 30, 2011, respectively. A change of 30% in APUC’s common share price from the price used above would change the number of shares issued by approximately 3,063 common shares.

The fair value of the net assets acquired in U.S. dollars was translated to Canadian dollars for pro forma purpose using the foreign exchange rate as at June 30, 2011 of US$1.00 = CDN$0.9645. A $0.10 increase in the strength of the U.S. dollar relative to the Canadian dollar, net of U.S. dollar debt financing, would result in an increase in purchase consideration of approximately $14,000 (US$13,149)

Preliminary purchase price allocation

The determination of the fair value of assets and liabilities acquired has been based upon management’s preliminary estimates and certain assumptions. Considering the regulated environment in which EnergyNorth and Granite State operate in, the value of the assets and liabilities acquired have been estimated to closely approximate their book values for purposes of these pro forma statements. The actual fair values of the assets and liabilities will be determined as of the date of acquisition and may differ from the amounts noted above in the pro forma preliminary purchase price allocation due to a number of factors, including:

• timing of completion of the acquisitions;

8

• changes in the net assets of EnergyNorth and Granite State;

• completion of further analysis, including intangible assets, post-retirement obligations pension and taxes.

4. Adjustments to Unaudited pro forma Financial Statements

(a) Intercompany & other assets/liabilities:

The pro forma adjustments reflect the elimination of the seller’s intercompany accounts and non-qualified pension assets & liabilities which, based on the share purchase agreements, are excluded from the purchase transactions.

(b) Goodwill:

The pro forma adjustment reflects the elimination of acquiree historical goodwill and the establishment of $20,580 goodwill resulting from the probable acquisitions. Goodwill is calculated as the excess of the purchase price over the fair values assigned to the net assets acquired.

(c) Deferred debt issuance costs:

The pro forma adjustment reflects the estimated financing costs of $1,200 related to the additional debt to be incurred in connection with the acquisition.

(d) Pension:

The pro forma adjustments reflect the net pension obligation to be assumed by the Company, as contemplated by the sale and purchase agreement. In addition, the pro forma adjustment to regulatory assets reflects the unamortized pension related gains and losses historically recorded in accumulated other comprehensive income but eliminated by the purchase equation. The final adjustments will depend on the actuarial calculations on the closing date and the number of participants transferring from the seller to the Company.

(e) Long term liabilities:

The pro forma adjustment reflects the estimated financing from long-term debt of $130,208 (US$135,000) and senior secured revolving credit facility of $18,871 (US$19,566) to be incurred in connection with the acquisition of GS-EN (note 3).

9

(f) Pre-acquisition income taxes:

The pro forma adjustments reflect the recovery of pre-acquisition income taxes from the seller in accordance with the indemnification clause of the purchase and sale agreement.

(g) Deferred taxes:

For Granite State, for tax purposes, the Company intends to file an election under section 338(h)(10) of the U.S. Internal Revenue Code, which recognizes the purchase transaction as a deemed asset acquisition, eliminating accounting and tax basis differences on these assets. The pro forma adjustment reflects the reduction of deferred tax liability of $16,645 resulting from this election. The Company does not intend to file a section 338(h)(10) election for EnergyNorth.

(h) Equity of acquiree:

The pro forma adjustment reflects the elimination of Granite State and EnergyNorth’s existing equity accounts.

(i) Equity of APUC:

The pro forma adjustment reflects the issuance of 25.3 million common shares of APUC in connection with the proposed acquisition for consideration of $135,000 net of estimated issuance costs of $4,000 and related tax benefits of $1,400 (note 3). Additional proceeds of $10,000 from this offering representing approximately 1.8 million shares are expected to be used for general corporate purposes. These 1.8 million shares are excluded from the pro forma statements.

(j) Impairment of goodwill:

The pro forma adjustment reflects the reversal of the impairment of goodwill at EnergyNorth that is recorded in the historical financial statements for the year ended March 31, 2011, which was related to the pre-acquisition goodwill balances and is not expected to have a continuing impact on the combined results of APUC and GS-EN.

(k) Interest expense:

The pro forma adjustment reflects additional interest expense and amortization of the deferred financing costs as a result of incremental debt financing required for the acquisition.

(l) Transaction costs:

Transaction costs specific to the GS-EN acquisitions were expensed as incurred in the amount of $1,888 for the year ended December 31, 2010 and $400 for the six-month period ended June 30, 2011. These costs have been reversed in the pro forma adjustments to the income statements as these amounts are considered non-recurring. The pro forma adjustment to accrued liabilities on the balance sheet reflects expected additional transaction costs of $1,000 for these acquisitions.

10

(m) Income taxes:

The pro forma adjustment reflects the income tax effect of the pro forma adjustments, which was calculated using an estimated statutory income tax rate of 35% with the exception of interest expense which is tax effected at 60%, reflecting the overall consolidated tax impact related to the financings.

(n) Foreign exchange (balance sheet):

The unaudited interim balance sheet of Granite State and EnergyNorth as at June 30, 2011 presented in U.S. dollars was translated to Canadian dollars using the foreign exchange rate as at June 30, 2011 of US$1.00 = CDN$0.9645

(o) Foreign exchange (statement of operations):

The audited statement of operations of Granite State and EnergyNorth for the year ended March 31, 2010 and the six months period ended June 30, 2011 presented in U.S. dollars were translated to Canadian dollars using the average foreign exchange rate for the 12 month and six month period of US$1.00 = CDN$1.0168 and US$1.00 = CDN$0.9769, respectively.

5. Pro forma shares outstanding

The average number of APUC common shares used in the computation of pro forma basic and diluted earnings per share has been determined as follows:

	Six months ended June  30, 2011		Year ended December  31, 2010
Weighted average shares - basic		108,279,592		94,338,193
Effect of share issuance to Emera		12,000,000		12,000,000
Effect of additional share issuance		13,274,336		13,274,336
Pro forma weighted-average shares - basic		133,553,928		119,612,529
Dilutive effect of stock options		326,483		—
Pro forma weighted-average shares - diluted		133,880,411		119,612,529

Additional proceeds of $10,000 from this offering representing approximately 1.8 million shares are expected to be used for general corporate purposes. These 1.8 million shares are excluded from the pro forma earnings per share calculation.

11

CERTIFICATE OF THE CORPORATION

Dated: October 20, 2011

This short form prospectus, together with the documents incorporated by reference, constitutes full, true and plain disclosure of all material facts relating to the securities offered by this short form prospectus as required by the securities legislation of each of the provinces of Canada.

(Signed) IAN ROBERTSON	(Signed) DAVID BRONICHESKI
Chief Executive Officer	Chief Financial Officer

On behalf of the Board of Directors

(Signed) KENNETH MOORE	(Signed) CHRISTOPHER JARRATT
Director	Director

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CERTIFICATE OF THE UNDERWRITERS

Dated: October 20, 2011

To the best of our knowledge, information and belief, this short form prospectus, together with the documents incorporated by reference, constitutes full, true and plain disclosure of all material facts relating to the securities offered by this short form prospectus as required by the securities legislation of each of the provinces of Canada.

(Signed) THOMAS I. KURFURST	(Signed) JAMES A. TOWER
SCOTIA CAPITAL INC.	BMO NESBITT BURNS INC.

(Signed) DAVID H. WILLIAMS	(Signed) IAIN WATSON	(Signed) JOHN KROEKER	(Signed) PAUL HUEBENER
CIBC WORLD MARKETS INC.	NATIONAL BANK FINANCIAL INC.	TD SECURITIES INC.	MACQUARIE CAPITAL MARKETS CANADA LTD.

(Signed) ROBERT NICHOLSON	(Signed) ALAN POLAK	(Signed) KEN MANGET
RBC DOMINION SECURITIES INC.	CANACCORD GENUITY CORP.	DESJARDINS SECURITIES INC.

(Signed) DANIEL PHAURE	(Signed) MICHAEL DENNY	(Signed) MARC MURNAGHAN
STIFEL NICOLAUS CANADA INC.	MACKIE RESEARCH CAPITAL CORPORATION	CORMARK SECURITIES INC.

C-2