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

For the fiscal year ended: December 31, 2006

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		(I.R.S. Employer
Classification Code Number)		Identification Number)

Suite 2900, 240 — 4^th Avenue S.W.
Calgary, Alberta Canada T2P 4H4
(403) 233-0224
(Address and telephone number of Registrant’s principal executive offices)

CT Corporation System
111-8^th Avenue, New York, New York 10011
(212) 894-8940

(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 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

(Title of Class)

(Title of Class)

     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 244,005,105 Trust Units, of no par value, outstanding as of December 31, 2006.

     Indicate by check mark whether the Registrant filing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934 (the “Exchange Act”). If “Yes” is marked, please indicate the filing number assigned to the Registrant in connection with such Rule.

Yes   o          No   þ

     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

 

 

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, 2006.
B		Management’s Discussion and Analysis.
C		Consolidated Financial Statements of Pengrowth Energy Trust, including Management’s Report to Unitholders, the Auditors’ Report and note 23 thereof which includes a reconciliation of the Consolidated Financial Statements to United States generally accepted accounting principles.
D		Oil and Gas Producing Activities Prepared in Accordance with SFAS No. 69 — “Disclosures about Oil and Gas Producing Activities”.
E		Pengrowth Energy Trust Code of Business Conduct and Ethics dated December 2006.

CERTIFICATIONS AND DISCLOSURE REGARDING CONTROLS AND PROCEDURES

Certifications. See Exhibits 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, 2006, 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 “Disclosure Controls and Procedures” contained in the Registrant’s Management’s Discussion and Analysis for the fiscal year ended December 31, 2006, 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 Management’s Discussion and Analysis for the fiscal year ended December 31, 2006, 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, 2006, 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, Kirby L. Hedrick, 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 code of ethics, principal accountant fees and services, pre-approval policies and procedures and off-balance sheet arrangements, is included on pages 81 through 82 and pages 97 through 98 of the Annual Information Form contained in Appendix A. Disclosures regarding the Registrant’s contractual obligations is included on page 83 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.

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.

APPENDIX A

PENGROWTH ENERGY TRUST ANNUAL INFORMATION FORM FOR THE YEAR
ENDED DECEMBER 31, 2006

PENGROWTH ENERGY TRUST

ANNUAL INFORMATION FORM

For the year ended December 31, 2006

March 30, 2007

TABLE OF CONTENTS

GLOSSARY OF TERMS AND ABBREVIATIONS			1
Corporate			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
The Trust’s Subsidiaries			7
The Corporation’s Subsidiaries			8
The Manager			8
Intercorporate Relationships			10
Business Strategy and Strengths			10
Historical Developments			12
Recent Acquisitions, Financings and Developments			14
Trends			17
PENGROWTH MANAGEMENT LIMITED			18
Business			18
Management Agreement			18
Management Fee			20
Management Agreement Second Term			20
PENGROWTH — OPERATIONAL INFORMATION			21
Principle Properties			21
Statement of Oil and Gas Reserves and Reserves Data			29
Additional Information Relating to Reserves Data			42
Future Development Costs			43
Finding, Development and Acquisition Costs			44
Other Oil and Gas Information			47
Replacement of Properties			53
Borrowing			53
TRUST UNITS			53
The Trust Indenture			53
The Trustee			54
Stock Exchange Listings			54
Ownership Restrictions			54
Redemption Right			54
Conversion Rights			55
Voting at Meetings of Unitholders			55
Voting at Meetings of Corporation			55
Termination of the Trust			55
Unitholder Limited Liability			56
THE ROYALTY INDENTURE			56
Royalty Units			56
The Royalty			56
The Trustee			57
EXCHANGEABLE SHARES			58
DISTRIBUTIONS			59
TRUST TAXATION			59

CANADIAN FEDERAL INCOME TAX CONSIDERATIONS			60
Status of the Trust			61
Taxation of the Trust			62
Taxation of Unitholders Resident in Canada			62
Taxation of Unitholders who are Non-Residents of Canada (“Non-Resident Unitholders”)			62
UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS			64
Classification of Pengrowth Energy Trust as a Partnership			64
Possible Classification as a Corporation; PFIC Rules			65
Consequences of Possible PFIC Classification			65
Tax Consequences of Trust Unit Ownership			66
Tax Treatment of Trust Operations			68
Disposition of Trust Units			69
Disposition of Trust Units by Redemption			71
Uniformity of Trust Units			71
Tax-Exempt Organizations			71
Administrative Matters			72
Reportable Transactions			72
Foreign Partnership Reporting			73
INDUSTRY CONDITIONS			73
Government Regulation			73
Pricing and Marketing — Oil			73
Pricing and Marketing — Natural Gas			73
Pricing and Marketing — Natural Gas Liquids			74
Environmental Regulation			75
MARKET FOR SECURITIES			76
DIRECTORS AND OFFICERS			77
Directors and Officers of Pengrowth Management Limited			77
Principal Holders of Shares of Pengrowth Management			78
Directors and Officers of the Corporation			78
Corporate Cease Trade Orders or Bankruptcies			80
Personal Bankruptcies			80
Penalties or Sanctions			80
AUDIT COMMITTEE			80
Principal Accountant Fees and Services			81
Pre-approval Policies and Procedures			82
RISK FACTORS			82
CONFLICTS OF INTEREST			95
LEGAL PROCEEDINGS			96
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS			96
INTERESTS OF EXPERTS			97
AUDITORS, TRANSFER AGENT AND REGISTRAR			97
MATERIAL CONTRACTS			97
CODE OF ETHICS			97
OFF-BALANCE SHEET ARRANGEMENTS			98
DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NEW YORK STOCK EXCHANGE			98
ADDITIONAL INFORMATION			99

Unless otherwise indicated, all of the information provided in this Annual Information Form is as at December 31, 2006.

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;
	•		Class A Trust Units refers to the class A trust units of the Trust created and issued pursuant to the Trust Indenture;
	•		Class B Trust Units refers to the class B trust units of the Trust issued and outstanding prior to the Consolidation;
	•		Common Shares refers to the common shares in the capital of the Corporation;
	•		Computershare refers to Computershare Trust Company of Canada;
	•		Consolidation has the meaning ascribed thereto under “Recent Acquisitions, Financings and Developments — Trust Unit Consolidation”;
	•		Corporation refers to Pengrowth Corporation, the administrator of the Trust;
	•		Manager refers to Pengrowth Management Limited, the manager of the Trust and the Corporation;
	•		October 31 Proposals has the meaning ascribed thereto under “Canadian Federal Income Tax Considerations”;
	•		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 July 27, 2006;
	•		Royalty Unitholder refers to holders of Royalty Units;
	•		Royalty Units refers to the royalty units of the Corporation created and issued pursuant to the Royalty Indenture;
	•		Trust refers to Pengrowth Energy Trust;
	•		Trust Indenture refers to the amended and restated trust indenture of the Trust, dated July 27, 2006;
	•		Trust Units refers to the Trust Units of the Trust created and issued pursuant to the Trust Indenture;
	•		Unitholders refers to holders of Trust Units and Class A Trust Units.

Engineering

	•		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 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 producing and non-producing;
	•		GLJ refers to GLJ Petroleum Consultants Ltd., independent petroleum consultants, Calgary, Alberta;
	•		GLJ Reports refers to the reports prepared by GLJ, with respect to Pengrowth’s properties, dated February 1, 2007, and with respect to the CP Properties, dated March 5, 2007, each having an effective date of December 31, 2006;
	•		Gross with respect to production and reserves refers to the total production and reserves attributable to a property before the deduction of royalties and with respect to land and wells refers to the total number of acres or wells, as the case may be, in which Pengrowth has a working interest or a royalty interest;
	•		Net refers to Pengrowth’s working interest share of production or reserves, as the case may be, after the deduction of royalties, and, with respect to land and wells, refers to Pengrowth’s working interest share therein;
	•		Pengrowth Company Interest is equal to Pengrowth Gross Interest plus Pengrowth Royalty Interest. That is, the working interest share of production or reserves prior to the deduction of royalties plus the interest in production made from gross production or reserves at the wellhead;
	•		Pengrowth Gross Interest refers to Pengrowth’s working interest share of reserves prior to the deduction of royalties. Pengrowth Royalty Interest reserves are not included in the Pengrowth Gross Interest reserves;
	•		Pengrowth Net Interest refers to Pengrowth’s working interest share of production or reserves, as the case may be, after the deduction of royalties and including Pengrowth Royalty Interest reserves, and, with respect to land and wells, refers to Pengrowth’s working interest share therein;
	•		Pengrowth 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;
	•		Pengrowth Total Proved Plus Probable Reserves means Pengrowth Company Interest share of the Total Proved Plus Probable Reserves;

	•		Probable Reserves refers to those additional reserves that are less likely 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;
	•		Reserve Life Index refers to the number of years determined by dividing the aggregate of the estimated reserves of a property from the GLJ Reports by the estimated production per year from such property using estimated production associated with the reserves from the GLJ Report for the year 2007 as a reference;
	•		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);
	•		Total Proved Plus Probable Reserves means the aggregate of Proved Reserves and Probable Reserves before the deduction of royalties;
	•		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) 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;
	•		°API refers to an indication of the specific gravity of crude oil measured on the API gravity scale;
	•		bbl, bbls, mbbls, and mmbbls refers to barrel, barrels, thousands of barrels and millions 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;
	•		CBM refers to coal bed methane;
	•		$M and $MM refers to thousands of dollars and millions of dollars, respectively;
	•		mmBtu and mmBtupd refers to million British thermal units and million British thermal units per day respectively;
	•		mcf, mmcf, bcf and tcf refers to thousands of cubic feet, millions of cubic feet, billions of cubic feet and trillions of cubic feet, respectively;
	•		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;
	•		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
cubic metre		cubic feet		35.494
bbls		cubic metre		0.159
cubic metre		bbls		6.290
feet		metre		0.305
metre		feet		3.281
miles		kilometre		1.609
kilometre		miles		0.621
acres		hectares		0.405
hectares		acres		2.471

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

PRESENTATION OF OUR FINANCIAL INFORMATION

Financial information in this Annual Information Form has been prepared in accordance with generally accepted accounting principles (“GAAP”) in Canada. Canadian GAAP differs in some significant respects from U.S. GAAP 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 23 to our audited annual consolidated financial statements for the year ended December 31, 2006, which are available on the Canadian System for Electronic Document Analysis and Retrieval “SEDAR” website at www.sedar.com and in our Form 40-F which is available through EDGAR at the United States Securities and Exchange Commission’s (the “SEC”) website at www.sec.gov.

PRESENTATION OF OUR RESERVE INFORMATION

The SEC generally permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves after the deduction of royalties and interests of others which are those reserves that a company has demonstrated by actual production or conclusive formation tests to be economically producible under existing economic and operating conditions. National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) permits oil and gas issuers, in their filings with Canadian securities regulators, to disclose not only Proved Reserves but also Probable Reserves, and to disclose reserves and production on a gross basis before deducting royalties. Probable Reserves are of a higher risk and are less likely to be accurately estimated or recovered than Proved 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 and in the documents incorporated by reference reserves designated as “probable”. If this Annual Information Form was required to be prepared in accordance with U.S. disclosure requirements, the SEC’s guidelines would prohibit reserves in these categories from being included. Moreover, in accordance with Canadian practice, we have determined and disclosed estimated future net cash flow from our reserves using both escalated and constant prices and costs; for the constant prices and costs case, prices and costs in effect as of December 31, 2006 were held constant for the economic life of the reserves. The SEC does not permit the disclosure of estimated future net cash flow from reserves based on escalating prices and costs and generally requires that prices and costs be held constant at levels in effect at the date of the reserve report. 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 companies in the United States”. Additional information prepared in accordance with United States Statement of Financial Accounting Standards No. 69 “Disclosures About Oil and Gas Producing Activities” relating to our oil and gas reserves is set forth in our 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, statements with respect to: benefits and synergies resulting from Pengrowth’s corporate and asset acquisitions during 2006, business strategy and strengths, goals, focus and the effects thereof, acquisition criteria, capital expenditures, reserves, reserve life indices, estimated production, production additions from Pengrowth’s 2007 development program, the impact on production of divestitures in 2007, remaining producing reserves lives, operating expenses, 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 abandonment and reclamation costs, government

royalty rates and expiring acreage. Statements relating to “reserves” are deemed to be 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 Pengrowth’s current beliefs as well as assumptions made by, and information currently available to Pengrowth, 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 Pengrowth, 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 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; Pengrowth’s 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; compliance with environmental laws and regulations; changes in tax laws; the failure to qualify as a mutual fund trust; and Pengrowth’s ability to access external sources of debt and equity capital. Further information regarding these factors may be found under the heading “Business Risks” in our Management’s Discussion and Analysis for the year ended December 31, 2006, in Pengrowth’s most recent consolidated financial statements, management information circular, quarterly reports, material change reports and news releases. Copies of Pengrowth’s Canadian public filings are available on SEDAR at www.sedar.com. Pengrowth’s U.S. public filings, including Pengrowth’s most recent annual report on Form 40-F as supplemented by its filings of Form 6-K, are available at www.sec.com and under “Risk Factors” herein.

Pengrowth cautions 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 Annual Information Form and Pengrowth does not undertake any obligation to up-date 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

Pengrowth Energy Trust is an oil and gas royalty trust that was created under the laws of the Province of Alberta on December 2, 1988. The purpose of the Trust is to purchase and hold Royalty Units and other securities issued by the Corporation, its majority 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 Trust and the Corporation are managed by the Manager.

Pengrowth’s head and registered offices are located at 2900, 240 — 4th Avenue S.W., Calgary, AB T2P 4H4.

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 who are the beneficiaries of the Trust. Each Trust Unit and Class A Trust Unit represents a fractional undivided beneficial interest in the Trust. Unitholders are entitled to receive monthly distributions in respect of the royalty (“Royalty”) the Corporation pays to the holders of the Royalty Units it has issued, and in respect of investments that are held directly by the Trust.

The Trust presently holds 90.9% of the outstanding Common Shares and in excess of 99.9% of the Royalty Units issued by the Corporation. In addition, the Trust holds other permitted investments, including oil and gas processing facilities and cash. 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 distributable cash of 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 has 1,100 Common Shares outstanding, 1,000 of which are owned by the Trust and 100 of which are owned by the Manager.

The Corporation acquires, owns and operates working interests and royalty interests in oil and natural gas properties. The Corporation has issued Royalty Units which entitle the holders thereof to receive a 99% share of the “royalty income” related to the oil and natural gas interests of the Corporation.

The authorized capital of the Corporation includes exchangeable shares which will have economic and voting rights substantially equivalent to the Trust Units of the Trust and which will be exchangeable, on certain conditions, for Trust Units. Holders of exchangeable shares will not receive dividends or distributions from the Trust, but will receive additional exchangeable shares in lieu of distributions. These additional exchangeable shares would be distributed by way of a stock split. To facilitate voting rights for the exchangeable shares, a special voting unit of the Trust has been authorized which will be entitled at any meeting of Unitholders to a number of votes equal to the number of outstanding exchangeable shares (not including exchangeable shares held by the Trust or its subsidiaries). There are presently no issued or outstanding exchangeable shares.

The Trust’s Subsidiaries

In addition to its interest in the Corporation, the Trust owns all of the issued and outstanding shares of Esprit Exploration Ltd. The Trust receives interest on the principal amount of Esprit Exploration Ltd.’s unsecured,

subordinated promissory notes and payments from the net profit interest granted to the Trust by Esprit Exploration Ltd. The Corporation, Esprit Energy Trust and Esprit Exploration Ltd. and all its subsidiaries entered into an Agency Agreement dated October 2, 2006 whereby the Corporation would provide certain services to Esprit Energy Trust and Esprit Exploration Ltd. and all its subsidiaries. Services generally include, but are not limited to, the provision of all operating, financial, strategic, legal, regulatory, human resource, technology, record keeping, record management and general and administrative services.

Esprit Exploration Ltd. was acquired in connection with the strategic business combination with Esprit Energy Trust on October 2, 2006 (the “Esprit Merger”). See “Recent Acquisitions, Financings and Developments — Esprit Merger”. Esprit Exploration Ltd. holds 100% of the issued and outstanding shares of Canadian 88 Energy Resources Corporation. Each of Esprit Exploration Ltd. and Canadian 88 Energy Resources Corporation are created under the laws of the Province of Alberta.

The Corporation’s Subsidiaries

The Corporation owns all of the issued and outstanding shares of Stellar Resources Limited, which holds a 0.01% partnership interest in each of Pengrowth Heavy Oil Partnership, Pengrowth Energy Partnership and Crispin Energy Partnership and acts as the general partner of each of the partnerships. The remaining 99.99% partnership interests in each of the partnerships are held by the Corporation. Pengrowth Heavy Oil Partnership and Pengrowth Energy Partnership were acquired in connection with the acquisition of certain properties from Murphy Oil Calgary Ltd. in 2004. Crispin Energy Partnership was acquired during 2005 in connection with the acquisition of Crispin Energy Inc. Each of Stellar Resources Limited, Pengrowth Heavy Oil Partnership, Pengrowth Energy Partnership and Crispin Energy Partnership are created under the laws of the Province of Alberta.

The Corporation owns all of the issued and outstanding shares of 1268071 Alberta Ltd., which in turn holds 100% of the issued and outstanding shares of 3174792 Nova Scotia Company. 3174792 Nova Scotia Company holds a 99.9% partnership interest in the Carson Creek Operating Partnership and all of the issued and outstanding shares of 3174793 Nova Scotia Company. 3174793 Nova Scotia Company holds the remaining 0.1% interest in the Carson Creek Operating Partnership. 3174792 Nova Scotia Company, 3174793 Nova Scotia Company and the Carson Creek Operating Partnership were acquired in connection with the acquisition of certain properties from ExxonMobil Canada Energy on September 28, 2006 (the “Carson Creek Acquisition”). See “Recent Acquisitions, Financings and Developments — Carson Creek Acquisition”. Each of 1268071 Alberta Ltd. and Carson Creek Operating Partnership are created under the laws of the Province of Alberta. Each of 3174793 Nova Scotia Company and 3174792 Nova Scotia Company are created under the laws of the Province of Nova Scotia.

The Corporation owns all of the issued and outstanding shares of 1275708 Alberta Ltd., which in turn holds 100% of the issued and outstanding shares of 1265707 Alberta ULC, 1265706 Alberta ULC, 1265704 Alberta Ltd. and 1265702 Alberta ULC. 1265707 Alberta ULC holds a 99.99% partnership interest in 706-707 Partnership. 1265706 Alberta ULC holds the remaining 0.01% partnership interest in 706-707 Partnership. 1265702 Alberta ULC holds 100% of the issued and outstanding shares of 1301253 Alberta Ltd. and a 99.99% partnership interest in 702 Partnership. 1301253 Alberta Ltd. holds the remaining 0.01% partnership interest in the 702 Partnership. Each of 1265702 Alberta ULC, 1265704 Alberta Ltd., 1265706 Alberta ULC and 1265707 Alberta ULC and 706-707 Partnership were acquired in connection with the acquisition of certain properties (the “CP Properties”) from ConocoPhillips Canada on January 22, 2007 (the “CP Acquisition”). See “Recent Acquisitions, Financings and Developments — CP Acquisition”.

The Manager

The Manager was created under the laws of the Province of Alberta on December 16, 1982.

The principal business of the Manager is that of a specialty fund manager. The Manager currently provides advisory, management, and administrative services to the Trust and the Corporation. The Manager also attends to the acquisition, development, operation and disposition of oil and natural gas properties and other related assets on behalf of the Corporation.

James S. Kinnear, President and a director of the Manager and Chairman, President, Chief Executive Officer and a director of the Corporation, owns, directly or indirectly, all of the issued and outstanding voting securities of the Manager. For a more comprehensive description of the Manager, see “Pengrowth Management Limited”.

Intercorporate Relationships

The following diagram illustrates Pengrowth’s organizational structure as at March 30, 2007:

Business Strategy and Strengths

Our goal is to maximize cash distributions on a per Trust Unit basis to our Unitholders while enhancing the value of our Trust Units. We focus on making accretive acquisitions, adding reserves and production through

development drilling, and maximizing the value of our mature property base by effectively producing our properties, which includes the use of new development technologies, such as tertiary recovery operations, and implementing other operational efficiencies. We engage in limited exploration for oil and natural gas.

Our ability to pay out distributions while enhancing Unitholder value over time is dependent upon effective operations and investments, and our ability to make acquisitions which yield returns that exceed our cost of capital. We evaluate acquisition opportunities based upon the following acquisition criteria:

Financial

	•		Acquisitions should be accretive on a per Trust Unit basis based upon current economics and forecast parameters.
	•		The undiscounted aggregate projected future net cash flow from the properties should exceed the aggregate purchase price of the properties and provide a reasonable rate of return.
	•		The oil and gas producing properties to be acquired should, in the context of the market, have an attractive rate of return.

Operational

•

Properties to be acquired should be high quality, relatively long life and proven producing properties. Pengrowth gives priority to properties with:

	•		low anticipated capital expenditures relative to the cash generation potential of the properties;
	•		relatively low operating costs or high netbacks;
	•		experienced, well regarded industry operators or where operatorship may be assumed by Pengrowth;
	•		favourable production history;
	•		upside potential through infill drilling, improved field operations and other development activities;
	•		potential synergies with our current properties and areas of our core expertise; and
	•		low environmental and site remediation risk.

Independent Verification

•

Each purchase of new properties will be based on an independent engineering report except for properties where the purchase price is less than $5 million.

Our structure, tax effectiveness and cost of capital allow us to bid competitively for oil and natural gas properties relative to taxable corporations and other taxable entities. However, the tax advantages that have historically been available to the Trust as a consequence of its status as a mutual fund trust may be adversely impacted by the October 31 Proposals. For a discussion of the consequences of the October 31 Proposals, see “Trust Taxation” “Canadian Federal Income Tax Considerations” and “Risk Factors — The October 31 Proposals, if enacted, are expected to materially and adversely affect the Trust, the Unitholders and the value of the Trust Units”. Opportunities to acquire oil and gas properties generally arise from sellers looking to

reduce indebtedness, seeking funds for higher risk exploration and development activities, exiting the business, or fulfilling other strategic objectives.

Historical Developments

Pengrowth’s first acquisition, in December of 1988, was the purchase of a 2.6507 percent working interest in Dunvegan Gas Unit No. 1 located near Fairview in the Peace River Arch area of Alberta. Pengrowth financed the acquisition by issuing 1,250,000 Royalty Units at a price of $10.00 per Royalty Unit, substantially all of which were issued to the Trust. The Trust issued 1,243,500 Trust Units to the public at a price of $10.00 per Trust Unit for gross proceeds of $12,435,000 which were used to pay for the Royalty Units. An additional 56,500 Royalty Units were also issued in the public offering. Of these additional Royalty Units, 14,952 were outstanding as of December 31, 2006.

Commencing in 1991, the Manager adopted a plan, and established criteria, to build Unitholder value through accretive acquisitions and financings of those acquisitions. Thereafter Pengrowth completed a series of acquisitions that were financed through periodic issuances of Trust Units, rights offerings and bank indebtedness.

The Trust commenced a series of fully marketed equity offerings in 1994 to fund various property acquisitions. Since that time Pengrowth has continued a course of targeted asset and corporate acquisitions. The most significant purchases and financings are described below.

Effective July 1, 1997, the Corporation acquired a 98.11 percent working interest in the Judy Creek Beaverhill Lake Unit, a 94.58 percent working interest in the Judy Creek West Beaverhill Lake Unit and a 9.58 percent working interest in Swan Hills Unit No. 1 for a net purchase price of $496.1 million. In November 1997, the Corporation increased its working interest in the Judy Creek Beaverhill Lake Unit to 100 percent.

On October 15, 1997, the Trust completed an offering of 23,928,572 Trust Units on an installment receipt basis with $12.50 per Trust Unit paid on closing and the balance of $8.75 per Trust Unit due on or before October 15, 1998. Gross proceeds raised amounted to $508 million comprised of cash of $299 million and an installment receivable of $209 million. On April 15, 1998, the Corporation assumed operatorship of the Judy Creek units from Imperial Oil Resources Ltd. Effective October 15, 1998, the Trust acquired certain facilities interests related to operations in the Judy Creek and Swan Hills areas from the Corporation for consideration of $106 million. The Trust entered into an agreement to lease the facilities back to the Corporation.

On November 10, 2000, the Trust issued 8,165,000 Trust Units to raise gross proceeds of $155,135,000, which were applied to acquire interests in Goose River, House Mountain, Minnehik Buck Lake, Mitsue and Weyburn from Canadian Natural Resources Limited for cash consideration of $128 million and the transfer of certain properties.

On May 31, 2001, the Trust issued 10,895,000 Trust Units to raise gross proceeds of $225.5 million.

Effective June 15, 2001, the Corporation acquired a royalty representing substantially all of the beneficial interest in the natural gas and liquids production from an 8.4 percent working interest in the Sable Offshore Energy Project from Nova Scotia Resources (Ventures) Limited (“NSRVL”) for $265 million (net adjusted price of $228.4 million). On December 24, 2001, the Corporation acquired certain additional petroleum and natural gas rights and other assets from NSRVL for a gross purchase price of $27.5 million. On May 7, 2003, the Corporation acquired an 8.4 percent working interest in the four Sable production facilities downstream of Thebaud Central Platform from Sable co-venturers ExxonMobil Canada Properties, Shell Canada Resources Limited, Imperial Oil Resources Ltd. and Mosbacher Operating Company Ltd. for net consideration of approximately $57 million. In May 2003, Pengrowth entered into an agreement with Nova Scotia Resources Limited (“NSRL”) to purchase varying interests in eleven significant discovery licenses for $4.5 million plus a 10 percent net profit interest to NSRL. In December 2003, Pengrowth acquired from Emera Offshore

Incorporated (and its subsidiaries, associates and affiliates on a consolidated basis) their 8.4 percent working interest in the Sable offshore production platforms facilities for $65 million. As a result of the foregoing transactions, the Corporation holds an undivided 8.4 percent working interest in Sable Offshore Energy Project.

On June 4, 2002, the Trust issued 8,000,000 Trust Units, including 2,000,000 Trust Units issued upon exercise of an underwriter’s option, at a price of $15.40 per Trust Unit for total gross proceeds of $123.2 million.

On October 1, 2002, with an effective date of July 1, 2002, the Corporation acquired certain properties located in northeast British Columbia from Calpine Natural Gas Partnership for net consideration after adjustments of $352 million.

In November, 2002, the Trust completed a cross-border equity offering in Canada and the United States of 20,125,000 Trust Units, including 2,625,000 Trust Units issued upon exercise of an underwriter’s option, at a price of $14.00 per Trust Unit (U.S. $8.93 per Trust Unit) for gross proceeds of approximately $281.8 million.

On April 23, 2003, Pengrowth completed a U.S. $200 million private placement of senior unsecured notes to a group of U.S. investors (the “U.S. Senior Notes”). The notes were offered in two tranches: U.S. $150 million at 4.93 percent due April 23, 2010 and U.S. $50 million at 5.47 percent due April 23, 2013. Interest on the notes is payable semi-annually.

On March 23, 2004, the Trust completed an equity offering of 10,900,000 Trust Units, including 2,700,000 Trust Units issued upon exercise of an underwriters’ option, at a price of $18.40 per Trust Unit for gross proceeds of approximately $200.5 million.

On May 31, 2004 the Corporation acquired certain properties from Murphy Oil Corporation for $551 million. The properties represent a diverse group of assets within western Canada, encompassing interests in the West Central Alberta and Peace River areas (including interests in the McLeod and Deep Basin areas); Southern Alberta (including interests in the Countess, Princess and Twining/Three Hills areas); and heavy oil (including interests in the Lindbergh, Tangleflags and Bodo/Cactus areas). The properties also include 219,000 acres of undeveloped land.

On July 27, 2004 Pengrowth implemented a reclassification of its Trust Units whereby the existing outstanding Trust Units were reclassified into Class B Trust Units and the Class B Trust Units held by non-residents of Canada were converted into Class A Trust Units (with the exception of Trust Units held by holders who did not provide a residency declaration to Computershare which remained unchanged pending receipt of a suitable residency declaration).

On August 12, 2004 Pengrowth acquired an additional 34.35 percent working interest in Pengrowth operated Kaybob Notikewin Gas Unit, adding approximately 2 mmboe of proved plus probable reserves for $20 million before adjustments. The acquisition increased Pengrowth’s working interest in the unit to 99 percent.

On December 30, 2004, the Trust completed an equity offering of 15,985,000 Class B Trust Units, including 5,285,000 Class B Trust Units issued upon exercise of an underwriters’ option and an over-allotment option, at a price of $18.70 per Class B Trust Unit for gross proceeds of $298.9 million.

On February 28, 2005, Pengrowth closed the acquisition of an additional 11.89 percent working interest in Swan Hills Unit No. 1 increasing Pengrowth’s total working interest in the unit to 22.34 percent. The purchase price was $87 million, after adjustments from the October 1, 2004 effective date to the closing date.

On April 29, 2005, pursuant to a Plan of Arrangement under the Business Corporations Act (Alberta), Pengrowth completed the acquisition of Crispin Energy Inc. which held interests in oil and natural gas assets

including CBM assets mainly in Alberta. Pengrowth issued 3,538,581 Class B Trust Units and 686,732 Class A Trust Units valued at $88 million in exchange for all outstanding shares of Crispin Energy Inc.

On December 1, 2005, Pengrowth completed a £50 million private placement of senior unsecured 10 year notes with a group of U.K. based investors (the “U.K. Senior Notes”). In a related transaction, Pengrowth entered into a series of currency swaps to hedge the foreign exchange risk and fixed the effective coupon rate of the notes at 5.49 percent.

Since the formation of Pengrowth in 1988, Pengrowth has completed a total of 20 public equity financings for gross proceeds of approximately $3.3 billion.

For acquisition, financings and other developments that occurred during 2006, See “Recent Acquisitions, Financings and Developments”.

Recent Acquisitions, Financings and Developments

Monterey Transaction

On January 12, 2006, Pengrowth announced certain transactions with Monterey under which Pengrowth sold approximately 1,000 boepd of production for $22 million of cash and 8 million shares in Monterey and farmed out acreage in northeast British Columbia under terms that include our ability to participate in exploration activities in conjunction with Monterey. Pengrowth holds approximately 34 percent of the common shares of Monterey.

Monterey has agreed to drill a minimum of 20 exploration wells and pay 100 percent of the costs to earn a 75 percent interest in the farmed out lands.

Dunvegan Acquisition

On March 30, 2006, Pengrowth closed the acquisition of an additional working interest in the Dunvegan Unit No. 1 as well as some minor oil and gas properties in central Alberta for approximately $48 million. This increased Pengrowth’s interest to 10.4% at the Dunvegan Gas Unit.

Borrowing

On June 16, 2006, Pengrowth entered into a new $500 million extendible revolving term credit facility syndicated among eight financial institutions (the “Credit Facility”). The Credit Facility is unsecured, covenant based and has a three year term maturing June 16, 2009. Pengrowth has 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. Various borrowing options are available under the Credit Facility including prime rate based advances and bankers’ acceptance loans. The Credit Facility carries floating interest rates that are expected to range between 0.65 percent and 1.15 percent over bankers’ acceptance rates depending on Pengrowth’s consolidated ratio of senior debt to earnings before interest, taxes and non-cash items. On October 2, 2006, in conjunction with the closing of the Esprit Merger, Pengrowth and the lenders agreed to increase the Credit Facility to $950 million and add two new financial institutions into the syndicate. No other material changes were made to the Credit Facility. In addition, Pengrowth has a $35 million demand operating line of credit for working capital purposes. The facilities were reduced by drawings of $257 million and by outstanding letters of credit in the amount of approximately $17.6 million at December 31, 2006.

On January 22, 2007, in conjunction with the closing of the CP Acquisition, Pengrowth entered into a new $600 million bridge credit facility syndicated among ten financial institutions (the “Bridge Credit Facility”). The Bridge Credit Facility is unsecured, covenant based and has a one year term. Various borrowing options are available under the Bridge Credit Facility including prime rate based advances and bankers’ acceptance

loans. The Bridge Credit Facility carries floating interest rates that are expected to range between 0.65 percent and 1.15 percent over bankers’ acceptance rates, depending on Pengrowth’s consolidated ratio of senior debt to earnings before interest, taxes and non-cash items. Certain net proceeds from any future asset dispositions, equity offerings or debt issuances are required to repay the amount borrowed under the Bridge Credit Facility.

Trust Unit Consolidation

On July 27, 2006, the Trust completed the consolidation (the “Consolidation”) of its then outstanding Class A Trust Units, Class B Trust Units and trust units remaining in the form in existence prior to the reclassification which occurred on July 27, 2004 (“Prior Trust Units”) into a single class of trust units, referred to herein as “Trust Units”. The Consolidation was effected through amendments to the Trust Indenture. The principal amendments to the Trust Indenture were as follows: (a) the residency restrictions attached to the Class B Trust Units were removed; (b) the Class B Trust Units were renamed as Trust Units; (c) the Prior Trust Units were converted to Trust Units; and (d) the Class A Trust Units were converted to Trust Units, other than the Class A Trust Units for which an election and declaration of Canadian residency was provided by the holder thereof. Class A Trust Units for which an election and declaration of Canadian residency was provided remain outstanding but the terms thereof have been amended to prohibit the transfer of such Class A Trust Units. Such outstanding Class A Trust Units may be converted to Trust Units or redeemed for cash, subject to the terms of the Trust Indenture, at any time and at the discretion of the holder thereof. See “Trust Units — Redemption Right” and “Trust Units — Conversion Rights”. As a result, the Class A Trust Units were de-listed from the TSX, the renamed Class B Trust Units remained listed and posted for trading on the TSX as Trust Units with a new symbol “PGF.UN”, and the Trust Units were substitutionally listed in place of the Class A Trust Units on the NYSE under the symbol “PGH”.

Carson Creek Acquisition

On September 28, 2006, Pengrowth completed the acquisition from ExxonMobil Canada Energy all of the issued and outstanding shares of a company which had interests in oil and natural gas assets (the “Carson Creek Assets”) in the Carson Creek area of Alberta and the adjacent Carson Creek Gas Plant for $475 million, prior to adjustments. The Carson Creek Assets consisted of an 87.5 percent operated working interest in Carson Creek North Unit No. 1, a 95.1 percent operated working interest in both Carson Creek Unit No. 1 and the Carson Creek Gas Plant and a firm pipeline transportation contract. The acquisition of the Carson Creek Assets is consistent with Pengrowth’s long term strategy of acquiring working interests in large original oil-in-place reservoirs offering the potential for incremental recovery through the application of improved technology and recovery techniques. The acquisition provided the addition of approximately 19 mmboe of Total Proved Plus Probable Reserves (Pengrowth Company Interest based on GLJ forecast prices and costs). This acquisition was funded by a portion of Pengrowth’s September 28, 2006 equity offering of 23,310,000 Trust Units at a price of $22.60 per Trust Unit for total gross proceeds of $526,806,000.

Esprit Merger

On October 2, 2006 Pengrowth completed the Esprit Merger. Under the terms of the Esprit Merger, each Esprit trust unit was exchanged for 0.53 of a Trust Unit. As a result of the Esprit Merger, approximately 34,725,157 Trust Units were issued to holders of Esprit trust units. See the business acquisition report of the Trust, dated October 31, 2006 and available on SEDAR at www.sedar.com.

Pengrowth was able to successfully capitalize on the opportunity to acquire long life natural gas assets during a lower natural gas price environment and added approximately 60.7 million boe of proved plus probable oil and natural gas reserves and 250,000 net acres of undeveloped land to our asset base.

The Esprit assets include shallow gas and CBM potential, core areas of Pengrowth expertise, and development potential exists on many of Esprit’s core properties. Esprit’s net undeveloped land acreage position increased Pengrowth’s existing land base by approximately 60 percent, providing a source of internally generated

drilling opportunities supported by over 12,000 square kilometers of 2-D seismic and 4,000 square kilometers of 3-D seismic. Esprit’s inventory of 46 net sections of CBM potential in the Greater Olds area will also augment Pengrowth’s potential in the area.

Convertible Debentures

As a result of the Esprit Merger, Pengrowth assumed all of Esprit’s 6.5 percent convertible unsecured subordinated debentures (the “Esprit Debentures”). The Esprit Debentures were originally issued on July 28, 2005 for a $100 million principal amount with interest paid semi-annually in arrears on June 30 and December 31 of each year. At October 2, 2006, $95.8 million principal amount of Esprit Debentures was outstanding. Each $1,000 principal amount of Esprit Debentures is convertible at the option of the holder at any time into fully paid Trust Units at a conversion price of $25.54 per Trust Unit. The Esprit Debentures mature on December 31, 2010. After December 31, 2008, Pengrowth may elect to redeem all or a portion of the outstanding Esprit Debentures at a price of $1,050 per Esprit Debenture or $1,025 per Esprit Debenture after December 31, 2009.

Pursuant to a change of control provision in the Debenture Indenture, Pengrowth was required to make an offer to purchase all of the outstanding Esprit Debentures at a price equal to 101 percent of the principal amount, plus any accrued and unpaid interest. On December 12, 2006 Pengrowth redeemed a portion of the Esprit Debentures, pursuant to the change of control provision, for cash proceeds of $21.8 million (including accrued interest of $0.6 million and offer premium of $0.2 million).

CP Acquisition

On January 22, 2007 Pengrowth closed the acquisition of the CP Properties for a purchase price of $1.0375 billion, prior to adjustments. See the business acquisition report of the Trust, dated March 16, 2007, and available on SEDAR at www.sedar.com.

The CP Properties will provide Pengrowth with 65.1 million boe of Total Proved Plus Probable reserves (Pengrowth Company Interest based on GLJ forecast prices and costs) and are balanced evenly between natural gas and crude oil. The CP Properties provide a wide range of opportunities to add value through an increased commitment of capital for active development including potential production from new horizons, infill drilling, continued optimization of existing waterflood programs and new enhanced oil recovery programs. The acquisition also provides synergies in several of Pengrowth’s focus areas including our Judy Creek and Swan Hills focus area. The acquisition adds more than 375,000 net acres of undeveloped land and approximately 9,300 kilometers of proprietary 2-D seismic and interests in over 50 3-D seismic surveys.

The CP Properties are characterized as being high working interest and a majority are operated providing a strategic fit to Pengrowth’s existing asset base.

The CP Acquisition was funded through Pengrowth’s December 8, 2006 equity offering of 24,265,000 Trust Units at a price of $19.00 per Trust Unit for total gross proceeds of $461,035,000 and by borrowing $600,000,000 pursuant to the Bridge Credit Facility.

Subsequent to the CP Acquisition, we commenced an asset rationalization program, the intent of which is to dispose of certain non-core properties and to use the proceeds therefrom to repay outstanding indebtedness.

2007 Forecast Capital, Production and Operating Costs

On January 25, 2007, the Board of Directors approved Pengrowth’s 2007 capital expenditure program of up to $300 million. Pengrowth will continue to develop the Judy Creek miscible flood program through a combination of infill drilling and new horizontal injection wells. In northeast British Columbia, Pengrowth

will focus on new gas wells and further development of existing waterflood programs. Many drilling opportunities in both heavy oil and shallow gas in Southern Alberta are anticipated to be completed in 2007. The approved budget includes $25 million in leasehold improvements that relate to a new long-term lease of head office space.

Pengrowth expects to fund the 2007 capital expenditure program through a combination of undistributed cash from operations, unused credit facilities, distribution reinvestment program proceeds and proceeds from the exercise of rights and options.

The table below describes the forecasted capital, production and operating costs for 2007:

Planned Capital Expenditures		$ Millions				% of Total
Drilling and Completion Expenditures			198				66
Facilities and Maintenance			59				20
Land and Seismic			18				6
Office Building			25				8
Total			300				100
Average daily production volume (boepd)			83,000 -- 87,500	(1)
Operating costs per boe		$	13.00	(2)

Notes:

(1)		Includes anticipated divestitures with approximately 7,700 boepd of associated current production, expected to close in the first and second quarters of 2007 with anticipated proceeds of $300 million to $450 million, prior to any adjustments. There can be no assurance regarding the completion of such divestitures, the timing thereof, or the proceeds therefrom. The volume of current production divested may or may not exceed 7,700 boepd. The 2007 estimate excludes potential additions through acquisitions other than the CP Acquisition.
(2)		Assuming production targets for 2007 are achieved.

Trends

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

Commodity prices, while volatile, are at high levels compared with historical averages over the last decade. These relatively high prices have been offset by higher costs. Although, the expectation is that profitability will remain, the volatility and recent decline from recent highs in commodity prices do affect cash flow.

In addition, increases or decreases in the Canadian dollar relative to the US dollar also result in decreases or increases, respectively, in cash flow as the main markets for Pengrowth’s oil and gas are either directly priced in US dollars or based on pricing linked to US dollars.

On October 31, 2006, the federal Minister of Finance announced the October 31 Proposals, which, if enacted, would change the manner in which certain flow-through entities, and the distributions from such entities, are taxed. See “Trust Taxation”, “Canadian Federal Income Tax Considerations ” and “Risk Factors — The October 31 Proposals, if enacted, are expected to materially and adversely affect the Trust, the Unitholders and the value of the Trust Units” in this Annual Information Form.

With the recent decline in commodity prices and, in particular, the decline in natural gas prices together with uncertainty and limits to growth arising from the October 31 Proposals, consolidation in the oil and gas trust sector is expected as some trusts struggle to deliver distributions and growth. Pengrowth is relatively well-

placed to take advantage of this environment due to Pengrowth’s size, reputation and ability to identify, complete and finance new acquisitions, its strong operations team and a combination of solid asset base and strong financial flexibility.

Greenhouse gas emission limitations are expected to impact the oil and gas business, including Pengrowth, sometime in the future. Both Federal and Provincial rules are expected in the next few years. As an example, the Alberta Government introduced legislation on March 8, 2007 to regulate greenhouse gas emissions. While the exact impact is unknown at this time, capital most likely will be needed and operating costs will increase to meet emission requirements. See “Industry Conditions — Environmental Regulation”.

For additional information regarding the Trust’s strategy in this business environment, see “Management’s Discussion and Analysis — Outlook” in the Trust’s Annual Report for the year ended December 31, 2006.

PENGROWTH MANAGEMENT LIMITED

Business

The principal business of the Manager is to provide advisory, management, and administrative services primarily to the Trust and the Corporation. The Manager also previously provided investment advisory and management services in relation to investments by several Canadian pension funds in the energy sector. These investments were subsequently acquired by the Corporation for Royalty Units and cash. The Manager utilizes its extensive experience and employs prudent oil and gas business practices to increase the value of the assets of the Corporation through effective acquisitions and dispositions and through effective operations. The Manager has focused upon high quality, long life proven producing properties located in Canada. The Manager will continue to focus upon acquisitions which are strategic and which add value to the Corporation and the Trust on a per Trust Unit basis.

Management Agreement

The Unitholders and the Royalty Unitholders approved an amended and restated management agreement among the Trust, the Corporation, the Manager and Computershare, as trustee (the “Management Agreement”) at the annual and special meetings held on June 17, 2003. The Management Agreement governs both the Trust and the Corporation. The Board of Directors negotiated the Management Agreement with the Manager to incentivize future performance and to avoid the upfront termination payments associated with internalizations of management.

Key elements of the Management Agreement are:

	•		two distinct 3-year terms with a declining fee structure in the second 3-year term;
	•		a base fee determined on a sliding scale:

•

in the first three-year contract term:

	•		2 percent of the first $200 million of Income; and
	•		1 percent of the balance of Income over $200 million; and

•

in the second three-year contract term:

	•		1.5 percent of the first $200 million of Income; and
	•		0.5 percent of the balance of Income over $200 million.

For these purposes, “Income” means the aggregate of net production revenue of the Corporation and any other income earned from permitted investments of the Trust (excluding interest on cash or near-cash deposits or similar investments).

	•		a performance based fee based on total returns received by Unitholders which essentially compensates the Manager for total annual returns which average in excess of 8 percent per annum over a 3-year period;
	•		a ceiling on total fees payable determined in reference to a percentage of the fees paid under the previous management agreement: 80 percent each year in the first three-year contract term and 60 percent each year in the second three-year contract term and subject to a further ceiling essentially equivalent to $12 million annually during the second three-year contract term;
	•		requirement for the Manager to pay certain expenses of the Corporation and the Trust of approximately $2 million per year;
	•		an annual minimum management fee of $3.6 million comprised of $1.6 million of management fees and $2.0 million of expenses;
	•		key man provisions in respect of James S. Kinnear, the President of the Manager;
	•		an annual bonus pool based on 10 percent of the Manager’s base fee and performance fee for employees of, and special consultants to, the Corporation; and
	•		an optional buyout of the Management Agreement at the election of the Board of Directors upon the expiry of the first three-year contract term with a termination payment of approximately 2/3 of the management fee paid during the first three-year contract term plus expenses of termination.

The responsibilities of the Manager under the Management Agreement include:

	•		reviewing and negotiating acquisitions for the Corporation and the Trust;
	•		providing written reports to the Board of Directors to keep the Corporation fully informed about the acquisition, exploration, development, operation and disposition of properties, the marketing of petroleum substances, risk management practices and forecasts as to market conditions;
	•		supervising the Corporation in connection with it acting as operator of certain of its properties;
	•		arranging for, and negotiating on behalf of, and in the name of, the Corporation all contracts with third parties for the proper management and operation of the properties of the Corporation;
	•		supervising, training and providing leadership to the employees and consultants of the Corporation and assisting in recruitment of key employees of the Corporation;
	•		arranging for professional services for the Corporation and the Trust;
	•		arranging for borrowings by the Corporation and equity issuances by the Trust; and

•

conducting general Unitholder services, including investor relations, maintaining regulatory compliance, providing information to Unitholders in respect of material changes in the business of the Corporation or the Trust and all other reports required by law, and calling, holding and distributing material in respect of meetings of Unitholders and Royalty Unitholders.

Despite the broad authority of the Manager, approval of the Board of Directors is required on decisions relating to any offerings, including the issuance of additional Trust Units, acquisitions in excess of $5 million, annual operating and capital expenditure budgets, the establishment of credit facilities, the determination of cash distributions paid to Unitholders, the compensation practices, specific compensation programs for certain key executives of the Corporation, the amendment of any of the constating documents of the Corporation or the Trust and the amount of the assumed expenses of the Manager which are a portion of the compensation of the Manager.

Management Fee

Management fees are calculated on a percentage of “net operating income” (oil and gas sales and other income, less royalties, operating costs, solvent amortization and reclamation funding.) The base fee has been reduced from a sliding scale between 3.5 percent and 2.5 percent, to the new rate of 1.5 percent on the first $200 million of net operating income and 0.5 percent on net operating income over $200 million. Acquisition fees were eliminated (effective July 1, 2003), and the Manager is eligible to receive a “performance fee” if certain performance criteria are met. The previous fee arrangements remain relevant however as there is a cap imposed on the fees, including the performance fee, limiting the aggregate of such fees to 80 percent of the fees that would otherwise have been paid under the old management agreement (inclusive of acquisition fees) for the first three years, and 60 percent for the second three years.

Bonus Pool

The Manager has established an annual bonus plan as an incentive to the officers, employees and special consultants of the Manager and the Corporation (excluding the President, James S. Kinnear). The annual bonus plan is carved out from the management fee paid to the Manager, and is calculated as 10 percent of the total fees, including the management fee and the performance fee, received by the Manager. Bonuses are paid from time to time to top performing individuals in accordance with criteria recommended by the Manager.

Management Agreement Second Term

Under the terms of the Management Agreement, the Corporation had the right to terminate the Management Agreement effective June 30, 2006 on payment to the Manager of a termination fee and certain other amounts. In the absence of such termination, the Management Agreement continues in effect for a final three year term ending June 30, 2009.

An Independent Committee of the Board of Directors of the Corporation was constituted for the purpose of considering a termination of the Management Agreement. The Independent Committee retained Scotia Capital Inc. as its financial advisor. After considering the anticipated effects to the Corporation and to the Unitholder value of both a termination of the Management Agreement and a continuation of the Management Agreement, the Independent Committee recommended to the full Board of Directors that the Management Agreement not be terminated at the end of the first term.

The Independent Committee based its recommendation on several factors, including:

•

The termination fee payable to the Manager on termination of the Management Agreement;

	•		The estimated cost of internal management, until June 30, 2009, in the event of a termination of the Management Agreement;
	•		The estimated maximum management fees that would be payable to the Manager over the final three years of the term of the Management Agreement;
	•		The advice of its financial advisor;
	•		The management fee ceiling applicable during the final three years of the Management Agreement, which will result in lower management fees in the second term of the Management Agreement ending June 30, 2009 as compared to the first term of the Management Agreement ended June 30, 2006; and
	•		The commitment by the Manager to certain key governance standards relating to the conduct of the affairs of the Trust and a continuing commitment to overall corporate governance practices (as such practices would apply to Pengrowth in an internalized management structure); and a further commitment to assist and work with the Board in establishing a plan for the orderly transition to a traditional corporate management structure at the end of the final term of the Management Agreement on June 30, 2009.

Based on the recommendation of the Independent Committee, the Board of Directors resolved not to terminate the Management Agreement at the end of the first term and has therefore resolved to continue the Management Agreement in accordance with its terms for a second three year term ending on June 30, 2009.

PENGROWTH — OPERATIONAL INFORMATION

As at December 31, 2006, the Corporation had 461 permanent employees. The Corporation has invested more than $5 billion in the energy sector primarily to purchase mature, proven producing oil and natural gas properties in Canada.

Principle Properties

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

Pengrowth obtained the GLJ Report dated February 1, 2007 in respect to the oil and gas properties of Pengrowth effective December 31, 2006. All reserves data presented under this sub-heading is based on the GLJ Report. Pengrowth’s producing properties as of December 31, 2006 are summarized in the following table:

Summary of Pengrowth Company Interest
at December 31, 2006⁽¹⁾
Forecast Prices and Costs

										Company Interest								2006 Actual Oil
		Remaining								Total Proved Plus				Value at 10%				Equivalent
		Reserve Life				Reserve Life Index				Probable Reserves				Discount				Production
Field		(Years)				(Years)				(mboe)				($M)				(boepd)
Judy Creek BHL Unit			44				11.4				34,279				558,895				9,613
Olds Gas Field Unit No. 1 (2)			47				18.3				22,270				217,850				786
Weyburn Unit			36				18.3				21,954				298,319				2,894
Swan Hills Unit No. 1			50				20.1				18,655				207,237				2,884
Carson Creek North BHL Unit No. 1 (2)			37				11.6				15,598				231,727				1,227
Sable Offshore Energy Project			9				4.1				13,080				292,062				6,428

										Company Interest								2006 Actual Oil
		Remaining				Reserve				Total Proved Plus				Value at 10%				Equivalent
		Reserve Life				Life Index				Probable Reserves				Discount				Production
		(Years)				(Years)				(mboe)				($M)				(boepd)
Judy Creek West BHL Unit			50				23.6				9,298				100,048				1,146
Monogram Gas Unit			38				10.9				7,769				127,039				2,017
Dunvegan Gas Unit No. 1			34				9.5				6,354				91,648				1,802
Olds Non-Unit (2)			38				8.6				6,305				103,547				680
Tangleflags North EOR			26				6.9				5,727				41,796				1,632
Quirk Creek			33				11.6				5,492				74,695				883
East Bodo			46				21.6				5,193				48,691				701
Twining			50				13.6				4,864				67,109				1,745
McLeod River			42				8.3				4,240				65,320				1,365
Twining CBM			36				9.8				4,149				53,916				133
Kaybob Notikewin Unit No. 1			40				13.5				4,146				49,557				875
Blackstone (2)			26				10.7				3,956				56,293				267
Oak			42				9.4				3,631				68,693				1,082
Princess			50				9.5				3,572				61,327				1,050
Tilley Milk River Unit			49				15.9				3,151				37,791				600
Enchant			48				14.6				2,986				39,229				610
Other (3)			50				8.0				91,105				1,540,583				22,401
Total			50				10.1				297,774				4,433,372				62,821

Notes:

(1)		The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation.
(2)		Acquired late in 2006. Production based on three months averaged over the year.
(3)		“Other” includes Pengrowth’s working and royalty interests in approximately 170 other properties.
(4)		Natural Gas has been converted to barrels of oil equivalent on the basis of six mcf of natural gas being equal to one boe.

Judy Creek Beaverhill Lake Unit and Judy Creek West Beaverhill Lake Unit

Pengrowth has a 100 percent working interest in both the Judy Creek Beaverhill Lake Unit (the “Judy Creek A Pool”) and the Judy Creek West Beaverhill Lake Unit (the “Judy Creek B Pool” and together with Judy Creek A Pool, “Judy Creek”). Judy Creek is located approximately 200 kilometers northwest of Edmonton in north-central Alberta and covers an area of approximately 155 square kilometers (60 sections). Judy Creek was discovered in 1959, placed on waterflood (secondary recovery) in 1962 and miscible flood (tertiary recovery) in 1985. To December 31, 2006, a total of 356 mmbbls have been produced from the Judy Creek A Pool. Remaining Pengrowth Company Interest Total Proved Plus Probable Reserves at December 31, 2006 are estimated at 34.3 mmboe. To December 31, 2006, a total of 115 mmbbls have been produced from the Judy Creek B Pool. Remaining Pengrowth Company Interest Total Proved Plus Probable Reserves at December 31, 2006 are estimated to be 9.3 mmboe. The remaining producing reserve life for the Judy Creek A Pool and Judy Creek B Pool is 44 and 50 years and the Reserve Life Index is 11.4 and 23.6 years, respectively. Pengrowth’s Company Interest production for Judy Creek averaged 10,759 boepd in 2006.

      Development Activity

In 2006, three new miscible patterns were initiated in Judy Creek A Pool with a total expected recovery of 540 mbbls. Two miscible flood patterns ended solvent injection in 2006. Seven infill wells were drilled and completed (four producers and three injectors). The average initial oil rate for the producing wells was 200 bblpd. The injector drills complete two new waterflood patterns and one miscible pattern which will commence injection in the second quarter of 2007.

Four new miscible patterns are currently being developed in Judy Creek A Pool with a total expected recovery of 660 mbbls. Two of the patterns will commence injection in the second quarter while the other two will

commence in the third quarter of 2007. Two of the patterns being developed will be horizontal injectors in the SW quadrant of the Judy Creek A Pool. Two more patterns will be developed and commence injection in the fourth quarter of 2007. The 2007 drilling program will involve two to five infill drills with a primary focus on creating new miscible patterns.

     CO₂ Pilot

Pengrowth has undertaken a CO₂ pilot project, the overall scope of which is to inject purchased CO₂ and acid gas from the Judy Creek Gas Conservation Plant. The CO₂ injection began in the first quarter of 2007 and acid gas injection is anticipated to commence in the second quarter of 2007. Increased hydrocarbon production is expected within the next six to eighteen months.

Olds Gas Unit No. 1

The Olds Gas Unit No. 1 is situated in a corridor that extends from just north of the town of Carstairs to the town of Olds, approximately 100 kilometers north of Calgary. Pengrowth operates, and has a 100% working interest in, the Olds Gas Unit No. 1, which produces from the Crossfield member of the Wabamun Group. At December 31, 2006, the remaining Pengrowth Company Interest Total Proved Plus Probable Reserves were 22.3 mmboe with a remaining reserve life of 47 years and a Reserve Life Index of 18.3 years. Production from the Olds Gas Unit No. 1 field averaged 3,118 boepd in the last quarter of 2006 following the Esprit Merger.

Pengrowth owns and operates the sour gas processing plant at Olds, which processes both Pengrowth’s production and third party volumes. Third party volumes represent approximately 30 percent of the total sales volumes processed.

     Development Activity

Installation of a Wabamun south field compressor facility is being evaluated, which would optimize existing production and enhance recovery or remaining reserves in place. If feasible, the compressor facility will likely be installed and operational by the first quarter of 2008. In addition, 2007 activity will include a new water disposal well conversion from an existing suspended wellbore with close proximity to the Olds Gas Plant, which will take place by the fourth quarter of 2007.

Olds Non-Unit

Within the Olds geographic area, Pengrowth has various working interests in numerous non-unit zones. These include the Pekisko, Ellerslie, Viking, Edmonton and Belly River formations. The Crossfield member is also considered non-unit where it is not located within the boundary of the Olds Gas Unit No. 1. At December 31, 2006 Pengrowth Company Interest Total Proved Plus Probable Reserves were 6.3 mmboe with a remaining reserve life of 38 years and a Reserve Life Index of 6.3 years. Olds Non-Unit production averaged 2,698 boepd in the last quarter of 2006 following the Esprit Merger.

     Development Activity

In 2006, Pengrowth drilled one exploratory Crossfield well north of Olds. Pengrowth executed a successful farm-in and Viking re-completion of an existing wellbore in late in 2006. The well flowed at an initial rate of 2,000 mcfpd in mid-February 2007. Additional Viking re-completions and new drills are being evaluated for completion in 2007. Five additional Viking well drills and re-completions and the drilling of one deeper new well is anticipated for 2007.

A three mile pipeline was installed in 2006 to improve production from an existing well that was limited by third party facilities. The pipeline re-directed production from the well to Pengrowth’s owned and operated Olds Gas Plant, and extended the Olds gathering system further north and west in the Garrington area. The net

incremental gain was over 600 mcfpd. Pengrowth also realizes significant savings in third party gathering and processing fees.

Weyburn Unit

Pengrowth holds a 9.76 percent working interest in the partner-operated Weyburn Unit in southeast Saskatchewan. Medium gravity oil is produced from the Midale carbonate reservoir under waterflood and a CO₂ miscible flood enhanced recovery program. At December 31, 2006, Pengrowth Company Interest Total Proved Plus Probable Reserves were 21.9 mmboe with a remaining reserve life of 36 years and a Reserve Life Index of 18.3 years. Pengrowth Company Interest production averaged 2,894 boepd in 2006.

     Development Activity

A total of 55 horizontal infill and re-entry wells were drilled in 2006, adding about 1,050 boepd to year end production. Of the 75 total CO₂ miscible flood patterns, 44 patterns have been developed. Current CO₂ supply is 125 mmcfpd.

Building on the success of the infill drilling programs over the last three years, an additional 45 wells are planned for 2007. The 2007 development program also includes two new CO₂ miscible flood patterns, four half-patterns and two pattern realignments. Higher production volumes have resulted in some infrastructure bottlenecks that are being addressed in 2006, most notably, 90,000 bblpd of water injection pumping capacity is being added early in 2007 and 100 mmcfpd of CO₂ recycle compression capacity will be added late in the year.

Swan Hills Unit No. 1

Pengrowth holds a 22.34 percent working interest in the partner-operated Swan Hills Unit No. 1 located near the Judy Creek field in north central Alberta. At December 31, 2006, Pengrowth Company Interest Total Proved Plus Probable Reserves were 18.7 mmboe with a remaining reserve life of 50 years and a Reserve Life Index of 20.1 years. Pengrowth Company Interest production averaged 2,882 boepd in 2006.

     Development Activity

In 2006 four new wells were drilled on 80 acre spacing in the northwest area of the Swan Hills Unit No. 1 adding about 285 boepd to year end production. In addition, five wells were recompleted/reactivated and ten wells were equipped with larger pumping systems collectively adding a further 115 boepd to year end production.

The Swan Hills Unit No. 1 continued injecting into three existing 80 acre hydrocarbon miscible flood patterns in 2006. Two new 80 acre patterns were developed and one new injection well was drilled. At year end, the new patterns had started injection.

Injection into the CO₂ miscible flood pilot project was terminated at mid-year after completing 11 injection cycles, which was 13.6 percent of the planned pore volume. Although production response was less than anticipated, the Swan Hills Unit No. 1 will continue to monitor the wells and to analyze the results through reservoir modeling.

The 2007 development plans include drilling four new 80 acre infill wells in the northwest area, developing a new 40 acre hydrocarbon miscible flood pattern that will include drilling five new wells, developing another two 80 acre hydrocarbon miscible patterns that will include drilling one new well and a variety of well recompletions, suspended well reactivations and artificial lift upgrades.

Carson Creek

Carson Creek is located 160 kilometers northwest of the city of Edmonton and is comprised of two high working interest Pengrowth operated units which cover approximately 187 square kilometers. Pengrowth has a 95.12% working interest in the Carson Creek Gas Unit. A lean gas cycling scheme was operational from 1962 to 1985 whereby the liquid rich gas was separated into liquid and lean gas, and the lean gas was reinjected. Gas reinjection now occurs during plant upset conditions. As of December 31, 2006, Pengrowth Company Interest Total Proved Plus Probable Reserves were 2.8 mmboe with a remaining reserve life of 10 years and a Reserve Life Index of 5.7 years.

Pengrowth has an 87.5% working interest in the Carson Creek North Unit. The Carson Creek North Unit was discovered in 1958 and the current waterflood was initiated in 1964. As of December 31, 2006, Pengrowth Company Interest Total Proved Plus Probable Reserves for the oil unit were 15.6 mmboe with a remaining life of 37 years and a Reserve Life Index of 11.6 years.

     Development Activity

Pengrowth’s 2007 activities will include shooting 136 square kilometers of 3D seismic over the Carson Creek North Unit acreage, reservoir characterization and simulation modeling, waterflood optimization, and wellsite compression work in the Carson Creek Gas Unit. From the interpretation of this technical work including the 3D seismic results, Pengrowth anticipates drilling two wells and up to six well recompletions in 2007.

Shallow gas opportunities are currently being exploited through a farmout arrangement, which was entered into prior to Pengrowth acquiring Carson Creek and which expires in October 2007.

Sable Offshore Energy Project

The Sable Offshore Energy Project involves the development of several natural gas fields near Sable Island which is located approximately 225 kilometers off the east coast of Nova Scotia. Raw gas is delivered to the onshore gas plant facility at Goldboro, where the liquids are extracted and sent to the fractionation plant at Point Tupper for processing. Sales gas is transported to market via the Maritimes & Northeast Pipeline. Propane and butane is shipped by both truck and rail while condensate is transported by ship. Pengrowth’s working interest is 8.4 percent.

As of December 31, 2006, Pengrowth Company Interest Total Proved Plus Probable Reserves were 13.1 mmboe. The Pengrowth Company Interest production averaged 6,428 boepd in 2006.

     Development Activity

A significant portion of Pengrowth’s capital expenditures on partner-operated properties were invested at the Sable Offshore Energy Project in 2006 with the addition of one well drilled from the Alma platform and the installation of compression to allow more gas production from the field.

The new well, Alma three, was drilled and completed in 2006. It came on production April 2006 and is contributing about 30 mmcfpd of gross incremental production. Additional perforations were added to the North Triumph well in late 2006 which also increased production. No new wells are planned for 2007 although perforating additional pay zones in some existing wells will continue.

Capital was also spent on the construction of a 30,000 HP compression project which was installed near Thebaud in 2006. As of November 28, 2006, the new compressor facilities on the additional platform next to the Thebaud platform were completed and started up. This compression will allow the Sable fields to be drawn down to much lower reservoir pressures allowing for a greater recovery of gas at higher production rates. Tanks for condensate were installed at both the Thebaud platform and the Goldboro facility to prevent

slugs of condensate from upsetting both the smooth operation of the new compressors and the pipeline from the offshore platform to the onshore facilities. Additional accommodation units have been added to Thebaud platform to house the additional workers required for the compressors and other projects. A project to grout the legs of the Thebaud platform to reduce motion of the platform in heavy seas was completed in January 2007.

Monogram Gas Unit

Pengrowth holds a 53.8 percent working interest in the partner-operated Monogram Gas Unit located in southern Alberta. The Monogram Gas Unit produces sweet, dry natural gas from the Medicine Hat, Milk River and Second White Specks formations. At December 31, 2006, Pengrowth Company Interest Total Proved Plus Probable Reserves were 7.8 mmboe with a remaining reserve life of 38 years and a Reserve Life Index of 10.9 years. Pengrowth Company Interest production in 2006 averaged 2,017 boepd.

     Development Activity

In 2006, a 20 well refracture program and a 70 well refracture program resulted in average gross production increases of 27 mcfpd per well and reserve additions of 20 mmcf per well. A ten well perforation/fracture stimulation program to determine if non-unitized formations contain pay that was by-passed was included. No development drilling occurred in 2006. In 2007, 28 infill wells were drilled in the first quarter, with another 62 infills planned for the second half of 2007. In addition, a 100 well refracture program is planned for the second half of 2007.

Dunvegan Gas Unit No. 1

In early 2006, Pengrowth acquired an additional 2.39% of the Dunvegan Unit No. 1, resulting in a total working interest of 10.37%. The Dunvegan Gas Unit No. 1 is located 430 kilometers northwest of Edmonton, Alberta in the Peace River area. The partner-operated Dunvegan natural gas field has approximately 200 producing wells and covers an area of 213 square kilometers. Approximately 95 percent of the Unit’s identified natural gas reserves are contained in the Mississippian Debolt formation. At December 31, 2006, Pengrowth Company Interest Total Proved Plus Probable Reserves were 6.4 mmboe with a remaining reserve life of 34 years and a Reserve Life Index of 9.5 years. In 2006, Pengrowth Company Interest production averaged 1,802 boepd.

     Development Activity

A successful infill drilling program that was first initiated in 2003 continued through 2006 with the drilling of twelve additional wells. All twelve wells were tied in prior to the end of 2006, with an average gross production rate exceeding 0.7 mmcfpd and 1.0 bcf of gross reserves per well. Based on the success of this infill program, an additional ten wells were approved for 2007 and are currently being drilled.

Tangleflags

Pengrowth holds a 50 percent working interest in the partner operated Tangleflags North EOR project. Located in west central Saskatchewan, approximately 40 kilometers northeast of Lloydminster, the property produces 12°API oil mainly from the Lloydminster sands under a SAGD thermal recovery process.

The enhanced oil recovery project commenced operation in the late 1980’s and contains horizontal producing wells along with both vertical and horizontal steam injection wells. As steam is injected into the reservoir and oil and water is withdrawn, a steam chamber is created which expands vertically and laterally, heating the reservoir and allowing the oil to drain more easily to the horizontal producing wells located near the base of the reservoir. At December 31, 2006, Pengrowth Company Interest Total Proved Plus Probable Reserves were

5.7 mmboe with a remaining reserve life of 26 years and a Reserve Life Index of 6.9 years. Pengrowth Company Interest production averaged 1,632 boepd in 2006.

     Development Activity

Three recompletions of injectors to producers were completed in 2006. A thirteen well drilling program began in the fourth quarter of 2006 and all wells were completed in the first quarter of 2007. It is anticipated that all thirteen wells will be brought on at low rates in the first quarter with a steady increase to full potential in the third quarter. This will be done in an effort to avoid well problems. No new drilling projects are expected for 2007.

Quirk Creek

Pengrowth holds a 68 percent working interest in four producing Rundle Formation deep plate gas wells, a 31 percent working interest in 10 producing Rundle upper plate gas wells, a 25 percent working interest in three producing gas wells in Millarville and a 30.5 percent working interest in the Quirk Creek natural gas plant located in the Quirk Creek area of Southern Alberta, approximately 30 kilometers southwest of Calgary.

At December 31, 2006, Pengrowth Company Interest Total Proved Plus Probable Reserves were 5.5 mmboe with a remaining reserve life of 33 years and a Reserve Life Index of 11.6 years. Pengrowth Company Interest production averaged 883 boepd in 2006.

     Development Activity

One development Rundle deep plate well was drilled in 2006 and commenced production in October. Operational difficulties were encountered until a line heater was connected in December. The current raw rate of 5 mmcfpd (3.5 mmcfpd net) is expected to increase to 7 mmcfpd (4.8 mmcfpd net) in April after a new line heater is installed. Another deep plate location is expected to be proposed and authorized in the 4th quarter. Third party processing revenues in 2006 made up 18 percent of gross revenues for the property.

East Bodo

The Bodo heavy oil properties straddle the Alberta-Saskatchewan border and produce mainly 12° API oil from the McLaren and 15° API oil from the Lloydminster reservoirs. Pengrowth operates several batteries to treat oil, as well as a number of compressor stations to process solution and non-associated gas. A waterflood is underway to improve production from the East Bodo Lloydminster formation. At December 31, 2006, Pengrowth Company Interest Total Proved Plus Probable Reserves were 5.2 mmboe with a remaining reserve life of 46 years and a Reserve Life Index of 21.6 years. Pengrowth Company Interest production averaged 701 boepd in 2006.

     Development Activity

In 2006, Pengrowth expanded the waterflood. Eight wells drilled in 2006, six of which were horizontal, added to the 2006 production. Four producing wells were converted to injection wells and one well was deepened to improve the water supply for the waterflood. To determine the potential for enhanced recovery in East Bodo, a polymer flood pilot was initiated in May 2006. The benefit of a polymer flood over conventional waterflooding is improved oil recovery and potentially incremental reserves. Pengrowth plans to expand the polymer pilot in 2007. In addition to the Lloydminster and McLaren reservoir activity in East Bodo, three wells were re-completed for uphole gas in 2006.

Twining

The Twining Field is located approximately 160 kilometres northeast of Calgary, Alberta. The primary producing zone is the Pekisko with additional production from the Ellerslie, Glauconite and Belly River zones. At December 31, 2006, Pengrowth Company Interest Total Proved Plus Probable Reserves were 4.9 mmboe with a remaining reserve life of 50 years and a Reserve Life Index of 13.6 years. Pengrowth Company Interest production from the Twining Field averaged 1,745 boepd during 2006.

Pengrowth operates over 100 wells and four main battery facilities in the Twining area, and also operates the Equity Gas Unit No. 1 and has working interests in four partner-operated units.

     Development Activity

In 2006 Pengrowth drilled four wells into the Mannville and Viking formations, resulting in two producing wells and two standing well bores. A successful Equity Gas Unit well was drilled based on seismic that was shot in late 2005. Six infill Pekisko oil well locations were identified, with one well being drilled in December 2006. Pengrowth plans five Pekisko wells in 2007. One standing Pekisko oil well was also successfully recompleted in 2006.

Based on the success of the Mannville drills, Pengrowth plans two additional wells for 2007. Twenty-eight square kilometres of seismic shot over the east half of the Equity Gas Unit in November 2006 may provide additional drilling locations.

McLeod River

Pengrowth holds various interests in the McLeod River property, which is located approximately 175 kilometres west of Edmonton, Alberta. Reserves have been assigned to the Blueridge, Bluesky, Cadomin, Cardium, Gething, Notikewin, and Rock Creek formations.

As of December 31, 2006, Pengrowth Company Interest Total Proved Plus Probable Reserves were 4.2 mmboe with a remaining reserve life of 42 years and a Reserve Life Index of 8.3 years. Pengrowth Company Interest production averaged 1,365 boepd during 2006.

     Development Activity

One partner operated well was drilled in the first quarter of 2006 and one operated well was tied-in in the third quarter of 2006. Although no new wells are scheduled to be drilled in 2007, five recompletions are scheduled. Additionally, facility consolidation is in progress to improve efficiency and reduce operating costs.

Twining CBM

The Twining Field is located approximately 160 kilometers northeast of Calgary, Alberta. During the first full year of CBM development activity, Pengrowth participated in numerous wells in the Twining-Mikwan area, including an aggressive program operated by Pengrowth. At December 31, 2006, Pengrowth Company Interest Total Proved Plus Probable Reserves were 4.1 mmboe.

     Development Activity

In 2006, Pengrowth drilled 11 wells for Horseshoe Canyon CBM to complete its Phase 1 evaluation program, resulting in six producing wells and five standing wells. Production from the six wells averaged approximately 475 mcfpd net to Pengrowth for the last quarter of 2006. Based on these results, a further 52 wells were drilled in 2006. These wells were all cased and ready to be tied in during 2007.

Pengrowth also constructed a 5 mmcfpd CBM compressor station in the North Twining area that was commissioned on February 9, 2007. The station has the potential to be expanded to 10 mmcfpd in the future. Pengrowth owns 34 percent of this facility. In early 2007 net CBM production from 23 operated wells totaled 1.9 mmcfpd. The remaining 40 wells will be tied in during 2007. Plans for 2007 include drilling 16 wells in the Twining area, testing the Horseshoe Canyon coals in the Olds area and drilling a horizontal Mannville test.

Partner operated CBM activity in the Mikwan/Three Hills Creek/Ghost Pine/Trochu/Twining areas resulted in the drilling of about 65 wells and participation in three major compression/dehydration and gas gathering systems. Pengrowth’s working interests range from 6% to 56%. This CBM development drilling activity is continuing in 2007 with approximately 50 wells expected.

Kaybob Notikewin Unit No. 1

The Kaybob Notikewin Unit No. 1 is located approximately 240 kilometers northwest of Edmonton, Alberta. Pengrowth holds a 98.88 percent working interest in the Unit. The Kaybob Notikewin Unit No. 1 produces natural gas and natural gas liquids from the Notikewin formation. Initial production from this formation commenced in 1962. As of December 31, 2006, Pengrowth Company Interest Total Proved Plus Probable Reserves were 4.1 mmboe with a remaining reserve life of 40 years and a Reserve Life Index of 13.5 years. Pengrowth’s production averaged 875 boepd in 2006.

     Development Activity

No further activity has been planned for 2007 as the field has been fully developed with the current wells.

Statement of Oil and Gas Reserves and Reserves Data

Disclosure of Reserves Data

The information in this section is based upon evaluations by GLJ with an effective date of December 31, 2006 contained in the GLJ Reports dated February 1, 2007 and March 5, 2007, and was prepared in accordance with NI 51-101. The effective date of the information in this section is December 31, 2006 and the preparation date of the information is January 12, 2007 (with respect to the report relating to Pengrowth’s assets and excluding the CP Properties) and February 15, 2007 (with respect to the report relating to the CP Properties). The information in this section summarizes the oil, liquids and natural gas reserves of Pengrowth and the CP Properties and the net present values of future net revenue for these reserves using GLJ’s constant prices and costs and forecast prices and costs. Pengrowth engaged GLJ to provide an evaluation of Proved Reserves and Total Proved Plus Probable Reserves and no attempt was made to evaluate possible reserves. It is Pengrowth’s practice to obtain an engineering report evaluating all of its Proved Reserves and Probable Reserves as at December 31 of each year. All of Pengrowth’s reserves are in Canada in the provinces of Alberta, British Columbia, Saskatchewan and Nova Scotia. In a subsequent event, Pengrowth acquired the CP Properties on January 22, 2007. Due to the materiality of the CP Acquisition, reserves tables have been included for the CP Properties and for the proforma Pengrowth plus the CP Properties, all with net present values as of December 31, 2006.

The following tables set forth certain information relating to the oil and natural gas reserves of Pengrowth and the present value of the estimated future net cash flow associated with such reserves as at December 31, 2006 contained in the GLJ report dated February 1, 2007. 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.

The Alberta Royalty Tax Credit program has been cancelled as of January 1, 2007. Credits from this program are therefore not included in the GLJ cash flow forecasts.

The information set forth below is derived from the GLJ Reports which have been prepared in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook and the reserves definitions contained in NI 51-101 and the Canadian Oil and Gas Evaluation Handbook. The GLJ Reports incorporate estimates of future well abandonment obligations but do not include estimates of remediation costs. All evaluations of future net cash flow 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 cash flow 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.

The net cash flows estimated in the GLJ Reports represent estimates of the revenues from oil and gas sales from the petroleum and natural gas properties of Pengrowth together with an estimate of processing revenues less royalties (net of incentives), mineral taxes, field operating expenses and capital obligations. These net cash flows are not the same as the distributable cash reported by the Trust. The computation of distributable cash is described under the heading “Distributable Cash and Distributions” in Pengrowth’s Management’s Discussion and Analysis for the year ended December 31, 2006. Significant factors to consider include:

	•		the GLJ Report does not estimate general and administrative expenses, interest, management fees and holdbacks;
	•		the GLJ Report does not estimate all abandonment or any reclamation liabilities;
	•		for purposes of calculating distributable cash, the Trust amortizes the cost of miscible flood injection fluids purchased from third parties over the period of expected future economic benefit arising from the injection of those fluids, which had been 30 months and was revised to 24 months for 2005 onward. The GLJ Report includes the full cost of purchased injection fluids ($34.6 million in 2006) in operating costs in the year incurred; and
	•		Pengrowth withholds certain amounts from distributable cash to fund capital.

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 as Appendices A and B hereto, respectively.

Reserves Data (Constant Prices and Costs) — Pengrowth without CP Properties

Summary of Oil And Gas Reserves
Net Present Value of Future Net Revenue
as of December 31, 2006
Constant Prices and Costs

		Light and Medium Oil												Heavy Oil												Natural Gas
		Pengrowth				Pengrowth				Pengrowth				Pengrowth				Pengrowth				Pengrowth				Pengrowth				Pengrowth				Pengrowth
		Company				Gross				Net				Company				Gross				Net				Company				Gross				Net
		Interest				Interest				Interest				Interest				Interest				Interest				Interest				Interest				Interest
Reserves Category		(mbbls)				(mbbls)				(mbbls)				(mbbls)				(mbbls)				(mbbls)				(bcf)				(bcf)				(bcf)
Proved Reserves
Proved Developed Producing			67,347				37,136				58,001				11,368				11,360				9,975				537.7				534.4				425.2
Proved Developed Non-Producing			436				436				348				992				992				837				36.7				36.5				27.9
Proved Undeveloped			18,040				18,028				15,302				1,908				1,908				1,649				48.8				48.7				38.8
Total Proved Reserves			85,823				85,599				73,651				14,268				14,260				12,461				623.2				619.6				491.9
Probable Reserves			26,877				26,826				22,788				4,088				4,086				3,466				200.0				199.0				155.9
Total Proved Plus Probable Reserves			112,700				112,425				96,440				18,356				18,346				15,927				823.2				818.7				647.8

		Natural Gas Liquids												Total Oil Equivalent Basis
		Pengrowth				Pengrowth				Pengrowth				Pengrowth				Pengrowth				Pengrowth
		Company				Gross				Net				Company				Gross				Net
		Interest				Interest				Interest				Interest				Interest				Interest
Reserves Category		(mbbls)				(mbbls)				(mbbls)				(mboe)				(mboe)				(mboe)
Proved Reserves
Proved Developed Producing			20,339				20,290				14,531				188,672				187,857				153,381
Proved Developed Non-Producing			631				630				451				8,175				8,138				6,285
Proved Undeveloped			1,463				1,463				1,089				29,538				29,519				24,507
Total Proved Reserves			22,433				22,383				16,071				226,385				225,514				184,173
Probable Reserves			6,606				6,595				4,795				70,903				70,681				57,033
Total Proved Plus Probable Reserves			29,039				28,978				20,866				297,288				296,195				241,206

		Net Present Values of Future Net Revenue
		Constant Prices and Costs Before Income Taxes
		Discounted at (%/year)
		0%				5%				10%				15%				20%
Reserves Category		($MM)				($MM)				($MM)				($MM)				($MM)
Proved Reserves
Proved Developed Producing			4,417.1				3,363.3				2,746.3				2,341.5				2,054.5
Proved Developed Non-Producing			152.9				119.3				97.3				81.8				70.5
Proved Undeveloped			746.2				474.2				321.9				227.3				164.1
Total Proved Reserves			5,316.2				3,956.8				3,165.5				2,650.6				2,289.1
Probable Reserves			1,872.0				1,070.6				709.6				513.8				393.8
Total Proved Plus Probable Reserves			7,188.2				5,027.4				3,875.1				3,164.4				2,682.9

Reserves Data (Constant Prices and Costs) — CP Properties

Summary of Oil And Gas Reserves
Net Present Value of Future Net Revenue
as of December 31, 2006
Constant Prices and Costs

		Light and Medium Oil												Heavy Oil												Natural Gas
		Pengrowth				Pengrowth				Pengrowth				Pengrowth				Pengrowth				Pengrowth				Pengrowth				Pengrowth				Pengrowth
		Company				Gross				Net				Company				Gross				Net				Company				Gross				Net
		Interest				Interest				Interest				Interest				Interest				Interest				Interest				Interest				Interest
Reserves Category		(mbbls)				(mbbls)				(mbbls)				(mbbls)				(mbbls)				(mbbls)				(bcf)				(bcf)				(bcf)
Proved Reserves
Proved Developed Producing			12,954				12,931				11,658				5,804				5,801				5,446				137.6				136.3				117.9
Proved Developed Non-Producing			254				254				216				0				0				0				2.2				2.2				1.7
Proved Undeveloped			1,449				1,449				1,096				341				341				297				22.2				21.9				20.0
Total Proved Reserves			14,657				14,634				12,970				6,145				6,142				5,743				162.0				160.4				139.6
Probable Reserves			4,946				4,940				4,320				1,508				1,507				1,360				39.6				39.0				34.2
Total Proved Plus Probable Reserves			19,603				19,574				17,291				7,653				7,649				7,103				201.6				199.4				173.8

		Natural Gas Liquids												Total Oil Equivalent Basis
		Pengrowth Company				Pengrowth Gross				Pengrowth Net				Pengrowth Company				Pengrowth Gross				Pengrowth Net
		Interest				Interest				Interest				Interest				Interest				Interest
Reserves Category		(mbbls)				(mbbls)				(mbbls)				(mboe)				(mboe)				(mboe)
Proved Reserves
Proved Developed Producing			2,922				2,914				2,060				44,619				44,357				38,810
Proved Developed Non-Producing			53				53				33				678				670				526
Proved Undeveloped			130				130				87				5,616				5,576				4,822
Total Proved Reserves			3,105				3,097				2,179				50,913				50,603				44,158
Probable Reserves			727				725				506				13,773				13,673				11,887
Total Proved Plus Probable Reserves			3,831				3,822				2,685				64,685				64,276				56,045

		Net Present Values of Future Net Revenue
		Constant Prices and Costs Before Income Taxes
		Discounted at (%/year)
		0%				5%				10%				15%				20%
Reserves Category		($MM)				($MM)				($MM)				($MM)				($MM)
Proved Reserves Proved Developed Producing			868.0				718.2				614.6				538.8				481.1
Proved Developed Non-Producing			16.2				11.1				8.3				6.5				5.3
Proved Undeveloped			74.0				43.0				25.5				14.6				7.4
Total Proved Reserves			958.2				772.4				648.3				559.9				493.9
Probable Reserves			311.6				198.0				137.7				101.8				78.6
Total Proved Plus Probable Reserves			1,269.8				970.4				786.0				661.7				572.5

Reserves Data (Constant Prices and Costs) — Proforma Pengrowth and CP Properties

Summary of Oil and Gas Reserves
Net Present Value of Future Net Revenue
as of December 31, 2006
Constant Prices and Costs

		Light and Medium Oil												Heavy Oil												Natural Gas
		Pengrowth				Pengrowth				Pengrowth				Pengrowth				Pengrowth				Pengrowth				Pengrowth				Pengrowth				Pengrowth
		Company				Gross				Net				Company				Gross				Net				Company				Gross				Net
		Interest				Interest				Interest				Interest				Interest				Interest				Interest				Interest				Interest
Reserves Category		(mbbls)				(mbbls)				(mbbls)				(mbbls)				(mbbls)				(mbbls)				(bcf)				(bcf)				(bcf)
Proved Reserves
Proved Developed Producing			80,301				80,066				69,660				17,172				17,160				15,420				675.3				670.7				543.1
Proved Developed Non-Producing			689				689				565				992				992				837				38.9				38.7				29.6
Proved Undeveloped			19,489				19,477				16,397				2,249				2,249				1,946				70.9				70.7				58.9
Total Proved Reserves			100,480				100,233				86,622				20,413				20,402				18,204				785.2				780.0				631.5
Probable Reserves			31,823				31,766				27,108				5,596				5,593				4,826				239.5				238.0				190.1
Total Proved Plus Probable Reserves			132,303				131,999				113,730				26,009				25,995				23,030				1024.7				1018.1				821.6

		Natural Gas Liquids												Total Oil Equivalent Basis
										Pengrowth												Pengrowth
		Pengrowth Company				Pengrowth Gross				Net				Pengrowth Company				Pengrowth Gross				Net
		Interest				Interest				Interest				Interest				Interest				Interest
Reserves Category		(mbbls)				(mbbls)				(mbbls)				(mboe)				(mboe)				(mboe)
Proved Reserves
Proved Developed Producing			23,260				23,204				16,591				233,291				232,214				192,191
Proved Developed Non-Producing			684				683				484				8,853				8,808				6,811
Proved Undeveloped			1,593				1,593				1,176				35,154				35,095				29,329
Total Proved Reserves			25,538				25,480				18,250				277,298				276,177				228,331
Probable Reserves			7,333				7,320				5,301				84,675				84,353				68,920
Total Proved Plus Probable Reserves			32,871				32,800				23,551				361,973				360,471				297,251

		Net Present Values of Future Net Revenue
		Constant Prices and Costs Before Income Taxes
		Discounted at (%/year)
		0%				5%				10%				15%				20%
Reserves Category		($MM)				($MM)				($MM)				($MM)				($MM)
Proved Reserves
Proved Developed Producing			5,285.1				4,081.5				3,360.9				2,880.3				2,535.6
Proved Developed Non-Producing			169.1				130.4				105.6				88.4				75.8
Proved Undeveloped			820.2				517.2				347.4				241.9				171.6
Total Proved Reserves			6,274.4				4,729.2				3,813.8				3,210.5				2,783.0
Probable Reserves			2,183.6				1,268.7				847.3				615.6				472.4
Total Proved Plus Probable Reserves			8,458.0				5,997.9				4,661.1				3,826.1				3,255.4

Pengrowth without CP Properties
Additional Information Concerning Future Net Revenue
(undiscounted)
as of December 31, 2006
Constant Prices and Costs

Capital

Future

Development

Abandonment

Net Revenue

Revenue

Royalties

Operating Costs

Costs

Costs(1)

Before Income Tax

Reserves Category

($MM)

($MM)

($MM)

($MM)

($MM)

($MM)

Proved Reserves

11,334

1,991

3,485

415

127

5,316

Total Proved Plus Probable Reserves

14,879

2,664

4,283

611

133

7,188

Notes:

Pengrowth without CP Properties
Net Present Value of Future Net Revenue
By Production Group
as of December 31, 2006
Constant Prices and Costs

				Future Net
				Revenue Before
				Income Taxes
				(discounted
Reserves Category		Production Group		at 10% yr) ($M)
Proved Reserves		Light and Medium Crude Oil (including solution gas and other by-products) (1)			1,721,961
		Heavy Oil (including solution gas and other by-products) (1)			162,713
		Natural Gas (including by-products but excluding solution gas from oil wells) (2)			1,280,832
Total Proved Plus Probable Reserves		Light and Medium Crude Oil (including solution gas and other by-products) (1)			2,074,957
		Heavy Oil (including solution gas and other by-products) (1)			201,572
		Natural Gas (including by-products but excluding solution gas from oil wells) (2)			1,598,559

Notes:

Reserves Data (Forecast Prices and Costs) — Pengrowth without CP Properties

Summary of Oil and Gas Reserves
Net Present Value of Future Net Revenue
as of December 31, 2006
Forecast Prices and Costs

		Light and Medium Oil												Heavy Oil												Natural Gas
		Pengrowth				Pengrowth				Pengrowth				Pengrowth				Pengrowth				Pengrowth				Pengrowth				Pengrowth				Pengrowth
		Company				Gross				Net				Company				Gross				Net				Company				Gross				Net
		Interest				Interest				Interest				Interest				Interest				Interest				Interest				Interest				Interest
Reserves Category		(mbbls)				(mbbls)				(mbbls)				(mbbls)				(mbbls)				(mbbls)				(bcf)				(bcf)				(bcf)
Proved Reserves
Proved Developed Producing			67,070				66,861				57,753				11,364				11,356				9,973				540.9				537.6				427.8
Proved Developed Non-Producing			436				436				348				990				990				836				36.8				36.6				27.9
Proved Undeveloped			17,363				17,352				14,781				1,891				1,891				1,634				48.2				48.2				38.4
Total Proved Reserves			84,869				84,649				72,882				14,245				14,237				12,443				625.9				622.4				494.1
Probable Reserves			27,518				27,468				23,451				4,091				4,089				3,469				201.6				200.6				157.2
Total Proved Plus Probable Reserves			112,387				112,117				96,333				18,336				18,326				15,912				827.5				823.0				651.4

		Natural Gas Liquids												Total Oil Equivalent Basis
		Pengrowth				Pengrowth				Pengrowth				Pengrowth								Pengrowth
		Company				Gross				Net				Company				Pengrowth Gross				Net
		Interest				Interest				Interest				Interest				Interest				Interest
Reserves Category		(mbbls)				(mbbls)				(mbbls)				(mboe)				(mboe)				(mboe)
Proved Reserves
Proved Developed Producing			20,380				20,332				14,569				188,961				188,146				153,592
Proved Developed Non-Producing			631				630				452				8,187				8,154				6,291
Proved Undeveloped			1,439				1,439				1,075				28,726				28,707				23,895
Total Proved Reserves			22,450				22,400				16,096				225,875				225,007				183,777
Probable Reserves			6,693				6,682				4,862				71,899				71,677				57,986
Total Proved Plus Probable Reserves			29,143				29,082				20,958				297,774				296,684				241,763