U.S. SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 40-F

o		REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934.

þ		ANNUAL REPORT PURSUANT TO SECTION 13(a) OF THE SECURITIES EXCHANGE ACT OF 1934

PENGROWTH ENERGY TRUST

(Exact name of Registrant as specified in its charter)

Alberta, Canada
(Province or other jurisdiction of incorporation or organization)

1311		None
(Primary Standard Industrial Classification Code Number)		(I.R.S. Employer Identification Number)

Suite 2100, 222 Third Avenue S.W.
Calgary, Alberta Canada T2P 0B4
(403) 233-0224
(Address and telephone number of Registrant’s principal executive offices)

Puglisi & Associates
850 Library Avenue, Suite 204
New York, Delaware 19711
(302)738-6680

(Name, address (including zip code) and telephone number (including area code)
of agent for service in the United States)

copies to:

Brad D. Markel Bennett Jones LLP 4500 Bankers Hall East 855 – 2nd Street SW Calgary, Alberta T2P 4K7 Canada (403) 298-3100		Edwin S. Maynard Andrew J. Foley Paul, Weiss, Rifkind, Wharton & Garrison LLP 1285 Avenue of the Americas New York, New York 10019-6064 USA (212) 373-3000

Title of each class		Name of each exchange on which registered
Trust Units		New York Stock Exchange

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act.

For Annual Reports indicate by check mark the information filed with this Form:

þ Annual information form      þ Audited annual financial statements

     Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report:

     There were 289,834,790 Trust Units, of no par value, outstanding as of December 31, 2009.

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

Yes  þ     No  o

     Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files).

Yes  o     No  o

     This report on Form 40-F shall be incorporated by reference into or as an exhibit to, as applicable, the registrant’s Registration Statement on Form F-3 (File No. 333-143810) and the registrant’s Registration Statement on Form F-10 (File No. 333-158580) under the Securities Act of 1933, as amended.

 

 

DOCUMENTS FILED AS PART OF THIS ANNUAL REPORT

     The following documents have been filed as part of this Annual Report on Form 40-F as Appendices hereto:

Appendix		Documents
A		Pengrowth Energy Trust Annual Information Form for the year ended December 31, 2009.
B		Management’s Discussion and Analysis.
C		Consolidated Financial Statements of Pengrowth Energy Trust, including Management’s Report to Unitholders, the Auditors’ Reports and note 24 thereof which includes a reconciliation of the Consolidated Financial Statements to United States generally accepted accounting principles.
D		Supplemental Unaudited Disclosures about Oil and Gas Producing Activities required under United States Generally Accepted Accounting Principles.
E		Pengrowth Energy Trust Code of Business Conduct and Ethics dated November 11, 2009.

CERTIFICATIONS AND DISCLOSURE REGARDING CONTROLS AND PROCEDURES

Certifications. See Exhibits 3, 4, 5 and 6 to this Annual Report on Form 40-F.

Disclosure Controls and Procedures. The required disclosure is included in the section entitled “Disclosure Controls and Procedures” contained in the Registrant’s Management’s Discussion and Analysis for the fiscal year ended December 31, 2009, filed as part of this Annual Report on Form 40-F.

Management’s Annual Report on Internal Control Over Financial Reporting. The required disclosure is included in the section entitled “Internal Control Over Financial Reporting” contained in the Registrant’s Management’s Discussion and Analysis for the fiscal year ended December 31, 2009, filed as part of this Annual Report on Form 40-F.

Attestation Report of the Registered Public Accounting Firm. The required disclosure is included in the “Auditors’ Report” that accompanies the Registrant’s Consolidated Financial Statements for the fiscal year ended December 31, 2009, filed as part of this Annual Report on Form 40-F.

Changes in Internal Control Over Financial Reporting. During the fiscal year ended December 31, 2009, there were no changes in the Registrant’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Registrant’s internal control over financial reporting.

NOTICES PURSUANT TO REGULATION BTR

None.

IDENTIFICATION OF THE AUDIT COMMITTEE

The Registrant has a separately-designated standing audit committee established in accordance with Section 3(a)(58)(A) of the Exchange Act. The members of the audit committee are: Thomas A. Cumming, James D. McFarland, Michael S. Parrett and A. Terence Poole.

AUDIT COMMITTEE FINANCIAL EXPERT

The board of directors of the Registrant has determined that each of Michael S. Parrett and A. Terence Poole, members of the Registrant’s audit committee, qualify as audit committee financial experts for purposes of paragraph (8) of General Instruction B to Form 40-F. The board of directors has further determined that each of Mr. Parrett and Mr. Poole is also independent, as that term is defined in the Corporate Governance Listing Standards of the New York Stock Exchange. The Commission has indicated that the designation of each of Mr. Parrett and Mr. Poole as an audit committee financial expert does not make either of them an “expert” for any purpose, impose any duties, obligations or liabilities on them that are greater than those imposed on members of the audit committee and the board of directors who do not carry this designation or affect the duties, obligations or liabilities of any other member of the audit committee or the board of directors.

ADDITIONAL DISCLOSURE

Certain disclosure regarding the corporate governance practices of the Registrant, including disclosure of the Registrant’s principal accountant fees and services, pre-approval policies and procedures, code of ethics and off-balance sheet arrangements, is included on pages 83,83,85 and 86, respectively, of the Annual Information Form contained in Appendix A. Disclosures regarding the Registrant’s contractual obligations is included on page 25 of Management’s Discussion and Analysis contained in Appendix B.

UNDERTAKING

Registrant undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the Commission staff, and to furnish promptly, when requested to do so by the Commission staff, information relating to: the securities registered pursuant to Form 40-F; the securities in relation to which the obligation to file an annual report on Form 40-F arises; or transactions in said securities.

CONSENT TO SERVICE OF PROCESS

Form F-X signed by the Registrant and its agent for service of process has been filed with the Commission together with Form F-10 (333-158580) in connection with its securities registered on such form.

Any changes to the name or address of the agent for service of process of the Registrant shall be communicated promptly to the Commission by an amendment to the Form F-X referencing the file number of the Registrant.

SIGNATURES

Pursuant to the requirements of the Exchange Act, the Registrant certifies that it meets all of the requirements for filing on Form 40-F and has duly caused this Annual Report to be signed on its behalf by the undersigned, thereunto duly authorized.

EXHIBIT INDEX

Exhibit		Description
1		Consent of Independent Registered Public Accounting Firm
2		Consent of GLJ Petroleum Consultants Ltd.
3		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350
4		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350
5		Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934
6		Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934

PENGROWTH ENERGY TRUST ANNUAL INFORMATION FORM FOR THE YEAR
ENDED DECEMBER 31, 2009

PENGROWTH ENERGY TRUST

ANNUAL INFORMATION FORM

For the year ended December 31, 2009

March 8, 2010

TABLE OF CONTENTS

GLOSSARY OF TERMS AND ABBREVIATIONS			1
CONVERSION			4
PRESENTATION OF OUR FINANCIAL INFORMATION			5
PRESENTATION OF OUR RESERVE INFORMATION			5
FORWARD-LOOKING STATEMENTS			5
PENGROWTH ENERGY TRUST			7
Introduction			7
The Trust			7
The Corporation			7
Intercorporate Relationships			8
Business Strategy			8
Recent Developments			9
Historical Developments — 2007 and 2008			13
Trends			14
PENGROWTH — OPERATIONAL INFORMATION			15
Principal Properties			15
Light Oil Properties			16
Heavy Oil Properties			19
Conventional Gas Properties			20
Shallow Gas Properties			23
Offshore Gas Properties			25
Oil Sands Properties			25
Statement of Oil and Gas Reserves and Reserves Data			26
Additional Information Relating to Reserves Data			36
Future Development Costs			38
Finding, Development and Acquisition Costs			38
Future Development Capital			39
Other Oil and Gas Information			40
Forward Contracts			43
Additional Information Concerning Abandonment & Reclamation Costs			43
Costs Incurred			43
Exploration and Development Activities			44
Production Estimates			44
Production History (Netback)			45
Before Tax Net Asset Value (NAV) at December 31, 2009			46
TRUST UNITS			47
The Trust Indenture			47
The Trustee			47
Stock Exchange Listings			48
Ownership Restrictions			48
Redemption Right			49
Conversion Rights			49
Exchangeable Shares			49
Voting at Meetings of Unitholders			49
Voting at Meetings of Corporation			50
Termination of the Trust			50
Unitholder Limited Liability			50
THE ROYALTY INDENTURE			51
Royalty Units			51
The Royalty			51
Replacement of Properties			52
The Trustee			52
Exhibit 1
Exhibit 2
Exhibit 3
Exhibit 4
Exhibit 5
Exhibit 6

DISTRIBUTIONS			52
General			52
Historical Distributions			52
Restrictions on Distributions			54
CERTAIN CANADIAN FEDERAL INCOME TAX CONSIDERATIONS			56
Taxation of the Trust			56
Taxation of Unitholders Resident in Canada			57
Taxation of Unitholders who are Non-Residents of Canada			58
UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS			59
Classification of the Trust as a Corporation			60
Ownership and Disposition of Trust Units			60
Other Considerations			61
INDUSTRY CONDITIONS			62
Government Regulation			62
Pricing and Marketing — Oil			62
Pricing and Marketing — Natural Gas			62
Pricing and Marketing — Natural Gas Liquids			63
Royalties			63
Environmental Regulation			66
Climate Change			66
RISK FACTORS			68
MARKET FOR SECURITIES			79
DIRECTORS AND OFFICERS			80
Directors and Officers of the Corporation			80
Corporate Cease Trade Orders or Bankruptcies			81
Personal Bankruptcies			82
Penalties or Sanctions			82
AUDIT COMMITTEE			82
Principal Accountant Fees and Services			83
Pre-approval Policies and Procedures			83
CONFLICTS OF INTEREST			84
LEGAL PROCEEDINGS			84
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS			84
INTERESTS OF EXPERTS			85
AUDITORS, TRANSFER AGENT AND REGISTRAR			85
MATERIAL CONTRACTS			85
CODE OF ETHICS			85
OFF-BALANCE SHEET ARRANGEMENTS			86
DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NEW YORK STOCK EXCHANGE			86
ADDITIONAL INFORMATION			86

Appendix A — Report on Reserves Data by Independent Qualified Reserves Evaluator on Form 51-101F2

Appendix B — Report of Management and Directors on Oil and Gas Disclosure on Form 51-101F3

Appendix C — Audit Committee Terms of Reference

Unless otherwise indicated, all of the information provided in this Annual Information Form is as at December 31, 2009.

GLOSSARY OF TERMS AND ABBREVIATIONS

The following terms in this Annual Information Form have the meanings set forth below:

Corporate

“Board” or “Board of Directors” refers to the board of directors of the Corporation;

“Computershare” refers to Computershare Trust Company of Canada;

“Corporation” refers to Pengrowth Corporation, the administrator of the Trust;

“Credit Facility” refers to Pengrowth’s $1.2 billion extendible revolving term credit facility syndicated among eleven financial institutions;

“Debenture” refers to Pengrowth’s six and a half percent convertible unsecured subordinated debentures assumed in connection with Pengrowth’s strategic business combination with Esprit Energy Trust;

“Debenture Indenture” refers to the trust indenture relating to the Debentures entered into among Esprit Energy Trust, Esprit Exploration Ltd. and Computershare (as trustee), dated July 28, 2005 and assumed by Pengrowth on October 2, 2006 pursuant to the first supplemental trust indenture relating to the Debentures, entered into by the Trust, Esprit Energy Trust, Esprit Exploration Ltd., the Corporation and Computershare (as trustee);

“Manager” refers to Pengrowth Management Limited, the manager of the Trust and the Corporation prior to July 1, 2009;

“Pengrowth”, “we”, “us” and “our” refers to the Trust and all of its wholly-owned direct and indirect subsidiary entities on a consolidated basis;

“Royalty Indenture” refers to the amended and restated royalty indenture of the Corporation, dated December 30, 2009, and supplemented on December 31, 2009;

“Royalty Unitholder” refers to a holder of Royalty Units;

“Royalty Units” refers to the royalty units of the Corporation created and issued pursuant to the Royalty Indenture;

“SIFT Legislation” refers to the Specified Investment Flow-Through legislation and has the meaning ascribed thereto under “Certain Canadian Federal Income Tax Considerations”;

“Trust” refers to Pengrowth Energy Trust;

“Trust Indenture” refers to the amended and restated trust indenture of the Trust, dated July 1, 2009;

“Trust Units” refers to the trust units of the Trust created and issued pursuant to the Trust Indenture; and

“Unitholders” refers to holders of Trust Units, class A trust units and special units, as the context requires.

Engineering

“Company Interest” is equal to Pengrowth’s gross interest plus Pengrowth’s Royalty Interest; that is, the Working Interest share of production or reserves prior to the deduction of royalties plus any royalty interest in production or reserves at the wellhead;

“Contingent Resources” are those quantities of petroleum estimated, on a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. Contingent Resources do not constitute, and should not be confused with, reserves;

“Developed Non-Producing Reserves” refers to those reserves that either have not been on production, or have previously been on production but are shut-in and the date of resumption of production is unknown;

“Developed Producing Reserves” refers to those reserves expected to be recovered from completion intervals open at the time of the estimate; these reserves may be currently producing or, if shut in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty;

“Developed Reserves” refers to those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure to put the reserves on production; the developed category may be subdivided into Developed Producing Reserves and Developed Non-Producing Reserves;

“future net revenue” refers to the estimated net amount to be received with respect to the development and production of reserves computed by deducting, from estimated future revenues, estimated future royalty obligations, costs related to the development and production of reserves and abandonment and reclamation costs (corporate general and administrative expenses and financing costs are not deducted);

“GLJ” refers to GLJ Petroleum Consultants Ltd., independent petroleum consultants, Calgary, Alberta;

“GLJ Report” refers to the report prepared by GLJ, dated February 5, 2010 with an effective date of December 31, 2009;

“gross” with respect to: (i) Pengrowth’s interest in production or reserves, refers to Pengrowth’s Working Interest (operating or non-operating) share before the deduction of royalties and without including any royalty interests (excluding Pengrowth’s Royalty Interest reserves); (ii) Pengrowth’s wells, refers to the total number of wells in which Pengrowth has an interest; and (iii) Pengrowth’s properties, refers to the total area of properties in which Pengrowth has an interest;

“net” with respect to: (i) Pengrowth’s interest in production or reserves, refers to Pengrowth’s Working Interest (operating or non-operating) share after the deduction of royalty obligations, plus Pengrowth’s royalty interests in production or reserves; (ii) Pengrowth’s interest in wells, refers to the number of wells obtained by aggregating Pengrowth’s working interest in each of its gross wells; and (iii) Pengrowth’s interest in a property, refers to the total area in which Pengrowth has an interest multiplied by the working interest owned by Pengrowth;

“Possible Reserves” are those additional reserves that are less certain to be recovered than Probable Reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated Proved plus Probable plus Possible Reserves;

“Probable Reserves” refers to those additional reserves that are less certain to be recovered than Proved Reserves; it is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated Proved plus Probable Reserves;

“Proved Reserves” refers to those reserves that can be estimated with a high degree of certainty to be recoverable; it is likely that the actual remaining quantities recovered will exceed the estimated Proved Reserves;

“Remaining Reserve Life” refers to the expected productive life of the property or fifty years, whichever is less;

“Reserve Life Index” refers to the number of years determined by dividing the Company Interest Total Proved Plus Probable Reserves of a property by the 2010 Company Interest estimated Total Proved Plus Probable production from such property. The reserves and the 2010 estimated production for such property come from the GLJ Report;

“reserves” refers to estimated remaining quantities of oil and natural gas and related substances anticipated to be recovered from known accumulations, from a given date forward, based on: (i) analysis of drilling, geological, geophysical and engineering data; (ii) the use of established technology; and specified economic conditions which are generally accepted as being reasonable and shall be disclosed; reserves are classified according to the degree of certainty associated with the estimate (e.g., proved, probable);

“Royalty Interest” refers to Pengrowth’s interest in production and payment that is based on the gross production at the wellhead; a royalty is paid in either cash or kind, but is paid on a value calculated at the wellhead;

“Total Proved Plus Probable Reserves” or “P+P” means the aggregate of Proved Reserves and Probable Reserves;

“Undeveloped Reserves” refers to those reserves expected to be recovered from known accumulations where a significant expenditure (e.g. the cost of drilling a well) is required to render them capable of production; they must fully meet the requirements of the reserves classification (proved, probable, possible) to which they are assigned; and

“Working Interest” refers to the percentage of undivided interest, excluding royalty interest, held by Pengrowth in an oil and gas property.

Abbreviations

“API” refers to the American Petroleum Institute;

“^oAPI” refers to an indication of the specific gravity of crude oil measured on the API gravity scale;

“bbl”, “Mbbl”, “MMbbl” and “Bbbl” refers to barrels, thousands of barrels, millions of barrels and billions of barrels, respectively;

“bblpd” refers to barrels per day;

“boe”, “Mboe” and “MMboe” refers to barrels of oil equivalent, thousands of barrels of oil equivalent and millions of barrels of oil equivalent, respectively, on the basis of one boe being equal to one barrel of oil or NGLs or six Mcf of natural gas;

“boepd” refers to barrels of oil equivalent per day;

“bwpd” refers to barrels of water per day;

“CBM” refers to natural gas, primarily methane, producible from coal seams, commonly called coal bed methane;

“EOR” refers to enhanced oil recovery;

“EDGAR” refers to the Electronic Data Gathering Analysis and Retrieval System maintained by the SEC;

“GAAP” or “Canadian GAAP” refers to generally accepted accounting principles in Canada;

“$M” and “$MM” refers to thousands of dollars and millions of dollars, respectively;

“MMBtu” refers to million British thermal units;

“Mcf”, “MMcf” and “Bcf” refers to thousands of cubic feet, millions of cubic feet and billions of cubic feet, respectively;

“Mcfe” refers to thousand cubic feet of natural gas equivalent on the basis of one barrel of oil or one barrel of NGLs being equal to six Mcf of natural gas;

“Mcfpd” and “MMcfpd” refers to thousands of cubic feet per day and millions of cubic feet per day, respectively;

“NGLs” refers to natural gas liquids;

“NYSE” refers to the New York Stock Exchange;

“SAGD” refers to steam assisted gravity drainage;

“SEC” refers to the United States Securities and Exchange Commission;

“SEDAR” refers to the System for Electronic Document Analysis and Retrieval of the Canadian Securities Administrators;

“Tax Act” refers to the Income Tax Act (Canada) and the regulations thereunder, as amended from time to time;

“TSX” refers to the Toronto Stock Exchange; and

“WTI” refers to West Texas Intermediate.

Disclosure provided herein in respect of a boe may be misleading, particularly if used in isolation. A boe conversation ratio of six Mcf of natural gas to one barrel of crude oil equivalent is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

CONVERSION

In this Annual Information Form, measurements are given in standard imperial or metric units only. The following table sets forth certain standard conversions:

To Convert From		To				Multiply by
Mcf		cubic metre					28.174
bbl		cubic metre					0.159
MMBtu		gigajoule					1.0546
cubic metre		bbl					6.29
metre		feet					3.281
mile		kilometre					1.609
kilometre		mile					0.621
acre		hectare					0.405

PRESENTATION OF OUR FINANCIAL INFORMATION

Financial information in this Annual Information Form has been prepared in accordance with Canadian GAAP. Canadian GAAP differs in some significant respects from United States generally accepted accounting principles and thus our financial statements may not be comparable to the financial statements of U.S. companies. The principal differences as they apply to us are summarized in note 24 to our audited annual consolidated financial statements for the year ended December 31, 2009, which are available on the SEDAR website at www.sedar.com and in our current Form 40-F, which is available through EDGAR at the SEC’s website at www.sec.gov.

Unless otherwise stated, all sums of money referred to in this Annual Information Form are expressed in Canadian dollars.

PRESENTATION OF OUR RESERVE INFORMATION

National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) of the Canadian Securities Administrators permits oil and gas issuers, in their filings with Canadian securities regulators, to disclose not only Proved Reserves but also Probable Reserves, Possible Reserves and Contingent Resources, and to disclose reserves and production on a gross basis before deducting royalties. Probable Reserves and Possible Reserves are of a higher risk and are less likely to be accurately estimated or recovered than Proved Reserves. Contingent Resources are higher risk than Probable Reserves and Possible Reserves and are less likely to be accurately estimated or recovered than Probable Reserves or Possible Reserves. Because we are permitted to prepare this Annual Information Form in accordance with Canadian disclosure requirements, we have disclosed in this Annual Information Form reserves designated as Probable Reserves, Possible Reserves and Contingent Resources and have disclosed reserves and production on a gross basis before deducting royalties.

Current SEC reporting requirements permit oil and gas companies to disclose probable and possible reserves, in addition to the required disclosure of proved reserves. If this Annual Information Form was required to be prepared in accordance with U.S. disclosure requirements, the SEC’s requirements would prohibit Contingent Resources from being disclosed. Under current SEC requirements, net quantities of reserves are required to be disclosed, which requires disclosure on an after royalties basis and does not include reserves relating to the interests of others. For a description of these and additional differences between Canadian and U.S. standards of reporting reserves, see “Risk Factors — Canadian and United States practices differ in reporting reserves and production and our estimates may not be comparable to those of companies in the United States”. Additional information prepared in accordance with the U.S. Financial Accounting Standards Board’s Accounting Standards Update (Extractive Activities-Oil and Gas (Topic 932)) relating to our oil and gas reserves is set forth in our current Form 40-F, which is available through EDGAR at the SEC’s website at www.sec.gov.

FORWARD-LOOKING STATEMENTS

This Annual Information Form contains forward-looking statements within the meaning of securities laws, including the “safe harbour” provisions of Canadian securities legislation and the United States Private Securities Litigation Reform Act of 1995. Forward-looking information is often, but not always, identified by the use of words such as “anticipate”, “believe”, “expect”, “plan”, “intend”, “forecast”, “target”, “project”, “guidance”, “may”, “will”, “should”, “could”, “estimate”, “predict” or similar words suggesting future outcomes or language suggesting an outlook. Forward-looking statements in this Annual Information Form include, but are not limited to, benefits and synergies resulting from our corporate and asset acquisitions, business strategy and strengths, goals, focus and the effects thereof, acquisition criteria, capital expenditures, reserves, reserve life indices, estimated production, production additions from our 2010 development program, remaining producing reserves lives, operating expenses, royalty rates, net present values of future net revenue from reserves, commodity prices and costs, exchange rates, the impact of contracts for commodities, development plans and programs, tax horizon, future income taxes, taxability of distributions, the impact of proposed changes to Canadian tax legislation or U.S. tax legislation, our proposed conversion to a dividend paying corporation, abandonment and reclamation costs, government royalty rates (including estimated increase in royalties paid and estimated decline in net present value of reserves and 2010 cash flows) and expiring acreage.

Statements relating to reserves are forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the reserves described exist in the quantities predicted or estimated and can profitably be produced in the future.

Forward-looking statements and information are based on our current beliefs as well as assumptions made by, and information currently available to, us concerning anticipated financial performance, business prospects, strategies, regulatory developments, future oil and natural gas commodity prices and differentials between light, medium and heavy oil prices, future oil and natural gas production levels, future exchange rates, the proceeds of anticipated divestitures, the amount of future cash distributions paid by the Trust, the cost of expanding our property holdings, our ability to obtain equipment in a timely manner to carry out development activities, our ability to market our oil and gas successfully to current and new customers, the impact of increasing competition, our ability to obtain financing on acceptable terms, and our ability to add production and reserves through our acquisition, development and exploration activities. Although management considers these assumptions to be reasonable based on information currently available to it, they may prove to be incorrect.

By their very nature, forward-looking statements involve inherent risks and uncertainties, both general and specific, and risks that predictions, forecasts, projections and other forward-looking statements will not be achieved. We caution readers not to place undue reliance on these statements as a number of important factors could cause the actual results to differ materially from the beliefs, plans, objectives, expectations and anticipations, estimates and intentions expressed in such forward-looking statements. These factors include, but are not limited to: the volatility of oil and gas prices; production and development costs and capital expenditures; the imprecision of reserve estimates and estimates of recoverable quantities of oil, natural gas and liquids; our ability to replace and expand oil and gas reserves; environmental claims and liabilities; incorrect assessments of value when making acquisitions; increases in debt service charges; the loss of key personnel; the marketability of production; defaults by third party operators; unforeseen title defects; fluctuations in foreign currency and exchange rates; inadequate insurance coverage; counterparty risk; compliance with environmental laws and regulations; changes in tax and royalty laws; the failure to qualify as a mutual fund trust; our ability to access external sources of debt and equity capital, the implementation of International Financial Reporting Standards (“IFRS”); and the implementation of greenhouse gas (“GHG”) emissions legislation. Further information regarding these factors may be found under the heading “Risk Factors” in this Annual Information Form, under the heading “Business Risks” in our Management’s Discussion and Analysis for the year ended December 31, 2009, and in our most recent consolidated financial statements, management information circular, quarterly reports, material change reports and news releases.

Readers are cautioned that the foregoing list of factors that may affect future results is not exhaustive. When relying on our forward-looking statements to make decisions with respect to Pengrowth, investors and others should carefully consider the foregoing factors and other uncertainties and potential events. Furthermore, the forward-looking statements contained in this Annual Information Form are made as of the date of this document and we do not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as required by applicable law. The forward-looking statements contained in this Annual Information Form are expressly qualified by this cautionary statement.

PENGROWTH ENERGY TRUST

Introduction

The Trust is an energy investment trust that was created under the laws of the Province of Alberta on December 2, 1988. The purpose of the Trust is to pay distributions to our Unitholders and to purchase and hold Royalty Units and other securities issued by the Corporation, its wholly-owned subsidiary, as well as other investments and to issue Trust Units to members of the public. The Corporation directly and indirectly acquires, owns and manages Working Interests and Royalty Interests in oil and natural gas properties. The head office and registered office of the Trust is located at 2100, 222 — 3rd Avenue S.W., Calgary, Alberta, Canada, T2P 0B4.

The Trust

The Trust is governed by the Trust Indenture. Under the Trust Indenture, the Trust has issued Trust Units and class A trust units to Unitholders. Each Trust Unit and class A trust unit represents a fractional undivided beneficial interest in the Trust. Our Unitholders receive monthly distributions as declared by the Board in respect of the royalty (“Royalty”) the Corporation pays to the holder of the Royalty Units, and in respect of investments that are held by the Trust.

The Trust holds 100 percent of the outstanding common shares in the capital of the Corporation. The Trust also holds all of the Royalty Units issued by the Corporation. The Trust holds other permitted investments, including indebtedness of the Corporation and oil and gas processing facilities. The Trust’s share of royalty income, together with any lease, interest and other income of the Trust, less general and administrative expenses, management fees, debt repayment, taxes and other expenses (provided that there is no duplication of expenses already deducted from royalty income), forms the cash to be distributed by the Trust.

The Corporation

The Corporation was created under the laws of the Province of Alberta on December 30, 1987. The name of the Corporation was changed from “Pengrowth Gas Corporation” to “Pengrowth Corporation” in 1998. The Corporation presently has 1,100 common shares issued and outstanding, all of which are owned by the Trust. These common shares do not participate in any distributions from the Corporation.

The Corporation acquires, owns and operates Working Interests and Royalty Interests in oil and natural gas properties. The Corporation invests a percentage of cash flow on operated, low cost, low risk, repeatable drilling opportunities in the WCSB. The Corporation has issued Royalty Units to the Trust, which entitles the Trust to receive a 99 percent share of the “royalty income” related to the oil and natural gas interests of the Corporation.

As at December 31, 2009, we had 596 permanent employees.

Prior to July 1, 2009, the Trust and the Corporation were managed by the Manager pursuant to a management agreement among the Manager, the Trust, the Corporation and Computershare, as trustee (the “Management Agreement”). On June 30, 2009, the Management Agreement expired. See “Pengrowth Energy Trust — Recent Developments — Expiry of the Management Agreement”.

Intercorporate Relationships

The following diagram illustrates our organizational structure as of January 1, 2010:

Business Strategy

Our goal over the longer term is to maximize value creation for Unitholders through reinvesting a portion of our cash flow on our oil and gas properties while continuing our cash distributions. In 2009, our business model increased the emphasis on capital reinvestment following a review of the best opportunities for value creation on our existing asset base. This value creation strategy was announced on October 1, 2009 and balances our distributions with our capital program and places an emphasis of living within Pengrowth’s cash flow. Our increased capital program focuses on Pengrowth’s short and medium term inventory of low cost, low risk resource plays that have the ability to enhance reserves and production, including utilizing new technologies, while achieving operational efficiencies and maintaining cost discipline. See “Pengrowth Energy Trust — Recent Developments — Changes to our Value Creation Strategy”. We will continue acquiring companies and assets and anticipate financing those acquisitions with a prudent combination of debt and equity. We are positioning ourselves to continue with this strategy as a dividend paying corporation after we convert from a trust in response to the SIFT Legislation.

Our operational expertise is in the Western Canadian Sedimentary Basin (“WCSB”). We rely on our expertise to partially offset production declines in our mature oil and gas properties as well as develop new production in less mature oil and gas properties. We have an advantage through our expertise in horizontal well carbonate reef multi-stage fracturing technology use, EOR technologies and waterflood optimization. Our inventory of undeveloped land and opportunities on producing properties provide future drilling opportunities for the short-term and mid-term. In the mid-term, we anticipate the development of CO₂ EOR at a number of fields with the initial development at Judy Creek. In the mid-term and long-term, we anticipate developing additional unconventional resource plays for oil and gas, including the Lindbergh SAGD project and the Horn River shale gas property.

We will continue to prepare Pengrowth in 2010 for a transition into a dividend paying corporation on or before January 1, 2011. For 2010, we have established a prudent capital spending level that is higher than the previous year, but flexible in an uncertain commodity price environment. Over the long term, we will target a balance of capital spending that can maintain or modestly grow reserves on a debt adjusted per unit basis. As we address the challenges of transitioning to a dividend paying corporation and the ordinary declines in production from our existing assets through development capital projects, we will create key focus areas where the deployment of newer technology can add production and reserves in a repeatable and scalable manner.

We prioritize our development investments based on each project’s:

	•		net present value of future cash flow as compared to the capital invested;
	•		rate of return of future cash flows;
	•		potential for continued, repeatable and scalable development; and
	•		investments necessary to maintain existing facilities and wells.

Recent Developments

The following is a description of the significant developments in our business since January 1, 2009.

2010 Forecast Capital, Production and Operating Costs

On December 17, 2009, we released the details of our 2010 capital expenditure program and provided guidance on production and operating costs for 2010. Our 2010 development capital expenditure program is expected to be up to $285 million, excluding Alberta drilling credits. We will continue to monitor and adjust capital investment levels in order to ensure that we optimize value, operate within our cash flow and have the flexibility to take advantage of acquisition opportunities.

The table below describes the forecasted capital, production and operating costs for 2010:

Planned Capital Expenditures		($ millions)
Drill, Complete and Tie-In		$	192
Major Projects (Lindbergh, Horn River)			28
Land and Seismic			8
Total Development Capital		$	228
Facilities Maintenance			50
Total Development Capital Including Facilities		$	278
Other (e.g., IT)			7
Total Capital		$	285
Average Daily Production Volume (boepd)			74,000 — 76,000	(1)
Operating Costs (per boe)		$	14.40	(2)
General and Administrative Costs (per boe)		$	2.23	(2)

Notes:

(1)		The 2010 estimate excludes potential additions arising from acquisitions or reductions from dispositions.
(2)		Assuming production targets for 2010 are achieved.

The 2010 capital program is focused 70 percent on oil development and liquids rich gas projects, with the largest portion directed toward tight carbonate and heavy oil projects. Approximately $82 million will be spent on operated tight carbonate plays including $27 million at Carson Creek and $21 million at Judy Creek. We also plan to spend $15.5 million on our heavy oil projects, in addition to an expenditure of $15 million for our pilot SAGD oil project at Lindbergh. At our shale gas property at Horn River, $12 million has been budgeted to drill three wells in the winter of 2009 and 2010.

Our 2010 operating costs of approximately $395 million are expected to slightly increase on a year over year basis by $14 million or four percent. Although we anticipate an increase in power and labour costs, it is expected that the remainder of our other operating costs will remain stable. The anticipated increases in power and labour costs combined with an anticipated lower average production rate for 2010 has resulted in an estimated $14.40 per boe operating cost for 2010, a ten percent increase when compared to the 2009 full year amount of $13.13 per boe. We will continue to actively manage our power usage, the single largest component of our operating costs, through our power shedding and hedging programs.

Total general and administrative (“G&A”) costs are expected to increase slightly for 2010 to $2.23 per boe when compared to full year 2009 cost of $2.14 per boe due to declining production guidance for 2010 versus 2009. Included in our 2010 G&A forecast are non-cash G&A costs of approximately $0.37 per boe. Total costs associated with our anticipated conversion from a trust to a dividend paying corporation are estimated to be approximately $1 million and have been included in the 2010 G&A forecast.

The Board of Directors considered a number of factors in approving the capital budget for 2010, including anticipated cash flow from operations based upon forecast commodity prices, the level of distributions paid by the Trust, our level of indebtedness, access to capital and cost of capital. The 2010 budget relies on undistributed cash from operations to fully fund the capital program.

On January 1, 2009, the Government of Alberta implemented the new royalty framework (the “New Royalty Framework”) and the transitional royalties (the “Transitional Royalties”), which apply to wells drilled after November 18, 2008 and to production from those wells through

December 31, 2013. Approximately 74 percent of our reserves are from properties where royalties are paid to the Government of Alberta. The Alberta Government’s royalties do affect how we allocate capital as the royalties impact both the net present value and rate of return. On March 3, 2009, the Government of Alberta announced an incentive program that was initially intended to be in place for one-year but was subsequently extended on June 25, 2009 for an additional year. This program applies to wells which begin drilling on or after April 1, 2009 and before April 1, 2011. The new well royalty reduction incentive program (“NWRR”) provide a $200 per meter drilled royalty credit as well as a maximum five percent royalty rate for the first year of production. The drilling credits are limited based on a sliding scale of 2008 Alberta production. Our 2010 credit is limited to twenty percent of Alberta Crown royalties paid or an estimated credit of $40 million. The five percent royalty rate extends for one year unless 50,000 barrels of oil or 500 million cubic feet of gas is produced. In either of those instances, the five percent royalty rate ceases.

Convertible Debentures

On December 16, 2009, we announced that we would redeem the outstanding Debentures in accordance with their terms of issuance. On January 15, 2010, the Debentures were redeemed at a cash redemption price of $1,025 per $1,000 principal value for a total cost of $76,609,525, plus accrued and unpaid interest to the redemption date. The cash redemption amount was funded with incremental borrowings from the Credit Facility.

Equity Financing

On October 23, 2009, we completed a bought deal public offering of 28,847,000 Trust Units at a price of $10.40 per Trust Unit for total gross proceeds of approximately $300 million. The net proceeds of approximately $285 million were used to repay indebtedness under the Credit Facility and for general corporate purposes.

Gross Overriding Royalties Created

We created gross overriding royalties (“GORR”) on a number of properties that have approximately 8,000 boepd of production in anticipation of selling the GORR. These GORRs are effective October 1, 2009 and cause five percent of the revenue to be paid.

Result Acquisition

On October 1, 2009, we acquired all of Result Energy’s interests in the Horn River Basin for $11 million dollars. We acquired 28,842 net acres and Result’s interest in one standing wellbore.

Reduction in Distributions

A reduction in distributions from $0.17 per Trust Unit to $0.10 per Trust Unit per month was announced on February 19, 2009 commencing with the March 16, 2009 distribution. The Board of Director’s stated objective in making this reduction in distributions was exercising financial prudence in uncertain times. On October 1, 2009, we announced changes to our value creation strategy to focus on investing a larger percentage of cash flow on operated, low cost, low risk, repeatable drilling opportunities in the WCSB. To provide funds for our expanded capital program, while maintaining fiscal discipline, we reduced our November 16, 2009 cash distribution by 30 percent or $0.03 per Trust Unit to $0.07 per Trust Unit.

Changes to our Value Creation Strategy

On October 1, 2009, we announced changes to our value creation strategy to focus on investing a larger percentage of cash flow on operated, low cost, low risk, repeatable drilling opportunities in the WCSB. The following are some of the key changes that will be implemented as part of the value creation strategy:

	•		Shifting internal capital expenditures on our existing high quality asset base to focus on existing low cost, low risk plays (Carson Creek, shallow gas, CBM) as well as to identify, test and develop other resource plays where repeatable, predictable and scalable results can be achieved.
	•		Increasing capital expenditures as a percentage of cash flow to facilitate higher reinvestment levels on our existing assets as well as to advance longer term value of our Lindbergh, EOR and Horn River resource plays.
	•		Adopting a sustainable business model where distributions plus capital expenditures are equal to cash flow.
	•		Enhancing our low cost culture ensuring a high level of capital efficiency and cost discipline.
	•		Reducing debt to levels more consistent with energy trust averages projected for the next 18 months.
	•		Acquiring other WCSB assets with low cost, low risk, repeatable, predictable and scalable drilling opportunities.
	•		Maintaining or modestly growing production and reserves on a debt adjusted per unit basis.

These changes resulted from our strategic review of the best opportunities for value creation on our existing asset base and a broader review of unconventional value creation opportunities in the WCSB.

Our track record of value creation with the drill bit since 2006, as evidenced by our low finding and development costs, and a review of our current unfunded projects, supports increased levels of capital re-investment.

Taxability of Distributions Paid to U.S. Residents

Effective July 1, 2009, the Trust elected to be treated as a corporation for U.S. federal income tax purposes. Prior to July 1, 2009, distributions paid to U.S. residents were treated as partnership distributions for U.S. federal tax purposes and were subject to a 15 percent Canadian withholding tax to the extent that such amounts represented a distribution of Pengrowth’s income. Pursuant to the Tax Act, distributions to U.S. resident Unitholders of amounts in excess of Pengrowth’s income (e.g., returns of capital) were also subject to a 15 percent Canadian withholding tax. On September 21, 2007, Canada and the United States signed the fifth protocol to the Canada-U.S. Convention dated September 21, 2007 (the “Protocol”) to the Canada-United States Tax Convention, 1980 (the “Canada-U.S. Convention”), which would have increased the amount of Canadian withholding tax from 15 to 25 percent on distributions of income. The increase would have become effective on January 1, 2010. Under Article IV(7)(b) of the Protocol, U.S. resident Unitholders are denied certain of the benefits under the Canada-U.S. Convention which would otherwise reduce the withholding tax on distributions of Pengrowth’s income from 25 to 15 percent. The effect of Pengrowth’s election to be treated as a corporation is to maintain the current withholding tax rate of 15 percent and not subject its U.S. investors to an increase in the 15 percent withholding tax on their distributions starting January 1, 2010.

Expiry of the Management Agreement

The Unitholders and the Royalty Unitholders approved the Management Agreement (the “Management Agreement”) at the annual and special meetings held on June 17, 2003. Pursuant to the Management Agreement, the Manager provided advisory, management, and administrative services primarily to the Trust and the Corporation. The Management Agreement expired on June 30, 2009. On October 10, 2007, a special committee of the Board of Directors, comprised of all independent members of the Board, was formed for the purpose of advising the Board in connection with the orderly transition to a traditional corporate governance structure at the end of the term of the Management Agreement. The Management Agreement expired on June 30, 2009 and the Board and executive officers of the Corporation now have exclusive oversight over the business, assets and operations of Pengrowth. There is no ongoing relationship between Pengrowth and the Manager.

Board of Directors and Management Changes

On May 25, 2009 Derek W. Evans was appointed as the President and Chief Operating Officer and as a director of the Corporation. On September 13, 2009, we announced the appointment of Derek W. Evans as President and Chief Executive Officer of the Corporation. Mr. Evans’ appointment as Chief Executive Officer followed the retirement of James S. Kinnear as Chairman and Chief Executive Officer. Mr. Kinnear remains on the Board of Directors.

On November 11, 2009, John Zaozirny, Vice Chairman and Lead Independent Director, was appointed as the Chairman of the Board of Directors.

On January 8, 2010, we announced the appointment of James D. McFarland to the Board of Directors.

Amendments to the Trust Indenture and the Unanimous Shareholder Agreement

At our most recent annual and special meeting of Unitholders, held on June 9, 2009, Unitholders approved an extraordinary resolution authorizing certain amendments to the Trust Indenture and to the Corporation’s unanimous shareholder agreement. The purposes of such amendments are to increase the grant of responsibility and authority to the Corporation to administer the business, affairs and operations of

the Trust and to amend the right of the Manager to nominate members of the board of directors of the Corporation. The amendments reflect that the Manager ceased to be the manager of the Trust upon the expiry of the Management Agreement on June 30, 2009. See “Trust Units – The Trustee”.

SIFT Legislation Considerations

On October 31, 2006, the Department of Finance (Canada) (“Finance”) announced proposed tax measures which will materially and adversely change the manner in which Pengrowth is taxed and will also change the character of the distributions to Unitholders for Canadian federal income tax purposes. On June 22, 2007, the SIFT Legislation became law when Bill C-52 received royal assent. It is expected that the SIFT Legislation will apply to Pengrowth and its Unitholders commencing in 2011, provided that Pengrowth does not exceed the limits on “normal growth” prior to that time.

On July 14, 2008, Finance announced proposals that would permit the conversion of a trust to a corporation on a tax-deferred basis (the “SIFT Conversion Rules”). Finance also announced changes to these rules on November 28, 2008 and introduced a notice of ways and means motion on January 27, 2009 implementing the SIFT Conversion Rules. On March 12, 2009, the SIFT Conversion Rules received royal assent in Bill C-10. The SIFT Conversion Rules contain legislation which permits a conversion of a trust to a corporation to occur on a tax-deferred basis under two general types of commercial structures: (i) an exchange transaction, whereby unitholders of a trust would exchange their units for securities issued by a corporation, or (ii) a dissolution transaction, whereby the trust would distribute the securities it holds in its corporate subsidiary to its unitholders in consideration for the redemption of the unitholders’ units. Under either scenario, it is expected that the shares received by the unitholders would be issued by the new “public” entity and would be listed on the TSX or some other public stock exchange. The SIFT Conversion Rules also include certain provisions which permit the consolidation of the trust’s structure to occur on a tax-deferred basis. The SIFT Conversion Rules require that the exchange transaction or the dissolution transaction, as the case may be, be implemented prior to 2013. Alternative structures may also exist to enable a SIFT conversion after that date on a tax deferred basis.

As a result, we currently anticipate converting to a dividend paying corporation on or before January 1, 2011. We believe our current structure provides value for our Unitholders and there may not be any immediate incentive to make a structural change prior to this date. This will allow us to continue to carefully manage our tax pools for future use as a dividend paying corporation.

We believe there will be an ongoing demand from investors for strong yield investments, and that a dividend paying entity is the most appropriate for our current asset base.

At-the-Market Equity Distribution Program

On December 14, 2007, we entered into an equity distribution agreement which was subsequently amended on July 10, 2009 (the “Distribution Agreement”) with SG Americas Securities, LLC and FirstEnergy Capital Corp. (collectively, the “Underwriters”) which permits us to distribute up to 25,000,000 Trust Units from time to time through the Underwriters (the “Equity Distribution Program”). Sales of Trust Units, if any, pursuant to the Distribution Agreement are made in transactions that are deemed to be “at-the-market distributions”, including sales made directly on the NYSE or the TSX. The Trust Units are distributed at market prices prevailing at the time of sale and, as a result, prices may vary between purchasers and during the period of distribution. A total of 901,400 Trust Units were issued under the Equity Distribution Program during the year ended December 31, 2009. The net proceeds of the distribution of Trust Units were used to repay debt, for development capital expenditures and for general business purposes. Regulatory approval permitting the distribution under the Equity Distribution Program was allowed to expire in January 2010 and may be reinstated at any time.

Historical Developments – 2007 and 2008

On September 30, 2008, we closed the acquisition of Accrete Energy Inc. for total consideration of $120 million paid by the issuance of 4,973,325 Trust Units and the assumption of $22 million of Accrete’s net liabilities. We acquired 1,900 boepd of production in the Harmattan gas field and 8.4 MMboe of P+P Company Interest reserves.

On August 21, 2008, we completed a U.S. $265 million private placement of 6.98 percent senior unsecured ten year notes to a group of U.S. investors, and a $15 million private placement of 6.61 percent senior unsecured ten year notes to a group of Canadian investors (together, the “2008 Senior Notes”). Interest on these notes is payable semi-annually.

On June 13, 2008, we amended and renewed our Credit Facility. The Credit Facility is unsecured, covenant based and has a three-year term expiring June 15, 2011. We have the option to extend the Credit Facility each year, subject to the approval of the lenders, or repay the entire balance at the end of the three-year term. In 2009, we chose not to exercise this option. In addition, we have a demand operating line of credit for working capital purposes, the size of which was increased from $35 million to $50 million as part of the June 13, 2008 amendments. As at December 31, 2009, availability under these facilities was reduced by drawings of $71 million and by outstanding letters of credit in the amount of approximately $23.2 million.

During 2007, we disposed of certain non-core assets to high-grade our portfolio. Total proceeds from dispositions during 2007 was $476 million. These transactions resulted in a decrease of 21.7 MMboe Proved and 28.4 MMboe Proved Plus Probable Reserves.

On July 26, 2007, we completed a U.S. $400 million private placement of 6.35 percent senior unsecured ten year notes (the “2007 U.S. Senior Notes”) to a group of U.S. investors. Interest on these notes is payable semi-annually.

On July 25, 2007, we filed a registration statement with the SEC to expand our distribution reinvestment and Trust Unit purchase plan (“DRIP”) to permit Unitholders resident in the United States to participate in the DRIP. The enhanced DRIP permits Unitholders to elect to reinvest their cash distributions in additional Trust Units at a five percent discount to the weighted average closing price of the Trust Units on the TSX for the 20 trading days immediately preceding the cash distribution date. In addition, pursuant to the DRIP, Unitholders may purchase additional Trust Units for cash of up to Cdn. $1,000 (U.S. $1,000) per month under the same terms.

On January 22, 2007, we closed the acquisition of entities that held certain properties from ConocoPhillips Canada for a purchase price of $1.0375 billion, prior to adjustments. This acquisition was funded through our December 8, 2006 equity offering of 24,265,000 Trust Units at a price of $19.00 per Trust Unit, which yielded total gross proceeds of $461,035,000, and from the proceeds of a $600,000,000 bridge credit

facility, which has since been repaid in full. The acquisition added 64.7 MMboe of Total Proved Plus Probable Reserves and more than 375,000 acres of undeveloped lands. The acquired properties are high working interest and were a strategic fit to our existing asset base.

Trends

There are a number of business and economic factors which underlie trends in the oil and gas industry in western Canada that influence the future of our business.

Commodity prices have the most significant impact on our financial results, and have proven to be quite volatile since peak prices for oil and North American natural gas were reached in 2008. Oil prices have partially rebounded through the last half of 2009 while natural gas prices in North America have not experienced a similar recovery. At the same time, the increase in value of the Canadian dollar relative to the U.S. dollar has also reduced the reported value stated in Canadian dollars to Pengrowth of our oil and gas sales. Since our expenses are paid in Canadian dollars and commodity prices are generally US dollar denominated, the higher Canadian dollar has a negative impact on our cash flow. We have continued to hedge portions of our oil and natural gas production in order to partially insulate us from commodity price volatility. We have hedged in Canadian dollars to partially mitigate the impact of the rising Canadian dollar. We have adopted a cautious capital program in 2010 in order to maintain as much financial flexibility as possible in the face of continued commodity price uncertainty.

Our capital program for 2010 will continue to place a greater emphasis on value creation through our drilling programs. We will continue to spend capital to further our long term resource potential at Lindbergh and Horn River while looking for new areas where repeatable drilling programs can add production and reserves to complement our mature assets. With lower commodity prices and higher costs in western Canada, the Alberta and British Columbia governments introduced royalty incentive programs that include lower royalties for newly drilled wells and in Alberta a royalty credit to offset some of the drilling costs.

The deployment of newer drilling and completion technology, in particular multi-stage fractured horizontal wells, has changed the productivity and economic returns of wells in tighter geological formations. Mature assets in western Canada that were previously considered to be marginal now may have additional reserves, production and improved economics from the application of this newer technology. We also anticipate increasing our use of enhanced oil recovery technology such as hydrocarbon miscible floods, polymer injection and CO2 injection to increase the recoverable reserves from known reservoirs.

The credit and capital markets improved in 2009 allowing us to issue Trust Units for $285 million in net proceeds under a bought deal public offering of Trust Units and approximately $10 million under the Equity Distribution Program. Coupled with our intent to live within our cash flow, we are in a good position to acquire assets in western Canada. A significant number of producing properties in western Canada are expected to be sold in 2010 as larger oil and gas producers sell some of their conventional production and smaller gas-weighted producers may have difficulty funding full capital programs.

For additional information regarding our strategy in this business environment, see “Management’s Discussion and Analysis – Outlook” in our Annual Report for the year ended December 31, 2009.

PENGROWTH — OPERATIONAL INFORMATION

Principal Properties

The portfolio of properties acquired and held by us primarily includes relatively long life, oil and gas producing properties with established production profiles.

The following table summarizes our producing properties as of December 31, 2009 based on the GLJ Report using forecast prices and costs. We obtained the GLJ Report dated February 5, 2010 in respect of the oil and gas properties of Pengrowth effective December 31, 2009. The following table also contains our average daily production of oil, natural gas and NGLs for the year ended December 31, 2009.

Summary of Company Interest
at December 31, 2009⁽¹⁾
(Forecast Prices and Costs)⁽²⁾

														P+P
						Remaining				Reserve				Value Before
		P+P				Reserve				Life				Tax at 10%				2009 Oil				2009 Gas				2009 NGL				2009 Total
		Reserves				Life				Index				Discount				Production				Production				Production				Production
Field		(Mboe)(4)				(years)				(years)				($MM)				(bblpd)				(MMcfpd)				(bblpd)				(boepd)(4)
Light Oil Properties
Judy Creek			34,085				50				13.4				758.3				6,221				5.3				1,899				8,998
Weyburn			21,811				48				22.1				405.1				2,653				0.0				0				2,652
Swan Hills			16,684				50				18.2				232.1				2,058				2.1				301				2,707
Carson Creek			15,749				44				14.4				264.3				2,150				4.3				247				3,110
Deer Mountain			6,000				47				20.4				105.8				576				0.1				73				672
Fenn Big Valley			5,799				50				9.6				90.5				741				4.9				78				1,639
Other(3)			30,859								10.4				619.4				6,768				6.2				386				8,190
Subtotal			130,987								13.9				2,475.5				21,166				22.9				2,984				27,969
Heavy Oil Properties
Bodo			7,603				37				11.4				139.2				1,655				1.4				0				1,889
Jenner			6,756				24				6.2				202.1				2,900				2.6				20				3,353
Tangleflags			4,667				43				7.3				72.8				2,074				0.3				0				2,117
Other(3)			4,324								7.7				64.6				929				4.3				0				1,646
Subtotal			23,350								7.9				478.7				7,559				8.6				20				9,005
Conventional Gas Properties
Olds			18,020				50				12.6				224.2				7				18.8				709				3,849
Harmattan			17,410				50				10.3				219.2				393				18.6				1,679				5,172
Carson Creek			7,920				19				4.5				198.8				40				6.6				1,126				2,262
Dunvegan			5,786				33				10.3				77.1				32				7.5				414				1,698
Quirk Creek			5,545				40				9.2				76.9				0				6.5				345				1,430
Kaybob			3,316				34				13.3				43.5				0				4.1				41				722
Blackstone			3,110				32				10.3				32.9				0				5.3				0				886
McLeod River			3,083				47				8.2				48.4				22				5.5				214				1,150
Other(3)			10,878								7.9				160.1				462				23.5				391				4,771
Subtotal			75,069								9.0				1,081.1				956				96.4				4,919				21,939
Shallow Gas Properties
Twining/Three Hills Creek			11,779				50				10.5				194.6				389				12.4				342				2,794
Coal Bed Methane			9,066				39				12.6				105.9				0				12.4				9				2,069
Monogram			6,999				40				8.8				114.5				0				15.2				0				2,533
Jenner			6,313				32				9.8				74.7				21				10.1				10				1,707
Lethbridge			2,851				47				9.2				33.4				2				6.0				0				1,005
Other(3)			13,942								9.7				163.4				300				26.6				128				4,864
Subtotal			50,950								10.1				686.6				713				82.6				489				14,971
Offshore Gas Properties
Sable Island			9,031				8				4.4				146.0				0				26.7				1,178				5,633
Subtotal			9,031								4.4				146.0				0				26.7				1,178				5,633
Oil Sands Properties
Lindbergh			6,348				16				—				17.0				0				0.0				0				0

P+P

Remaining

Reserve

Value Before

P+P

Reserve

Life

Tax at 10%

2009 Oil

2009 Gas

2009 NGL

2009 Total

Reserves

Life

Index

Discount

Production

Production

Production

Production

Field

(Mboe)(4)

(years)

(years)

($MM)

(bblpd)

(MMcfpd)

(bblpd)

(boepd)(4)

Subtotal

6,348

—

17.0

0

0.0

0

0

Total

295,734

10.6

4,884.9

30,393

237.2

9,590

79,518

Light Oil Properties

Judy Creek

We have a 100 percent Working Interest in both the Judy Creek Beaverhill Lake Unit and the Judy Creek West Beaverhill Lake Unit (together referred to as “Judy Creek”). We also have a 54.4 percent Working Interest in the Judy Creek Gas Conservation Plant that services a number of other properties in the area including Swan Hills, Virginia Hills and South Swan Hills. Judy Creek is located approximately 200 kilometres northwest of Edmonton, Alberta and covers an area of approximately 38,300 acres. Judy Creek was discovered in 1959, placed on waterflood in 1962 and hydrocarbon miscible flood in 1985. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2009 are estimated to be 34.1 MMboe. The Remaining Reserve Life is 50 years and the Reserve Life Index is 13.4 years. Our Company Interest production for Judy Creek averaged 8,998 boepd in 2009.

2009 Development Activity

The 2009 development program included an oil producer drilled in the fourth quarter of 2008 in the northwest quadrant of “A” Pool that was completed and placed on production in January 2009. In December, three new miscible patterns in the southwest quadrant of the “A” Pool began solvent injection. Over the course of the year, nine acid fracture stimulations and three artificial-lift conversions added approximately 160 boepd.

2010 Development Activity

The 2010 capital program includes the development of a new miscible pattern. In addition, two directional oil producers will be drilled from existing suspended wellbores and one new vertical oil producer will be drilled. Follow-up oil well locations have been identified for execution pending results of the approved program. The ongoing program of well optimization will continue.

Carbon Dioxide (CO₂) Pilot

The intent of the Judy Creek CO₂ enhanced oil recovery pilot project is to evaluate the potential of CO₂ injection to increase oil recovery and to recover hydrocarbons left behind from the hydrocarbon miscible flood. The results will provide information to us to determine the feasibility of a commercial CO₂ injection. The injected fluid consists of trucked-in CO₂ and acid gas. The acid gas comes from the Judy Creek Conservation Plant and consists mainly of CO₂ and hydrogen sulfide (H₂S). CO₂ injection commenced in February of 2007 ended June 2009.

Favorable response has been evident to date with both incremental oil and hydrocarbon gas and gas liquids from the hydrocarbon miscible flood being produced. To date, 1.2 Bcf of CO₂ has been injected into the 80 acre pilot pattern. This program has resulted in an additional 46 Mbbl of oil (approximately 2.3 percent of the original oil in place) and 190 MMcf of natural gas hydrocarbons being produced from the hydrocarbon miscible flood. Although CO₂ injection has ended, the increased production is expected to continue and monitoring will be maintained into 2010.

Weyburn Unit

The Weyburn Unit is located in southeastern Saskatchewan, Canada. Pengrowth holds a 9.76 percent non-operated Working Interest in the Unit. The Unit produces medium sour crude oil (25-34° API) from the Midale carbonate reservoir under waterflood and a CO₂ miscible flood enhanced oil recovery program. The field consists of approximately 700 production wells and 300 injection wells. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2009 are estimated to be 21.8 MMboe. The Remaining Reserve Life is 48 years and the Reserve Life Index is 22.1 years. Our Company Interest production for Weyburn averaged 2,652 boepd in 2009.

2009 Development Activity

In 2009, drilling was limited to three horizontal CO₂ injectors. Efforts focused on the optimization of existing wells. CO₂ injection was held at 125 MMcfpd of source CO₂ plus approximately 123 MMcfpd of recycled CO₂, which is higher than previous years due to the addition of recycling compression in both 2008 and 2009.

2010 Development Activity

The 2010 capital program includes the drilling of two production wells, three CO₂ injectors and the start-up of five new CO₂ EOR patterns.

Swan Hills

The Swan Hills Unit is located near the Judy Creek field in north central Alberta. We hold a 24.01 percent non-operated Working Interest in the Swan Hills Unit No. 1. Light sour crude oil is produced from the Beaverhill Lake reservoir which has a waterflood and a hydrocarbon miscible flood EOR program. The remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2009 are estimated to be 16.7 MMboe. The Remaining Reserve Life is 50 years and the Reserve Life Index is 18.2 years. Our Company Interest production for Swan Hills averaged 2,707 boepd in 2009.

2009 Development Activity

In 2009, four new oil wells were drilled in the east margin area of the Unit, three of which were on production at year end. Three new hydrocarbon miscible flood patterns were fully developed, which included the conversion of two oil wells to injectors. Solvent injection started in all three hyrdrocarbon miscible patterns in the second half of 2009. Two of the patterns were the first to target the platform of the reef. Pattern development began in 2008. In addition, eight oil wells were recompleted.

2010 Development Activity

No drilling is planned for 2010. Hydrocarbon miscible injection will continue in 2010. One existing pattern will be re-configured to flood a previously unswept reservoir. A 40 acre pattern that has been on water injection since 2008 will be converted to a hydrocarbon miscible pattern.

Carson Creek

Carson Creek is located 160 kilometres northwest of Edmonton, Alberta and is comprised of two Pengrowth-operated Units (one oil and one gas and condensate) which cover approximately 46,200 acres. The Carson Creek North Unit (oil), in which we have an 88.6 percent Working

Interest, was discovered in 1958 and the current waterflood was initiated in 1964. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2009 are estimated to be 15.7 MMboe. The Remaining Reserve Life is 44 years and the Reserve Life Index is 14.4 years. Our Company Interest production for the Carson Creek North Unit averaged 3,110 boepd in 2009.

2009 Development Activity

Our 2009 activities included ongoing geologic modeling and reservoir simulation, waterflood optimization and well workovers to improve production. Natural pool decline was entirely offset in 2009, resulting in a two percent increase in daily average rate over 2008.

2010 Development Activity

We anticipate taking advantage of regular well maintenance to enhance production from existing wells in the Carson Creek North Unit. Waterflood optimization, including several injector stimulations and a water injector conversion, are planned for 2010.

Deer Mountain Area

Deer Mountain is located 190 kilometres northwest of Edmonton, Alberta, and consists of both a Pengrowth-operated Unit, which covers approximately 6,400 acres, and four non-Unit wells. The 85.42 percent Working Interest in the Unit covers ten sections of land, and the non-Unit lands contribute an additional four sections of land with operated interests that range from 67 to 100 percent. A waterflood scheme has been operating in the Deer Mountain Unit since September 1968. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2009 are estimated to be 6.0 MMboe. The Remaining Reserve Life is 47 years and the Reserve Life Index is 20.4 years. Our Company Interest production for Deer Mountain averaged 672 boepd in 2009.

2009 Development Activity

A waterflood optimization project was completed in December at Deer Mountain Unit No. 1. The response to the optimized waterflood is anticipated in the second half of 2010.

2010 Development Activity

We plan to drill two to four horizontal producers and will complete them with multi-stage fracturing. Two to three waterflood optimization workovers and acid fracture stimulation will also be implemented in 2010.

Fenn Big Valley

Fenn Big Valley is located 130 kilometres northeast of Calgary, Alberta. We have high working interests (mostly 100 percent) in several oil pools producing from the Nisku and Leduc formations. The Nisku production currently accounts for approximately 80 percent of the oil production at an average water cut of 97 percent. The field was placed on production in 1953 and has produced approximately 62 percent of the original oil in place under natural water drive. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2009 are estimated to be 5.8 MMboe. The Remaining Reserve Life is 50 years and the Reserve Life Index is 9.6 years. Our Company Interest production for Fenn Big Valley averaged 1,639 boepd in 2009.

2009 Development Activity

Our 2009 activity included four Nisku oil recompletions and reactivations as well as five Belly River/Edmonton gas recompletions.

2010 Development Activity

Our 2010 planned activities include a reactivation of a Nisku oil well and several recompletions of shallow gas wells.

Heavy Oil Properties

Bodo

The Bodo heavy oil property straddles the Alberta-Saskatchewan border near Township 35 and produces mainly 12° API oil from the McLaren formation and 15° API oil from the Lloydminster formation. We operate several batteries to treat oil, as well as a number of compressor stations to process solution and non-associated gas. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2009 are estimated to be 7.6 MMboe. The Remaining Reserve Life is 37 years and the Reserve Life Index is 11.4 years. Our Company Interest production for Bodo averaged 1,889 boepd in 2009.

2009 Development Activity

We drilled one horizontal and one vertical well in the Cactus Lake Bakken pool. One horizontal well was drilled in the Bodo area as part of our successful polymer project. Injection wells were added in several areas, including Cactus Lake and East Bodo to expand the polymer area, and in South Bodo.

2010 Development Activity

A new ten well program is planned in the East Bodo area in 2010. The program will consist of seven producers and three injectors. We will convert producing wells to injection wells in East Bodo, Cactus and Cosine to improve ultimate oil recovery. The polymer flood is expected to be expanded to other portions of the pool.

Jenner

The Jenner oil property is located approximately 250 kilometres east of Calgary, Alberta. We have an average Working Interest of 94.5 percent in the north pool and an average Working Interest of 89.1 percent in the south pool. We operate all of the production within this property. Oil quality ranges from 14-20° API and is produced from Upper Mannville Sands. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2009 are estimated to be 6.8 MMboe. The Remaining Reserve Life is 24 years and the Reserve Life Index is 6.2 years. Our Company Interest production for Jenner averaged 3,353 boepd in 2009.

2009 Development Activity

Our 2009 development activities included drilling two vertical oil wells and one gas well. In addition, water handling improvements were made and numerous production optimization projects were completed.

2010 Development Activity

The 2010 development activities will include the drilling of several oil wells as well as production optimization projects and further water handling improvements.

Tangleflags

Tangleflags is located in west central Saskatchewan, approximately 40 kilometres northeast of Lloydminster and produces 12° API oil mainly from the Lloydminster sands under thermal recovery process, with some cold production from other Mannville sands. We hold a 50 percent non-operating Working Interest. The thermal Tangleflags North EOR project commenced operation in the late 1980’s and a variety of well configurations have been tried. These include vertical injection with vertical production, vertical injection with horizontal production,

and horizontal injection with horizontal production (i.e., steam assisted gravity drainage or SAGD). The remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2009 are estimated to be 4.7 MMboe. The Remaining Reserve Life is 43 years and the Reserve Life Index is 7.3 years. Our Company Interest production for Tangleflags averaged 2,117 boepd in 2009.

2009 Development Activity

In 2009, three recompletions and five pump upgrades were completed.

2010 Development Activity

In 2010, fifteen recompletions are planned. No drilling is planned.

Conventional Gas Properties

Olds

The Olds property is our largest operated gas property, and is located 95 kilometres north of Calgary, Alberta. Our interests include 100 percent ownership in the Olds Gas Unit No. 1. In addition, we have a 75 percent average Working Interest in non-Unit reserves. The Olds Unit produces sour natural gas from the Wabamun Formation, with H₂S concentrations ranging from less than one to 35 percent. The non-Unit reserves are contained within formations from the Wabamun to the Edmonton group, and are predominantly sweet natural gas. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2009 are estimated to be 18.0 MMboe. The Remaining Reserve Life is 50 years and the Reserve Life Index is 12.6 years. Our Company Interest production for Olds averaged 3,849 boepd in 2009.

We operate and own 100 percent of the sour gas processing plant at Olds, which processes both our production and third party volumes. Third party volumes represent approximately 30 percent of the total volumes processed.

2009 Development Activity

Many of the 2009 planned activities were delayed due to low commodity prices; however, one new Wabamun gas well was drilled and tied-in. A Pekisko well that was recompleted with multi-stage fracturing technology in late 2008 was brought back on-stream early in 2009 with a 250 percent production increase. A program to extinguish flare pilots in the field was implemented, resulting in fuel gas savings of 120 boepd.

2010 Development Activity

Development plans for 2010 include debottlenecking the gathering system with the installation of a new pipeline. In addition, recompletion of two to three Wabamun wells using multi-stage fracturing technology, a clean-out of a Wabamun well currently shut in, and the replacement of a corroded pipeline to another shut in well are planned.

Harmattan

The Harmattan gas field is located approximately 90 kilometres northwest of Calgary, Alberta. It is comprised of wells and pools in formations from the Cardium to the Wabamun, as well as two partner-operated Elkton Units. The production is predominantly sweet natural gas with Working Interests averaging 55 percent in the non-Unit lands and 25 percent in the Units. The Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2009 are estimated to be 17.4 MMboe. The Remaining Reserve Life is 50 years and the Reserve Life Index is 10.3 years. Our Company Interest production for Harmattan averaged 5,172 boepd in 2009.

2009 Development Activity

A successful Cardium well was drilled and field optimization resulted in production improvements of 115 boepd.

2010 Development Activity

Development plans for 2010 includes one to two Elkton infill drills, drilling a number of horizontal Cardium wells utilizing multiple stage fracturing technology and a recompletion of a Viking zone.

Carson Creek

Carson Creek is located 160 kilometers northwest of Edmonton, Alberta and is comprised of two Pengrowth-operated Units (one oil and one gas and condensate) which cover approximately 46,200 acres. The Carson Creek Beaverhill Lake Unit No. 1 (gas), in which we have a 95.1 percent Working Interest, was discovered in 1958. From 1962 to 1985, a lean gas cycling scheme to strip NGLs from the liquid-rich natural gas was operational. During this period, the lean gas was re-injected. Gas re-injection now only occurs during plant disruption. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2009 are estimated to be 7.9 MMboe. The Remaining Reserve Life is 19 years and the Reserve Life Index is 4.5 years. Our Company Interest production for Carson Creek gas averaged 2,262 boepd in 2009.

We have a 95.1 percent Working Interest in the Carson Creek Gas plant, which processes the gas production.

2009 Development Activity

Development activity in 2009 consisted of drilling nine horizontal Swan Hills gas wells that proved the feasibility of horizontal stage fracturing technology in the newly delineated “C” pool. Capital cost savings were realized with each new well drilled.

2010 Development Activity

Continuation of the horizontal drilling program is planned for 2010. Six new horizontal drills have been budgeted for a program starting in the second half of the year.

Dunvegan

The partner operated Dunvegan gas field is located 430 kilometres northwest of Edmonton, Alberta in the Peace River area. We have a 10.37 percent Working Interest in the Dunvegan Gas Unit No. 1 and various interests in non-unit producing wells. The property contains over 200 producing wells and covers an area of approximately 52,600 acres. Approximately 95 percent of the Unit’s identified natural gas reserves are contained in the Mississippian Middle Debolt formation. The balance is in the Upper Debolt formation, which is being annexed to the Unit. The remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2009 are estimated to be 5.8 MMboe. The Remaining Reserve Life is 33 years and the Reserve Life Index is 10.3 years. Our Company Interest production for Dunvegan averaged 1,698 boepd in 2009.

2009 Development Activity

No drilling or completion activities occurred in 2009 due to low gas prices.

2010 Development Activity

Activity in 2010 will include ten new drilling locations focusing on the Middle Debolt zone. The addition of the Upper Debolt zone to the unit is expected to be finalized in 2010.

Quirk Creek

The Quirk Creek asset is located approximately 50 kilometres southwest of Calgary, Alberta, and is comprised of several highly permeable pools contained within thrust sheets carrying Mississippian reservoirs. We hold a 68 percent Working Interest in four producing Rundle deep plate gas wells, a 31 percent Working Interest in ten producing Rundle upper plate gas wells, a 25 percent Working Interest in three producing gas wells in other zones and a 30.5 percent Working Interest in the Quirk Creek Gas Plant. Natural gas production averages nine percent sour natural gas, with associated liquids. Quirk Creek has been producing since the late 1960’s, but a new 68 percent Pengrowth Working Interest well was drilled in 2006. This was the first well drilled in 25 years and extended the structure’s potential and accounts for the excess deliverability at Quirk Creek. The remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2009 are estimated to be 5.5 MMboe. The Remaining Reserve Life is 40 years and the Reserve Life Index is 9.2 years. Our Company Interest production for Quirk Creek averaged 1,430 boepd in 2009, a marked increase over 2008 as a result of the resolution of a number of equipment and design problems.

2009 Development Activity

No drilling or other subsurface development work was performed in 2009. Well capability continues to exceed plant inlet capacity.

2010 Development Activity

No drilling or other subsurface development work is planned for 2010.

Kaybob

The Kaybob Notikewin Unit No. 1 is located approximately 240 kilometres northwest of Edmonton, Alberta. We hold a 98.88 percent Working Interest in the Unit. The Kaybob Notikewin Unit No. 1 produces natural gas and NGLs from the Notikewin formation. Initial production from the Unit began in 1962. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2009 are estimated to be 3.3 MMboe. The Remaining Reserve Life is 34 years and the Reserve Life Index is 13.3 years. Our Company Interest production for Kaybob averaged 722 boepd in 2009.

2009 Development Activity

No drilling activity or well tie-ins took place in 2009.

2010 Development Activity

Two field compressor installations are planned to reduce producing pressures and increase production. One gas well reactivation is planned.

Blackstone

Blackstone is located approximately 180 kilometres northwest of Red Deer, Alberta. We hold a 50 percent Working Interest in one producing conventional gas well and a 23.9 percent Working Interest in a compressor facility. The subject well was drilled into the Blackstone Beaverhill Lake A Pool and was placed on production in January 2002. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2009 are estimated to be 3.1 MMboe. The Remaining Reserve Life is 32 years and the Reserve Life Index is 10.3 years. Our Company Interest production for Blackstone averaged 886 boepd in 2009.

2009 Development Activity

There was no development activity on the Blackstone property in 2009.

2010 Development Activity

No drilling is planned for 2010.

McLeod River

The McLeod River property is located approximately 110 kilometres west of Edmonton, Alberta. We hold various interests in 87 wells in the property ranging from 16.7 to 100 percent. Conventional gas is produced from the Rock Creek, Gething, Notikewin and Cardium formations. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2009 are estimated to be 3.1 MMboe. The Remaining Reserve Life is 47 years and the Reserve Life Index is 8.2 years. Our Company Interest production for McLeod River averaged 1,150 boepd in 2009.

2009 Development Activity

Our 2009 development activity included two well recompletions and one well reactivation.

2010 Development Activity

The activities for 2010 will include drilling one well and recompleting five others.

Shallow Gas Properties

Twining/Three Hills Creek

The Twining/Three Hills Creek property is located 130 kilometres northeast of Calgary, Alberta. Although production is mainly gas, there is also oil production from this area. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2009 are estimated to be 11.8 MMboe. The Remaining Reserve Life is 50 years and the Reserve Life Index is 10.5 years. Our Company Interest production for Twining/Three Hills Creek averaged 2,794 boepd in 2009.

2009 Development Activity

Development activity in 2009 included the drilling of one gas and three oil wells, one recompletion for oil and four recompletions for gas.

2010 Development Activity

Our 2010 development activities include drilling and recompleting Pekisko horizontal oil wells with multi-stage fracturing techniques. Five Mannville oil and gas recompletions are planned.

Coal Bed Methane (CBM)

Our CBM activity is focused in the Ghost Pine, Fenn Big Valley and Twining areas which are 100 to 160 kilometres northeast of Calgary, Alberta. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2009 are estimated to be 9.1 MMboe. The Remaining Reserve Life is 39 years and the Reserve Life Index is 12.6 years. Our Company Interest CBM production averaged 2,069 boepd in 2009.

2009 Development Activity

We drilled four Horseshoe Canyon CBM wells and one Mannville CBM horizontal well. Partners drilled an additional 6.5 net wells.

2010 Development Activity

Plans for 2010 include drilling 35 Horseshoe Canyon CBM/Belly River gas wells and one Mannville CBM horizontal well.

Monogram Gas Unit

The Monogram Gas Unit is located approximately 225 kilometres southeast of Calgary, Alberta. We hold a 53.82 percent Working Interest in the partner-operated Unit. Gas production from the Unit is in the shallow Medicine Hat, Milk River and Second White Specks formations. The Monogram Unit was unitized June 1, 1975. To the end of 2009, 919 wells have been drilled. The remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2009 are estimated to be 7.0 MMboe. The Remaining Reserve Life is 40 years and the Reserve Life Index is 8.8 years. Our Company Interest production for Monogram averaged 2,533 boepd in 2009.

2009 Development Activity

Our partner drilled 80 infill wells in the first quarter of 2009.

2010 Development Activity

There are no planned capital expenditures for 2010.

Jenner

The Jenner shallow gas property is located 250 kilometres east of Calgary, Alberta. Production from this property is primarily from the Milk River, Medicine Hat and Second White Specks formations within the Jenner, Atlee Buffalo and Atlee fields. We have an average Working Interest of 67.2 percent and operate the majority of the production. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2009 are estimated to be 6.3 MMboe. The Remaining Reserve Life is 32 years and the Reserve Life Index is 9.8 years. Our Company Interest production for Jenner Shallow Gas averaged 1,707 boepd in 2009.

2009 Development Activity

Our 2009 development activities focused on gas well de-watering and two Belly River gas well recompletions.

2010 Development Activity

The 2010 development activities will focus on a shallow gas infill drilling program of approximately 70 wells for gas from the Milk River, Medicine Hat and Second White Specks Sands. In addition a number of wells will be re-completed.

Lethbridge

Our operations in the Lethbridge, Alberta area cover a large area and include operating over 250 wells, most of which are 100 percent Working Interest. All wells produce sweet gas from the Milk River, BFS (Barons) and Bow Island formations. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2009 are estimated to be 2.9 MMboe. The Remaining Reserve Life is 47 years and the Reserve Life Index is 9.2 years. Our Company Interest production for Lethbridge averaged 1,005 boepd in 2009.

2009 Development Activity

During 2009, we performed 16 coiled tubing cleanouts and reactivated two wells.

     2010 Development Activity

The planned activities for 2010 include a continued well cleanout program.

Offshore Gas Properties

Sable Offshore Energy Project

The Sable Offshore Energy Project (“SOEP”) is located 225 kilometres off the east coast of Nova Scotia and consists of several natural gas fields and five producing platforms. We have an 8.4 percent Working Interest in SOEP. Raw gas is delivered to an onshore gas plant facility at Goldboro where the liquids are extracted and sent to the Point Tupper fractionation plant for processing. Sales gas is transported to market via the Maritimes and Northeast Pipeline. Propane and butane are shipped by both truck and rail and condensate is transported by tanker ship from the platform. SOEP has been producing since late 1999.

Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2009 are estimated to be 9.0 MMboe. The Remaining Reserve Life is 8 years and the Reserve Life Index is 4.4 years. Our Company Interest production for SOEP averaged 5,633 boepd in 2009.

     2009 Development Activity

The 2009 activities at SOEP included the successful drilling of a fourth well in the Alma field. The well was brought on production in October. A maintenance campaign was conducted in August, during which expanded living quarters were installed on the Thebaud platform and vessel inspections and repairs were completed.

     2010 Development Activity

Development activities in 2010 are expected to consist of a series of workovers for wells in the Venture field, and an expansion of the propane truck loading facilities at the Point Tupper fractionation plant. The benefits of developing small gas discoveries (Significant Discovery Licenses) close to the Sable project will be investigated.

Oil Sands Properties

Lindbergh

The Lindbergh oil sands property is located approximately 420 kilometres northeast of Calgary and 65 kilometres southwest of Cold Lake. We hold a 100 percent Working Interest in this oil sands asset where oil quality averages 11° API from the Lloydminster oil sands.

Company Interest Total Proved plus Probable Reserves at December 31, 2009 are estimated to be 6.3 MMboe. See also “—Lindbergh Oil Sands Contingent Resources”.

     2009 Development Activity

The planned drilling program was executed early in 2009 with the completion of two delineation and two observation wells. At mid year, lease continuation applications were made and accepted by Alberta Energy for the expiring portions of the oilsands leases.

     2010 Development Activity

The 2010 program includes delineation drilling and other development work to further confirm resource estimates as well as detailed engineering and procurement in preparation for development of the pilot.

Statement of Oil and Gas Reserves and Reserves Data

Disclosure of Reserves Data

The information in this section is based upon an evaluation by GLJ, prepared in accordance with NI 51-101, with an effective date of December 31, 2009 contained in the GLJ Report dated February 5, 2010, with the exception of information relating to income tax and the after tax future net revenues associated with our reserves, which we determined. The effective date of the information in this section is December 31, 2009 and the preparation date is January 15, 2010 when the final information was provided. The information in this section summarizes our oil, liquids and natural gas reserves and the net present values of future net revenue for these reserves using GLJ’s forecast prices and costs and constant prices and costs. We engaged GLJ to provide an independent evaluation of Proved Reserves and Total Proved Plus Probable Reserves and no attempt was made to evaluate Possible Reserves in the conventional properties. It is our practice to obtain an engineering report evaluating all of our Proved Reserves and Probable Reserves as at December 31 of each year. Only in respect of the Lindbergh oil sands property did GLJ evaluate Possible Reserves and Contingent Resources. All of our reserves are in Canada in the provinces of Alberta, British Columbia, Saskatchewan and Nova Scotia.

The following tables set forth certain information relating to our oil and natural gas reserves and the net present value of the estimated future net revenue associated with such reserves as at December 31, 2009 contained in the GLJ Report dated February 5, 2010. These tables summarize the data contained in the GLJ Report, and, as a result, may contain slightly different numbers than the GLJ Report due to rounding. Columns may not add due to rounding.

For the purposes of this Annual Information Form, the Probable Reserves reported for the Lindbergh oil sands property in the GLJ Report are included with the Heavy Oil reserves. See — “Lindbergh Oil Sands Reserves and Contingent Resources”.

Our future net revenues associated with the production and reserves contained in this Annual Information Form reflect the royalty programs in-place on December 31, 2009. Approximately 74 percent of our reserves are on Alberta Crown land where the Province announced in 2009 a New Well Royalty Reduction (“NWRR”) program that provides a royalty credit equal to $200 per meter drilled and a five percent royalty for the first twelve months of production, not exceeding 50,000 barrels of oil or 500 million cubic feet of gas. This NWRR program applies to wells that began drilling (spud) on or after April 1, 2009 and before March 31, 2011. There are two additional royalty programs which the Province has established: the New Royalty Framework and Transitional Royalties. The Transitional Royalties, which may be elected, applies to wells drilled after November 18, 2008 and to production through December 31, 2013. In the GLJ Report, no election for the Transitional Royalties was assumed as there was no economic advantage to make such an election.

Approximately four percent of our reserves are on British Columbia Crown Lands where the Province announced in August 2009 an oil and gas stimulus package. The stimulus package included a two percent royalty rate for all wells drilled from September 2009 through June 2010.

The information set forth below is derived from the GLJ Report, which has been prepared in accordance with the standards contained in the Canadian Oil and Gas Evaluation (“COGE”) Handbook and the reserves definitions contained in NI 51-101 and the Canadian Oil and Gas Evaluation Handbook. The GLJ Report incorporates estimates of future well abandonment obligations but does not include estimates of remediation costs. The GLJ forecasts of future net revenue are stated prior to any provision for income taxes, interest costs or general and administrative costs and after the deduction of estimated future capital expenditures for wells to which reserves have been assigned. It should not be assumed that the estimated future net revenue shown below is representative of the fair market value of the properties. There is no assurance that such price and cost assumptions will be attained and variances could be material. The recovery and estimates of crude oil, NGL and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, NGL and natural gas reserves may be greater than or less than the estimates provided herein.

We determined the future net revenue and present value of future net revenue after income taxes after taking into account the impact of the SIFT Legislation. See “Certain Canadian Federal Income Tax Considerations — Taxation of the Trust — SIFT Legislation”. Our estimate of income tax in the foregoing analysis makes use of the following assumptions:

•

SIFT tax starting January 2011 at 27.06 percent (and 25.56 percent in 2012 and thereafter). The SIFT tax is based on the provincial allocation from the Corporation’s December 31, 2008 tax return;

•

Annual general and administration expenses at the current level;

•

Interest expense at the current level;

•

Inclusion of tax pools and deductions at the trust level as well as at the operating entity level (total tax pools of $2.9 billion);

•

Royalties paid to the Trust after allowance for capital expenses contemplated by the GLJ Report;

•

Distributions by the Trust to the Unitholders in an amount equal to the cash received by the Trust; and

•

Any such other additional deductions and adjustments as is and would be consistent with the manner in which we file and would file future tax returns. See “Canadian Income Tax Considerations”.

The net revenues estimated in the GLJ Report represent estimates of the revenues from oil and gas sales from our petroleum and natural gas properties together with an estimate of processing revenues less royalties (net of incentives), mineral taxes, field operating expenses and capital obligations. These net revenues are not the same as cash flows from operating activities reported by the Trust in its statement of cash flows. The GLJ Report does not estimate general and administrative expenses and interest.

In accordance with the requirements of NI 51-101, the Report on Reserves Data by Independent Qualified Reserves Evaluator in Form 51-101F2 and the Report of Management and Directors on Oil and Gas Disclosure in Form 51-101F3 are attached to this Annual Information Form as Appendices A and B, respectively.

Reserves Data (Forecast Prices and Costs)

Summary of Oil and Gas Reserves
as of December 31, 2009
(Forecast Prices and Costs) ⁽¹⁾

		Light and Medium Oil												Heavy Oil(2)												Natural Gas Liquids
		Company Interest				Gross Interest				Net Interest				Company Interest				Gross Interest				Net Interest				Company Interest				Gross Interest				Net Interest
Reserves Category		(Mbbl)				(Mbbl)				(Mbbl)				(Mbbl)				(Mbbl)				(Mbbl)				(Mbbl)				(Mbbl)				(Mbbl)
Proved Reserves
Proved Developed Producing			65,640				65,504				52,047				14,370				14,362				12,750				19,253				19,165				14,026
Proved Developed Non- Producing			804				804				556				139				139				127				1,030				1,029				769
Proved Undeveloped			16,358				16,351				12,391				1,846				1,846				1,533				1,190				1,190				795
Total Proved Reserves			82,803				82,659				64,995				16,355				16,347				14,410				21,473				21,384				15,591
Probable Reserves			29,446				29,400				22,476				11,370				11,367				9,976				8,114				8,091				5,892
Total Proved Plus Probable Reserves			112,249				112,059				87,471				27,724				27,713				24,386				29,587				29,475				21,482

		Natural Gas												Coal Bed Methane												Total Oil Equivalent Basis(3)
										Net																Company Interest				Gross Interest				Net Interest
		Company Interest				Gross Interest				Interest				Company Interest				Gross Interest				Net Interest				(Mboe)				(Mboe)				(Mboe)
RESERVES CATEGORY		(MMcf)				(MMcf)				(MMcf)				(MMcf)				(MMcf)				(MMcf)				(3)				(3)				(3)
Proved Reserves
Proved Developed Producing			484,396				481,215				409,311				23,034				21,906				21,635				183,835				182,885				150,648
Proved Developed Non- Producing			18,490				18,322				14,460				—				—				—				5,055				5,025				3,862
Proved Undeveloped			30,360				30,359				26,463				19,263				19,184				16,325				27,665				27,644				21,851
Total Proved Reserves			533,246				529,897				450,234				42,297				41,090				37,960				216,554				215,554				176,361
Probable Reserves			170,204				169,277				140,778				11,293				11,037				10,226				79,180				78,911				63,511
Total Proved Plus Probable Reserves			703,449				699,175				591,013				53,590				52,127				48,186				295,734				294,464				239,872

Notes:

Summary of Net Present Value
of Future Net Revenue
as of December 31, 2009
Before and After Income Taxes
(Forecast Prices and Costs)⁽¹⁾

		Before Income Taxes																				Unit Value
		Discounted at (%/Year)																				Before Income Tax
		0%				5%				10%				15%				20%				Discounted at 10%/Year(2)
Reserves Category		($MM)				($MM)				($MM)				($MM)				($MM)				$/boe				$/Mcfe
Proved Reserves
Proved Developed Producing			5,793				4,301				3,442				2,888				2,502				22.85				3.81
Proved Developed Non-Producing			162				118				93				77				66				24.11				4.02
Proved Undeveloped			1,046				571				335				203				124				15.32				2.55
Total Proved Reserves			7,002				4,989				3,870				3,168				2,691				21.94				3.66
Probable Reserves			3,141				1,641				1,015				696				510				15.99				2.66
Total Proved Plus Probable Reserves			10,143				6,630				4,885				3,865				3,202				20.36				3.39

		After Income Taxes
		Discounted at (%/Year)(3)
		0%				5%				10%				15%				20%
Reserves Category		($MM)				($MM)				($MM)				($MM)				($MM)
Proved Reserves
Proved Developed Producing			5,189				3,840				3,079				2,594				2,260
Proved Developed Non-Producing			103				76				60				51				44
Proved Undeveloped			674				337				184				101				52
Total Proved Reserves			5,966				4,253				3,323				2,746				2,356
Probable Reserves			2,361				1,194				733				505				372
Total Proved Plus Probable Reserves			8,327				5,447				4,056				3,251				2,728

Notes:

Additional Information Concerning Future Net Revenue
(undiscounted)
as of December 31, 2009
(Forecast Prices and Costs)⁽¹⁾

														Capital Development				Abandonment				Future Net Revenue								Future Net Revenue
		Revenue				Royalties(2)				Operating Costs				Costs				Costs(3)				Before Income Taxes				Income Tax				After Income Taxes
Reserves Category		($MM)				($MM)				($MM)				($MM)				($MM)				($MM)				($MM)				($MM)
Proved Reserves			15,658				3,031				4,853				537				235				7,002				1,035				5,967
Total Proved Plus
Probable Reserves			22,388				4,426				6,670				887				262				10,143				1,816				8,327

Notes:

Net Present Value of Future Net Revenue
By Production Group
as of December 31, 2009
(Forecast Prices and Costs)⁽¹⁾

				Future Net Revenue
				Before Income Taxes
				(discounted at
				10%/yr)				Unit Value(4)
Reserves Category		Production Group		($MM)				($/boe)				($/Mcfe)
Total Proved Reserves		Light and Medium Crude Oil (including solution gas and other by-products)(2)			2,015				25.86				4.31
		Heavy Oil (including solution gas and other by-products)(2)			395				24.99				4.16
		Natural Gas (including by-products but excluding solution gas from oil wells)(3)			1,374				18.00				3.00
		Coal Bed Methane			87				13.74				2.29
		Total			3,870				21.94				3.66
Total Proved Plus		Light and Medium Crude Oil (including solution gas and other by-products)(2)			2,510				24.11				4.02
Probable Reserves		Heavy Oil (including solution gas and other by-products)(2)			506				19.21				3.20
		Natural Gas (including by-products but excluding solution gas from oil wells)(3)			1,759				17.36				2.89
		Coal Bed Methane			109				13.59				2.26
		Total			4,885				20.36				3.39

Notes:

Reserves Data (Constant Prices and Costs)

Summary of Oil And Gas Reserves
as of December 31, 2009
(Constant Prices and Costs)⁽¹⁾

		Light and Medium Oil												Heavy Oil(2)												Natural Gas Liquids
										Net												Net												Net
		Company Interest				Gross Interest				Interest				Company Interest				Gross Interest				Interest				Company Interest				Gross Interest				Interest
Reserves Category		(Mbbl)				(Mbbl)				(Mbbl)				(Mbbl)				(Mbbl)				(Mbbl)				(Mbbl)				(Mbbl)				(Mbbl)
Proved Reserves
Proved Developed Producing			62,736				62,613				54,860				13,951				13,944				12,731				17,220				17,137				12,592
Proved Developed Non-Producing			783				783				573				139				139				132				1,048				1,047				795
Proved Undeveloped			16,080				16,072				13,543				1,841				1,841				1,634				992				992				665
Total Proved Reserves			79,599				79,467				68,976				15,931				15,924				14,498				19,260				19,175				14,052
Probable Reserves			29,807				29,764				25,625				11,269				11,266				10,609				8,532				8,511				6,234
Total Proved Plus Probable Reserves			109,405				109,231				94,601				27,200				27,190				25,106				27,792				27,686				20,286

		Natural Gas												Coal Bed Methane												Total Oil Equivalent Basis(3)
																																		Net
										Net																Company Interest								Interest
		Company Interest				Gross Interest				Interest				Company Interest				Gross Interest				Net Interest				(Mboe)				Gross Interest				(Mboe)
Reserves Category		(MMcf)				(MMcf)				(MMcf)				(MMcf)				(MMcf)				(MMcf)				(3)				(Mboe) (3)				(3)
Proved Reserves
Proved Developed Producing			413,139				410,444				361,187				20,546				19,464				19,336				166,188				165,345				143,603
Proved Developed Non-Producing			16,666				16,528				13,505				—				—				—				4,748				4,723				3,752
Proved Undeveloped			11,896				11,894				10,538				12,780				12,731				10,810				23,025				23,008				19,400
Total Proved Reserves			441,701				438,866				385,230				33,326				32,195				30,146				193,960				193,077				166,755
Probable Reserves			167,893				167,103				145,333				10,395				10,160				9,484				79,323				79,085				68,271
Total Proved Plus Probable Reserves			609,594				605,970				530,563				43,720				42,355				39,630				273,283				272,162				235,025