Pengrowth Energy (PGH) 40-F/A 2007 FY Annual report (Canada) (amended)

U.S. SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 40-F/A

AMENDMENT NO. 1

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

þ  ANNUAL REPORT PURSUANT TO SECTION13(a) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended: December 31, 2007          Commission File Number: 1-31253

PENGROWTH ENERGY TRUST

(Exact name of Registrant as specified in its charter)
Alberta, Canada
(Province or other jurisdiction of incorporation or organization)

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

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

CT Corporation System
111-8^thAvenue, 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 – 2^ndStreet SW
Calgary, Alberta T2P 4K7 Canada
(403) 298-3100 Andrew J. Foley
Paul, Weiss, Rifkind, Wharton & Garrison LLP
1285 Avenue of the Americas
New York, New York 10019-6064 USA
(212) 373-3000

Securities registered or to be registered pursuant to Section 12(b) of the Act.

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

Securities registered or to be registered pursuant to Section 12(g) of the Act.

None
(Title of Class)

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

None
(Title of Class)

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

þ   Annual information form o   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 246,844,532 Trust Units, of no par value, outstanding as of December 31, 2007.

     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

     This Amendment No. 1 to the Annual Report on Form 40-F shall be incorporated by reference into or as an exhibit to, as applicable, the registrant’s Registration Statements on Form F-10 and F-3 (File Nos. 333-146928 and 333-143810, respectively) under the Securities Act of 1933, as amended.

EXPLANATORY NOTE

     This Amendment No. 1 (this “Amendment”) to the Annual Report on Form 40-F filed on March 19, 2008 (the “Original Filing”) of Pengrowth Energy Trust (“Pengrowth”) for the fiscal year ended December 31, 2007, is being filed for the purpose of amending Pengrowth’s Annual Information Form for the year ended December 31, 2007, in order to correct typographical errors in certain tables relating to gas reserves as of December 31, 2007 where units indicating the measured reserves should have been stated in “MMcf” (millions of cubic feet) and to correct a typographical error in a table relating to property acquisition, exploration and development costs incurred in 2007 where figures should have been listed in “$M” (thousands of dollars). In addition, we are including as exhibits a currently dated consent of our reserve engineers and currently dated certifications of our Chief Executive Officer and Chief Financial Officer.

     Other than as expressly set forth above, this Amendment does not, and does not purport to, update or restate the information in any Item of the Original Filing or reflect any events that have occurred after the Original Filing was filed. The filing of this Amendment shall not be deemed an admission that the Original Filing, when made, included any known, untrue statement of material fact or knowingly omitted to state a material fact necessary to make a statement not misleading.

DOCUMENTS FILED AS PART OF THIS AMENDMENT

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

Appendix	Documents
A	Pengrowth Energy Trust Revised Annual Information Form for the year ended December 31, 2007.
B*	Management’s Discussion and Analysis.
C*	Consolidated Financial Statements of Pengrowth Energy Trust, including Management’s Report to Unitholders, the Auditors’ Reports and note 23 thereof which includes a reconciliation of the Consolidated Financial Statements to United States generally accepted accounting principles.
D*	Comments by Auditors for U.S. Readers on Canada – U.S. Reporting Differences.
E*	Oil and Gas Producing Activities Prepared in Accordance with SFAS No. 69 — “Disclosures about Oil and Gas Producing Activities”.
F*	Pengrowth Energy Trust Code of Business Conduct and Ethics dated February 19, 2008.

* Previously filed.

CERTIFICATIONS AND DISCLOSURE REGARDING CONTROLS AND PROCEDURES

Certifications. See Exhibits 2, 3, 4 and 5 to this Annual Report on Form 40-F/A.

UNDERTAKING

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

CONSENT TO SERVICE OF PROCESS

The Registrant has previously filed a Form F-X in connection with the class of securities in relation to which the obligation to file this report arises. Any change to the name or address of the agent for service of process of the Registrant shall be communicated promptly to the Commission by an amendment to the Form F-X referencing the file number of the relevant registration statement.

EXHIBITS

     The following exhibits are filed as part of this report.

Exhibit
Number	Description
1	Consent of GLJ Petroleum Consultants Ltd.
2	Certification of the CEO pursuant to Rule 13(a)-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code.
3	Certification of the CFO pursuant to Rule 13(a)-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code.
4	Certification of the CEO pursuant to Rule 13a-14(a) of the Exchange Act.
5	Certification of the CFO pursuant to Rule 13a-14(a) of the Exchange Act.

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 Amendment No. 1 to the Annual Report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date: September 15, 2008	PENGROWTH ENERGY TRUST by its Administrator PENGROWTH CORPORATION
	By:	/s/  James S. Kinnear
		James S. Kinnear
		Chairman, President and Chief Executive Officer

APPENDIX A

PENGROWTH ENERGY TRUST REVISED ANNUAL INFORMATION FORM FOR THE YEAR

ENDED DECEMBER 31, 2007

PENGROWTH ENERGY TRUST

REVISED ANNUAL INFORMATION FORM
For the year ended December 31, 2007

March 19, 2008
(except for pages 37, 40 and 51 which are as of September 15, 2008)

TABLE OF CONTENTS

GLOSSARY OF TERMS AND ABBREVIATIONS	1
Corporate	1
Engineering	2
Abbreviations	3
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	8
Business Strategy and Strengths	9
SIFT Legislation Considerations	11
GENERAL DEVELOPMENT OF PENGROWTH ENERGY TRUST	12
Recent Developments	12
Historical Developments	17
Trends	19
PENGROWTH MANAGEMENT LIMITED	20
Business	20
Management Agreement	20
Bonus Pool	22
Management Agreement Second Term	22
PENGROWTH – OPERATIONAL INFORMATION	23
Principle Properties	23
Light Oil Properties	24
Heavy Oil Properties	27
Conventional Gas Properties	28
Shallow Gas Properties	31
Offshore Gas Properties	33
Statement of Oil and Gas Reserves and Reserves Data	35
Additional Information Relating to Reserves Data	45
Future Development Costs	47
Finding, Development and Acquisition Costs	47
Future Development Capital	48
Other Oil and Gas Information	49
Additional Information Concerning Abandonment & Reclamation Costs	50
Costs Incurred	51
Exploration and Development Activities	51
Production Estimates	51
Production History (Netback)	52
Replacement of Properties	53
TRUST UNITS	54
The Trust Indenture	54
The Trustee	54
Stock Exchange Listings	55
Ownership Restrictions	55
Redemption Right	55

Conversion Rights	55
Voting at Meetings of Unitholders	55
Voting at Meetings of Corporation	56
Termination of the Trust	56
Unitholder Limited Liability	56
THE ROYALTY INDENTURE	57
Royalty Units	57
The Royalty	57
The Trustee	58
EXCHANGEABLE SHARES	58
DISTRIBUTIONS	59
General	59
Historical Distributions	59
Restrictions on Distributions	60
CERTAIN CANADIAN FEDERAL INCOME TAX CONSIDERATIONS	64
Taxation of Unitholders Resident in Canada	65
Taxation of Unitholders who are Non-Residents of Canada	66
UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS	67
Classification of Pengrowth Energy Trust as a Partnership	68
Possible Classification as a Corporation; PFIC Rules	68
Consequences of Possible PFIC Classification	69
Tax Consequences of Trust Unit Ownership	70
Tax Treatment of Trust Operations	71
Disposition of Trust Units	73
Disposition of Trust Units by Redemption	74
Uniformity of Trust Units	75
Tax-Exempt Organizations	75
Administrative Matters	75
Reportable Transactions	76
Foreign Partnership Reporting	76
INDUSTRY CONDITIONS	76
Government Regulation	76
Pricing and Marketing — Oil	76
Pricing and Marketing — Natural Gas	77
Pricing and Marketing — Natural Gas Liquids	77
Environmental Regulation	78
RISK FACTORS	80
MARKET FOR SECURITIES	93
DIRECTORS AND OFFICERS	94
Directors and Officers of the Manager	94
Principal Holders of Shares of the Manager	94
Directors and Officers of the Corporation	95
Corporate Cease Trade Orders or Bankruptcies	96
Personal Bankruptcies	97
Penalties or Sanctions	97
AUDIT COMMITTEE	97
Principal Accountant Fees and Services	98
Pre-approval Policies and Procedures	98

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CONFLICTS OF INTEREST	99
LEGAL PROCEEDINGS	100
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	100
INTERESTS OF EXPERTS	100
AUDITORS, TRANSFER AGENT AND REGISTRAR	100
MATERIAL CONTRACTS	100
CODE OF ETHICS	101
OFF-BALANCE SHEET ARRANGEMENTS	101
DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NEW YORK STOCK EXCHANGE	101
ADDITIONAL INFORMATION	102

Appendix A — Report on Reserves Data by Independent Qualified Reserves Evaluator on Form 51-102F2

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

Appendix C — Audit Committee Terms of Reference

Unless otherwise indicated, all of the information provided in this Annual Information Form is as at December 31, 2007.

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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;

“Canada-U.S. Convention” means theCanada-United States Tax Convention, 1980;

“Computershare” refers to Computershare Trust Company of Canada;

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

“CP Acquisition” refers to the acquisition by Pengrowth of certain entities from ConocoPhillips Canada on January 22, 2007;

“Credit Facility” has the meaning ascribed thereto under “General Development of Pengrowth Energy Trust – Recent Developments – Borrowing”;

“Debenture” refers to Pengrowth’s 6.5 percent convertible unsecured subordinated debentures assumed in connection with Pengrowth’s strategic business combination with Esprit Energy Trust;

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

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

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

“Protocol” means the fifth protocol to the Canada-U.S. Convention dated September 21, 2007, which proposed changes to the Canada-U.S. Convention and which has been ratified by Canada but not the United States;

“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;

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

“Trust” refers to Pengrowth Energy Trust;

“Trust Indenture” refers to the amended and restated trust indenture of the Trust dated June 11, 2007;

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

“Unitholders” refers to holders of Trust Units and class A trust units.

Engineering

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

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

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

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

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

“GLJ Report” refers to the report prepared by GLJ, dated February 8, 2008 with an effective date of December 31, 2007;

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

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

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

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

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

“Reserve Life Index” refers to the number of years determined by dividing the aggregate of the estimated reserves of a property from the GLJ Report by the estimated production per year from such property using estimated production associated with the reserves from the GLJ Report for the year 2008 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);

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

“Total Proved Plus Probable Reserves” 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;

“^oAPI” 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;

“EDGAR” refers to the Electronic Data Gathering Analysis and Retrieval System maintained by the United States Securities and Exchange Commission;

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

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

“MMBtu” 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;

“P+P” refers to Total Proved Plus Probable Reserves;

“SAGD” refers to steam assisted gravity drainage;

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

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

“SIFT Legislation” refers to the provisions of the Tax Act implementing the taxation of specified investment flow-throughs and their members and unitholders, as the case may be, which were originally announced by the Minister of Finance (Canada) on October 31, 2006 and which received Royal Assent under Bill C-52 on June 22, 2007;

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

“TSX” refers to the Toronto Stock Exchange; and

“WTI” refers to West Texas Intermediate.

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

CONVERSION

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

To Convert From	To	Multiply by
Mcf	cubic metre		28.174
cubic metre	cubic feet		35.494
bbls	cubic metre		0.159
cubic metre	bbls		6.29
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.

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PRESENTATION OF OUR FINANCIAL INFORMATION

Financial information in this Annual Information Form has been prepared in accordance with Canadian GAAP. Canadian GAAP differs in some significant respects from 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, 2007, which are available on the SEDAR website at www.sedar.com and in our current Form 40-F, which is available through EDGAR at the SEC’s website at www.sec.gov.

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 51-101Standards of Disclosure for Oil and Gas Activities(“NI 51-101”) of the Canadian Securities Administrators permits oil and gas issuers, in their filings with Canadian securities regulators, to disclose not only Proved Reserves but also Probable Reserves, 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 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 reserves and estimated future net cash flow therefrom using both escalated and constant prices and costs; for the constant prices and costs case, prices and costs in effect as of December 31, 2007 were held constant for the economic life of the reserves. The SEC does not permit the disclosure of reserves and estimated future net cash flow therefrom 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 of 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 current Form 40-F, which is available through EDGAR at the SEC’s website at www.sec.gov.

FORWARD-LOOKING STATEMENTS

This Annual Information Form contains forward-looking statements within the meaning of securities laws, including the “safe harbour” provisions of Canadian securities legislation and the United StatesPrivate 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, 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 2008 development program, remaining producing reserves lives, operating expenses, royalty rates, net present values of future net revenue from reserves, commodity prices and costs, exchange rates, the impact of contracts for commodities, development plans and programs, tax horizon, future income taxes, taxability of distributions, the impact of proposed changes to Canadian tax legislation or U.S. tax legislation, abandonment and reclamation costs, government royalty rates (including estimated increase in royalties paid and estimated decline in net present value of reserves and 2009 cash flows) and expiring acreage. Statements relating to “reserves” are forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the reserves described exist in the quantities predicted or estimated and can profitably be produced in the future.

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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 and royalty 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 “Risk Factors” in this Annual Information Form, under the heading “Business Risks” in our Management’s Discussion and Analysis for the year ended December 31, 2007, and in Pengrowth’s most recent consolidated financial statements, management information circular, quarterly reports, material change reports and news releases.

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

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PENGROWTH ENERGY TRUST

Introduction

The Trust is an energy investment trust that was created under the laws of the Province of Alberta on December 2, 1988. The purpose of the Trust is to pay distributions to our unitholders and to purchase and hold Royalty Units and other securities issued by the Corporation, its 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.

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. Our Unitholders are entitled to receive monthly distributions in respect of the royalty (“Royalty”) the Corporation pays to the holders of the Royalty Units, and in respect of investments that are held by the Trust.

The Trust presently holds 90.9 percent of the outstanding common shares in the capital of the Corporation and all of the Royalty Units issued by the Corporation. The Trust also holds all of the issued and outstanding shares of, and a net profits interest granted by, Esprit Exploration Ltd. The Trust holds other permitted investments, including indebtedness of the Corporation and Esprit Exploration Ltd. and oil and gas processing facilities. The Trust’s share of royalty income, together with any lease, interest and other income of the Trust, less general and administrative expenses, management fees, debt repayment, taxes and other expenses (provided that there is no duplication of expenses already deducted from royalty income), forms the cash to be distributed by the Trust.

The Corporation

The Corporation was created under the laws of the Province of Alberta on December 30, 1987. The name of the Corporation was changed from “Pengrowth Gas Corporation” to “Pengrowth Corporation” in 1998. The Corporation has 1,100 common shares presently 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 percent 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. There are presently no exchangeable shares outstanding. See “Exchangeable Shares” in this Annual Information Form.

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 profits interest of Esprit Exploration Ltd. held by the Trust. The Corporation entered into an agency agreement dated October 2, 2006 with Esprit Energy Trust, Esprit Exploration Ltd. and all of its subsidiaries whereby the Corporation would provide certain services to Esprit Energy Trust, Esprit Exploration Ltd. and all of 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.

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Esprit Exploration Ltd. was acquired in connection with Pengrowth’s strategic business combination with Esprit Energy Trust. Esprit Exploration Ltd. was created under the laws of Canada. See “General Development of Pengrowth Energy Trust – Historical Developments”.

The Corporation’s Subsidiaries

The Corporation owns all of the issued and outstanding shares of Stellar Resources Limited, which holds a 0.01 percent 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 percent partnership interests in each of the foregoing 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 in connection with the acquisition of Crispin Energy Inc. in 2005. Each of Stellar Resources Limited, Pengrowth Heavy Oil Partnership, Pengrowth Energy Partnership and Crispin Energy Partnership were created under the laws of the Province of Alberta.

The Corporation holds a 0.1 percent partnership interest in the Carson Creek Operating Partnership and owns all of the issued and outstanding shares of 1268071 Alberta Ltd., which in turn holds a 99.9 percent partnership interest. The Carson Creek Operating Partnership was acquired in connection with the acquisition of certain properties by Pengrowth from ExxonMobil Canada on September 28, 2006. See “General Development of Pengrowth Energy Trust – Historical Developments”. Each of 1268071 Alberta Ltd. and the Carson Creek Operating Partnership were created under the laws of the Province of Alberta.

The Corporation holds a 0.01 percent partnership interest in 706-707 Partnership and owns all of the issued and outstanding shares of 1275708 Alberta Ltd., which in turn holds a 99.99 percent partnership interest. The 706-707 Partnership was acquired in connection with the CP Acquisition. See “General Development of Pengrowth Energy Trust – Recent Developments – CP Acquisition”. 1275708 Alberta Ltd. and the 706-707 Partnership were created under the laws of the Province of Alberta.

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 the organizational structure of Pengrowth as at the date hereof:

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Business Strategy and Strengths

Our goal is to maximize cash distributions to our Unitholders on a per Trust Unit basis while enhancing the value of the Trust Units. We focus on making accretive acquisitions, and financing those acquisitions with a prudent combination of debt and equity, adding reserves and production through development and limited exploration 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. Our core operational expertise is in conventional oil and gas production, enhanced oil recovery, shallow gas drilling and in CBM development. We are engaged in CO₂ floods and other environmentally friendly operations through our participation in the Weyburn Unit and a recent pilot project at our Judy Creek field. We are highly experienced in the conduct of conventional operations and the application of new technologies to enhance the value of long life proven producing assets. We rely on our expertise in Enhanced Oil Recovery (EOR) technology and waterflood management as well as infill drilling to partially offset production declines in our mature oil properties. Development drilling and the installation of additional compression helps to extend the operating life of our mature gas properties. In addition to paying distributions, we withhold a portion of our cash flow from operations for the effective maintenance of our asset base and to pursue attractive development opportunities to offset part of our ordinary production declines. We have also substantially increased the amount of undeveloped acreage we control in order to provide additional future drilling opportunities and we engage in lower risk exploration on these lands. Our operations are presently focused substantially in the Western Canadian Sedimentary Basin. We also have experience in offshore operations through our 8.4% participation in the Sable Offshore Energy Project. As we seek to address ordinary declines in production from our existing assets and the impact of the SIFT Legislation we are also considering the acquisition of international oil and gas assets.

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

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Acquisitions

• Acquisitions should be accretive on a per Trust Unit basis based upon current forecast parameters. In determining whether an acquisition is accretive, we examine the profile of production, operating costs, capital costs, abandonment expenses and other key variables and compare that with our existing asset base to understand the impact over time in terms of production, reserves and distributions on a per Trust Unit basis.

• 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.

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

o low anticipated capital expenditures relative to the cash generation potential of the properties;

o relatively low operating costs or high netbacks;

o experienced, well regarded industry operators or where operatorship may be assumed by Pengrowth;

o favourable production history;

o upside potential through infill drilling, improved field operations and other development activities;

o potential synergies with our current properties and areas of our core expertise; and

o low environmental and site remediation risk.

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

Development

• Development investments should provide a high rate of return and provide production within a short period of time, or be necessary to maintain existing production operations. Pengrowth prioritizes its development investments based on:

o rate of return;

o timing of production;

o potential for continued development; and

o those investments necessary to maintain existing facilities and wells.

Our structure, ability to access capital and cost of capital allow us to bid competitively for oil and natural gas properties. However, our cost of capital has been significantly increased by the announcement of the SIFT Legislation. For a discussion of the consequences of the SIFT Legislation, see “Certain Canadian Federal Income Tax Considerations” and “Risk Factors – SIFT Legislation is expected to materially and adversely affect the Trust, the Unitholders and the value of the Trust Units”.

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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.

SIFT Legislation Considerations

Pengrowth is one of North America’s leading energy trusts. Our portfolio of high quality, diversified assets provides a base for stable production and a large inventory of opportunities going forward. This asset base is well suited to the income distribution model and Pengrowth has been paying cash distributions to Unitholders for the past 18 years. We continue to believe that there is considerable merit in our business model, which is proven by our success over the past 18 years, and that there is an important role for yield investors in the Canadian oil and gas business both now and in the future.

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

During the next three years, we believe our structure provides significant value for our Unitholders and we do not see any immediate incentive to make a material structural change. During this time, we will continue to take advantage of growth opportunities with an increased focus on international opportunities, given that it appears that revenue from outside Canada will not be subject to the new tax. In addition, we will continue to carefully manage our substantial tax pools to mitigate the impact of the new tax on our Unitholders.

Following 2010, we believe there will be an ongoing demand from investors for strong yield investments and we are actively investigating a number of alternative structures and solutions to determine the structure that is most advantageous to our Unitholders.

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GENERAL DEVELOPMENT OF PENGROWTH ENERGY TRUST

Recent Developments

2008 Forecast Capital, Production and Operating Costs

On December 3, 2007, Pengrowth released the details of its 2008 capital expenditure program and provided guidance on production and operating costs for 2008. Pengrowth’s 2008 development capital expenditure program consists of up to $355 million, plus additional expenditures of up to $32 million on investments that have longer-term value. The 2008 program will be similar to the program executed in 2007 with over 566 wells (238 net wells) forecast to be drilled.

Pengrowth expects to fund its 2008 capital expenditure program through a combination of undistributed cash from operations, available credit facilities, distribution reinvestment program proceeds and proceeds from the exercise of rights and options. Pengrowth may also issue a limited number of Trust Units under the Equity Distribution Program. See “General Development of Pengrowth Energy Trust – Recent Developments – At-the-Market Equity Distribution Program” set out below.

The table below describes the forecasted capital, production and operating costs for 2008:

Planned Capital Expenditures	($ millions)			(% of Total)
Drilling and Completions	$	281			80	%
Plant and Facilities	$	44			12	%
Land and Seismic	$	25			7	%
Other (e.g., CO2 Pilot)	$	5			1	%
Total Development Capital	$	355			100	%
Long Term Investments (Lindbergh, Building, IT)	$	32
Total Capital	$	387
Average Daily Production Volume (boepd)	80,000 - 82,000(1)
Operating Costs (per boe)	$	13.20	(2)
General and Administrative Costs (per boe)	$	2.20	(3)

Notes:

(1)	The 2008 estimate excludes potential additions through acquisitions.
(2)	Assuming production targets for 2008 are achieved.
(3)	Includes management fees of approximately $0.40 per boe.

Asset Rationalization Program

Following the CP Acquisition, the strategic business combination with Esprit Energy Trust and the acquisition of the Carson Creek properties from ExxonMobil Canada, Pengrowth completed asset sales for $476 million ($458.8 million net of adjustments) in 2007. The difference in the value and the net proceeds were mainly due to Pengrowth receiving payments for production from the effective date to close. The proceeds were used to repay debt, including the partial repayment of a $600 million bridge facility, which has since been repaid in its entirety.

At-the-Market Equity Distribution Program

On December 14, 2007, Pengrowth entered into an equity distribution agreement (the “Distribution Agreement”) with SG Americas Securities, LLC and FirstEnergy Capital Corp. (collectively, the “Underwriters”) which will permit Pengrowth to distribute up to 25,000,000 Trust Units from time to time through the Underwriters over a period of up to 25 months from the date of the Distribution Agreement (the “Equity Distribution Program”). Sales of Trust Units, if any, pursuant to the Distribution Agreement will be made in transactions that are deemed to be “at-the-market distributions”, including sales made directly on the NYSE or the TSX. The Trust Units will be distributed at market prices prevailing at the time of sale and, as a result, prices may vary between purchasers and

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during the period of distribution. At the current level of distributions and commodity prices, Pengrowth’s 2008 capital expenditure program is expected to exceed the amount of cash withheld by the Corporation after funding distributions to Unitholders. The net proceeds of the distribution of Trust Units will be used for development capital expenditures and general business purposes. The volume and timing of sales, if any, will be at Pengrowth’s discretion. No Trust Units were issued under the Equity Distribution Program during the year ended December 31, 2007.

Changes to Royalty Legislation Affecting Pengrowth and its Unitholders

Pengrowth pays royalties to the provinces of Alberta, British Columbia, Saskatchewan and Nova Scotia for the right to produce the minerals owned by them. Of the royalties paid, approximately 79 percent are paid to the Province of Alberta.

On October 25, 2007, the Government of Alberta unveiled a new methodology to calculate the royalties payable to it. The new regime would introduce new royalties for conventional oil, natural gas and bitumen, effective January 1, 2009, that are linked to price and production levels and would apply to both new and existing conventional oil and gas activities and oil sands projects.

Royalties payable pursuant to petroleum and natural gas leases with the Government of Alberta aread valoremroyalties, calculated using the oil or natural gas price and the level of production. Royalties payable to the Government of Alberta currently are 30 and 35 percent in the case of old and new conventional oil, respectively, 5 to 35 percent in the case of natural gas and 15 to 50 percent in the case of NGLs.

Under the new royalty regime, the royalty formula for conventional oil will operate on a sliding rate formula containing separate elements that account for oil price and well production and specialty royalty programs will be eliminated along with “old” and “new” tiers. Royalty rates for conventional oil will range up to 50 percent, with rate caps once the price of conventional oil reaches Cdn. $120 per barrel. A significant portion of Pengrowth’s production and reserves are derived from mature fields such as Judy Creek where EOR techniques are employed. Currently, EOR receives an incentive in the form of a reduced royalty. The Government of Alberta has indicated that these incentives are to be maintained.

Under the new royalty regime, natural gas royalties will be set by a sliding rate formula sensitive to price and well production rate. Vintages will be eliminated along with certain specialty royalty programs, though a form of deep gas royalty holiday will be retained and lower royalty rates will be applied over a wider price range for wells with less productivity. Royalty rates for natural gas will range from 5 to 50 percent with rate caps once the price of natural gas reaches $16.59/GJ (gigajoule). A shallow rights reversion program will also be implemented that will result in the reversion to the Government of Alberta of mineral rights to undeveloped geological formations above developed zones. Royalties for NGLs will be set at 40 percent for pentanes and 30 percent for butanes and propane.

The implementation of the proposed changes to the royalty regime in Alberta is subject to certain risks and uncertainties. The changes will require new legislation, changes to existing legislation and regulations and development of proprietary software to support the calculation and collection of royalties. Additionally, certain proposed changes contemplate further public and/or industry consultation. There may be modifications introduced to the proposed royalty structure prior to the implementation thereof.

Based on the interpretations by GLJ of the proposed royalty changes and based on the January 2008 commodity price assumptions of GLJ, it is anticipated that the new royalty regime will result in a 12 to 18 percent increase in the total royalties paid to all parties by Pengrowth as compared to the current royalty structure. This increase is expected to result in a decline in the pre-tax net present value, discounted at 10 percent, of the future net revenues associated with (i) Pengrowth’s Proved Reserves of three to five percent; and (ii) Pengrowth’s Total Proved Plus Probable Reserves of three to five percent.

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Using the same GLJ analysis referred to in the foregoing paragraph, under the new royalty regime, it is anticipated that there will be a less than one-half of one percent decrease in Pengrowth’s Company Interest reserves and a one to three percent decrease in Pengrowth’s Net reserves, as compared to the current royalty structure. It is anticipated that the new royalty regime will result in a five to seven percent decline in Pengrowth’s cash flow for 2009, the first year in which the royalty changes take effect, as compared to the current royalty structure.

The changes to the royalty regime may impact Pengrowth’s future allocation of capital among petroleum and natural gas projects within and outside of Alberta. See“Risk Factors – Changes in government regulations that affect the crude oil and natural gas industry could adversely affect Pengrowth and reduce our distributions to our Unitholders”.

Pengrowth’s production, reserves and future net revenues associated therewith contained in this Annual Information Form do not reflect the impact of the proposed changes discussed above.

Taxability of Distributions Paid to U.S. Residents

Distributions paid to U.S. residents are treated as partnership distributions for U.S. federal tax purposes and are currently subject to a 15 percent Canadian withholding tax to the extent that such amounts represent a distribution of Pengrowth’s income. Pursuant to the Tax Act, distributions to U.S. unitholders of amounts in excess of Pengrowth’s income (e.g., returns of capital) are also subject to a 15 percent Canadian withholding tax. On September 21, 2007, Canada and the United States signed the Protocol to the Canada-U.S. Convention which proposes to increase the amount of Canadian withholding tax from 15 percent to 25 percent on distributions of income. Under Article IV(7)(b) of the Protocol, U.S. resident Unitholders will be denied certain of the benefits under the Canada-U.S. Convention which would otherwise reduce the Canadian withholding tax on distributions of Pengrowth’s income from 25% to 15% (or such lower rate otherwise available under the Canada-U.S. Convention) insofar as Pengrowth has elected to be treated as a partnership, and is therefore a fiscally transparent entity, for U.S. federal income tax purposes. The proposed increase in the Canadian withholding tax rates on distribution of income under the Protocol does not affect returns of capital which would still be subject to a 15 percent Canadian withholding tax. The increase will become effective no earlier than January 1, 2010. Residents of the U.S. should consult their individual tax advisors on the impact of any additional Canadian withholding tax and changes to tax laws. As of December 14, 2007, Canada completed the steps required to give effect to the Protocol. The Protocol will come into effect once it has been ratified by the United States and the two countries have formally notified each other that their procedures are complete.

Senior Unsecured Notes

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

Under the note agreement relating to the 2007 U.S. Senior Notes (as well as the note agreements relating to the 2003 U.S. Senior Notes and U.K. Senior Notes referred to below under “General Development of Pengrowth Energy Trust – Historical Developments”), the Trust is restricted from making distributions under certain circumstances. See“Distributions – Restrictions on Distributions”.

The terms of the note agreements relating to the 2007 U.S. Senior Notes, (as well as the note agreements relating to the 2003 U.S. Senior Notes and U.K. Senior Notes referred to below under “General Development of Pengrowth Energy Trust – Historical Developments”) ensure that note holders have priority over the Unitholders with respect to the assets and income of the Trust. In the event that we default on our debts, amounts due and owing to the note holders under the 2007 U.S. Senior Notes, the 2003 U.S. Senior Notes and the U.K. Senior Notes must be paid before any distributions can be made to Unitholders. This could result in an interruption of distributions. See“Risk Factors – Our indebtedness may limit the amount of distributions that we are able to pay our Unitholders, and if we default on our debts, the net proceeds of any foreclosure sale would be allocated to the

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repayment of our lenders, note holders and other creditors and only the remainder, if any, would be available for distribution to our Unitholders”.

U.S. DRIP

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

Changes to Tax Legislation Affecting Pengrowth and its Unitholders and Debentureholders

On October 31, 2006, the Minister of Finance (Canada) announced proposed tax measures which will materially and adversely change the manner in which Pengrowth is taxed and will also change the character of the distributions to you for Canadian federal income tax purposes. On June 22, 2007, the SIFT Legislation became law when Bill C-52 received Royal Assent. It is expected that the SIFT Legislation will apply to Pengrowth and its Unitholders commencing in 2011, provided that Pengrowth does not exceed the limits on “normal growth” prior to that time. The SIFT Legislation will subject the Trust to taxation, which will materially reduce the amount of cash available for distributions to the Unitholders. Commencing on January 1, 2011, the SIFT Legislation will, subject to the availability of tax pools, reduce the amount of cash available to the Trust to distribute to its Unitholders. Under the current SIFT Legislation, the proposed tax will be 29.5 percent in 2011 and 28 percent in 2012, based upon a 13 percent provincial tax rate and a federal tax rate of 16.5 percent reducing to 15 percent in 2012. On February 26, 2008, the Minister released the federal budget (the “Budget”). The Budget proposes to replace this 13 percent provincial tax rate with the applicable provincial income tax rates for each province in which the SIFT has a permanent establishment, based on a provincial allocation formula. To simplify the application of the SIFT Legislation, we have assumed a provincial tax rate of 10 percent, being the applicable rate in Alberta where we anticipate 78 percent of our revenue will be generated in 2008. In accordance with this assumption and subject to the availability of tax pools, the application of the SIFT Legislation will reduce the amount of cash available to the Trust to distribute to its Unitholders by an amount equal to 26.5 percent in 2011 (and by 25 percent in 2012 and thereafter) multiplied by the amount of the pre-tax income distributed by the Trust. There can be no assurance that the Budget will become law and, until it does, the proposed reduction to the provincial tax rate will not become effective. See “Certain Canadian Federal Income Tax Considerations”and “Risk Factors – The SIFT Legislation is expected to materially and adversely affect the Trust, the Unitholders and the value of the Trust Units” in this Annual Information Form. This Annual Information Form includes the impact of the SIFT Legislation on the future net revenues associated with Pengrowth’s reserves. The SIFT Legislation will not apply to distributions to the extent that they can be characterized as a return of capital. We are currently conserving tax pools rather than reducing the present taxability of distributions. As at December 31, 2007, Pengrowth has tax pools totaling approximately $2.8 billion that it can use, in part, to reduce the impact of the SIFT Legislation.

Pursuant to amendments to the Tax Act, interest on the Debentures which is paid or credited, or which is deemed to be paid or credited, to a non-resident of Canada is, effective January 1, 2008, no longer subject to Canadian withholding tax, provided that the beneficial recipient of such interest deals at arm’s length (within the meaning of the Tax Act) with the Trust at all material times.

Greenhouse Gas Emissions

Greenhouse gas (“GHG”) emission limitations are expected to impact the oil and gas business, including Pengrowth. Provincial (Alberta) rules were released in 2007 with the Federal rules proposed to be released in 2008. The exact impact of the Federal rules is unknown at this time, but there may be a financial impact on Pengrowth in connection with its efforts to meet these emission reduction requirements. The Alberta system requires facilities that emit more than 100,000 tonnes of GHG’s per year to reduce their emission intensity by 12

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percent over the 2005-2007 three year average. Pengrowth currently operates two facilities that exceed the 100,000 tonne limit. Under the Alberta regulations, if the emissions remain at current levels, Pengrowth is required to contribute approximately $500,000 to the fund annually.

Borrowing

On June 15, 2007, the Corporation entered into a new $1.2 billion extendible revolving term credit facility syndicated among eleven financial institutions (the “Credit Facility”). The Credit Facility is unsecured, covenant based and has a three-year term. The Corporation 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 0.60 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. In addition, Pengrowth has a $35 million demand operating line of credit for working capital purposes. As at December 31, 2007, availability under the Credit Facility and the demand operating line of credit were reduced by drawings of $514 million and by outstanding letters of credit in the amount of approximately $11 million.

Under the credit agreement relating to the Credit Facility, the Trust is restricted from making distributions under certain circumstances. See“Distributions – Restrictions on Distributions”.

The terms of the credit agreement relating to the Credit Facility ensure that the lenders have priority over the Unitholders with respect to the assets and income of the Trust. In the event that we default on our debts, amounts due and owing to the lenders under the credit facility must be paid before any distribution can be made to Unitholders. This could result in an interruption of distributions. See“Risk Factors – Our indebtedness may limit the amount of distributions that we are able to pay our Unitholders, and if we default on our debts, the net proceeds of any foreclosure sale would be allocated to the repayment of our lenders, note holders and other creditors and only the remainder, if any, would be available for distribution to our Unitholders”.

CP Acquisition

On January 22, 2007 Pengrowth closed the acquisition of entities that held certain properties from ConocoPhillips Canada 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 acquired properties provided Pengrowth with 64.7 MMboe of Total Proved Plus Probable Reserves at close (Pengrowth Company Interest based on GLJ forecast prices and costs) prior to Pengrowth’s asset rationalization program and were balanced evenly between natural gas and crude oil. The properties provide a wide range of opportunities to add value through 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 added more than 375,000 net acres of undeveloped land and approximately 9,300 kilometres of proprietary 2-D seismic and interests in over 50 3-D seismic surveys.

The acquired 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 which yielded total gross proceeds of $461,035,000 and from the proceeds of a $600,000,000 bridge credit facility, which has since been repaid in full.

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Historical Developments

Pengrowth has grown throughout its history through an active program of acquisitions and financings and through development and exploration activities on its properties. Since 1988, Pengrowth has completed more than 57 acquisitions and has raised in excess of $3.7 billion through 21 public equity offerings. As at December 31, 2007, Pengrowth has distributed approximately $3.4 billion to Unitholders.

On October 2, 2006 Pengrowth completed a strategic business combination with Esprit Energy Trust, and issued 34,725,157 Trust Units to holders of Esprit trust units. Pengrowth added approximately 60.7 MMboe of Total Proved Plus Probable Reserves and 250,000 net acres of undeveloped land. The Esprit assets include long-life natural gas assets, shallow gas and CBM potential in core areas of Pengrowth expertise.

On September 28, 2006, Pengrowth completed the acquisition from ExxonMobil Canada Energy of 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 provided the addition of approximately 19 MMboe of Total Proved Plus Probable Reserves and was funded by a portion of the proceeds from Pengrowth’s September 28, 2006 equity offering of 23,310,000 Trust Units at a price of $22.60 per Trust Unit which yielded total gross proceeds of $526,806,000.

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”.

On January 12, 2006, Pengrowth announced certain transactions with Monterey under which Pengrowth sold approximately 1,000 boepd of production for $22 million cash and 8,000,000 shares in Monterey. Pengrowth currently holds approximately 32 percent of the common shares of Monterey. A senior officer of the Corporation is a member of the Board of Directors of Monterey.

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. Interest on these notes is payable semi-annually.

On April 29, 2005, pursuant to a Plan of Arrangement under theBusiness 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.

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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, before adjustments from the October 1, 2004 effective date to the closing date.

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 the 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 August 12, 2004, Pengrowth acquired an additional 34.35 percent working interest in Pengrowth operated Kaybob Notikewin Gas Unit, adding approximately 2 MMboe of Total Proved Plus Probable Reserves for $20 million before adjustments. The acquisition increased Pengrowth’s working interest in the unit to 99 percent.

On July 27, 2004, in response to proposed changes in federal income tax legislation that would have impacted Pengrowth’s status as a mutual fund trust, 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 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 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 April 23, 2003, Pengrowth completed a U.S. $200 million private placement of senior unsecured notes to a group of U.S. investors (the “2003 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.

In November of 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 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.

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.

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

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

On November 10, 2000, the Trust issued 8,165,000 Trust Units to raise gross proceeds of $155.1 million, 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 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.

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.

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.

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 $12.4 million which were used to pay for the Royalty Units. An additional 56,500 Royalty Units were also issued in the public offering, all of which are now held by the Trust.

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.

Increases or decreases in the Canadian dollar relative to the U.S. 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 U.S. dollars or based on pricing linked to U.S. dollars. Also, Pengrowth’s operating expenses and capital costs are currently primarily paid in Canadian dollars, reducing or increasing margins as the Canadian dollar fluctuates against the U.S. dollar.

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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, 2007.

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, financing arrangements and operations. The Manager has focused to date 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. In addition, in response to the SIFT Legislation, and other competitive factors, the Manager is also examining opportunities to acquire international oil and gas properties.

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 three-year terms with a declining fee structure in the second three year term;

• a base fee determined on a sliding scale:

o in the first three year contract term:

§	two percent of the first $200 million of Income; and
§	one percent of the balance of Income over $200 million; and

o 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 eight percent per annum over a three year period;

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• 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, the Manager defers to the authority of the Board of Directors. 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.

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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 determined in March of 2006 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 until its expiry on June 30, 2009. A special committee of the Board of Directors, comprised of all independent members of the Board, was formed for the purpose of advising the Board in connection with all matters pertaining to the orderly transition to a traditional corporate management structure at the end of the term.

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PENGROWTH – OPERATIONAL INFORMATION

As at December 31, 2007, the Corporation had 568 permanent employees. The Corporation has invested more than $7 billion in the energy sector primarily to purchase mature, proven producing oil and natural gas properties in Canada and to invest in developing these properties.

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 8, 2008 in respect of the oil and gas properties of Pengrowth effective December 31, 2007. All reserves data presented under this sub-heading is from the GLJ Report. In addition, the following table contains Pengrowth’s average daily production of oil, natural gas and NGLs for the year ended December 31, 2007. Pengrowth’s producing properties as of December 31, 2007 are summarized in the following table:

Summary of Company Interest
at December 31, 2007⁽¹⁾
(Forecast Prices and Costs)

							P+P
							Value
					Reserve		Before Tax
	P+P		Remaining		Life		at 10%		2007 Oil		2007 Gas		2007 NGL		2007 Total
	Reserves(3)		ReserveLife		Index		Discount		Production		Production		Production		Production
Field	Mboe)		(years)		(years)		($MM)		(bblpd)		(MMcfd)		(bblpd)		(boepd)(3)
Light Oil
Judy Creek		40,447		50		13.3		797.9		7,359		4.1		1,529		9,564
Weyburn		21,966		44		21.1		345.0		2,779		—		—		2,779
Swan Hills		17,593		50		20.1		255.1		1,968		1.5		280		2,505
Carson Creek		15,194		34		11.9		311.6		2,031		3.8		505		3,169
Fenn Big Valley		5,998		28		8.8		104.5		632		6.1		54		1,703
Deer Mountain		5,264		45		19.7		101.4		543		0.1		60		618
Other(2)		35,143				9.8		883.8		8,908		9.8		708		11,256
Sub-Total		141,605				13.1		2,799.3		24,220		25.4		3,136		31,594
Heavy Oil
Jenner		7,728		23		7.2		155.1		2,890		1.5		4		3,144
Bodo		7,658		41		12.6		107.9		1,439		2.5		—		1,862
Tangleflags		5,321		25		7.3		56.2		1,910		0.2		—		1,951
Other(2)		5,060				8.6		61.9		970		5.6		—		1,902
Sub-Total		25,767				8.6		381.1		7,209		9.9		4		8,859
Conventional Gas
Olds		26,615		48		16.4		293.1		12		25.0		769		4,952
Harmattan		10,857		36		7.9		178.8		346		10.3		932		2,993
Dunvegan		6,204		40		10.4		85.0		35		8.1		444		1,835
Quirk Creek		5,134		38		10.5		77.9		—		3.6		214		820
Kaybob		4,078		38		13.7		45.6		—		4.2		37		736
McLeod River		3,688		41		7.1		61.1		7		6.4		250		1,316
Blackstone		3,588		24		10.3		49.4		—		6.1		—		1,025
Carson Creek		2,958		39		5.2		50.6		—		6.2		397		1,430
Other(2)		18,788				7.3		309.1		523		43.7		1,332		9,137
Sub-Total		81,910				9.7		1,150.6		923		113.7		4,375		24,242

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							P+P
							Value
					Reserve		Before Tax
	P+P		Remaining		Life		at 10%		2007 Oil		2007 Gas		2007 NGL		2007 Total
	Reserves(3)		ReserveLife		Index		Discount		Production		Production		Production		Production
Field	Mboe)		(years)		(years)		($MM)		(bblpd)		(MMcfd)		(bblpd)		(boepd)(3)
Shallow Gas
Three Hills/Twining		13,704		50		10.2		218.2		537		17.7		447		3,939
Coal Bed Methane		9,312		41		11.3		123.9		1		6.2		6		1,032
Monogram		8,044		32		8.9		127.0		—		12.1		—		2,015
Jenner		7,435		33		9.4		90.7		4		11.5		2		1,922
Lethbridge		3,685		50		7.6		51.2		—		7.2		—		1,193
Other(2)		16,728				10.0		247.5		600		30.2		18		5,713
Sub-Total		58,908				9.9		858.4		1,142		84.8		533		15,813
Offshore Gas
Sable Island		11,731		9		4.3		266.6		—		33.2		1,362		6,895
Sub-Total		11,731				4.3		266.6		—		33.2		1,362		6,895
Total		319,921				10.4		5,455.9		33,495		267.0		9,409		87,401

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)	“Other” includes Pengrowth’s Working Interests and Royalty Interests in approximately 100 other properties.
(3)	Natural gas has been converted to barrels of oil equivalent on the basis of six Mcf of natural gas being equal to one barrel of oil.

Light Oil Properties

Judy Creek

Pengrowth has a 100 percent working interest in both the Judy Creek Beaverhill Lake Unit and the Judy Creek West Beaverhill Lake Unit (together called “Judy Creek”). Pengrowth also has 54.4 percent working interest in the Judy Creek Gas Conservation Plant that services a number of other properties in the area including Swan Hills, Virginia Hills and South Swan Hills. Judy Creek is located approximately 200 kilometres northeast of Edmonton, Alberta and covers an area of approximately 155 square kilometres. Judy Creek was discovered in 1959, placed on waterflood in 1962 and hydrocarbon miscible flood in 1985. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2007 are estimated to be 40.4 MMboe. The Remaining Reserve Life is 50 years and the Reserve Life Index is 13.3 years. Pengrowth’s Company Interest production for Judy Creek averaged 9,564 boepd in 2007.

     2007 Development Activity

Four new miscible patterns were initiated in Judy Creek Beaverhill Lake Unit with a total expected recovery of 670 Mboe. Four infill wells were drilled and completed (one horizontal producer and three injectors). The initial oil rate for the horizontal producer well was 200 bblpd. The injection wells drilled complete three new miscible patterns, two of which started injection in the third quarter of 2007 and one will start injection in the second quarter of 2008. Nine reactivations and twelve recompletions were completed in 2007, which collectively added 915 bblpd.

     Carbon Dioxide (CO₂) Pilot

The overall scope of this CO₂ pilot project is to inject gas at a miscible pressure to determine the feasibility of recovering remaining oil, as well as ethane, left behind from the hydrocarbon miscible flood. The injected gas consists of trucked in CO₂ and acid gas which consists mainly of CO₂ and hydrogen sulfide (H₂S) from the Judy Creek Gas Conservation Plant. CO₂ injection commenced in February of 2007, while acid gas injection commenced in April of 2007. Even though the pilot was in its early stages, minor oil and gas response from a producer was observed in March of 2007. The other producers in the pattern began responding in the second quarter. The response is evidenced by incremental ethane, methane, oil and recycling CO₂. Pengrowth is encouraged by the response to date, and, as a result, Pengrowth intends to continue the pilot project through 2008.

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     2008 Development Activity

Two new miscible patterns are currently being developed in the Judy Creek A Pool for 2008. Both patterns are expected to commence injection in the third quarter. The 2008 drilling program will involve two to five infill wells with the primary focus on creating new miscible patterns. Ten to fifteen recompletions are planned throughout 2008 and we plan to reshoot seismic over the CO₂ pilot to help monitor the flood.

Weyburn Unit

Pengrowth holds a 9.76 percent non-operating working interest in the Weyburn Unit in southeast Saskatchewan. Oil is produced from the Midale carbonate reservoir under waterflood and a CO₂ miscible flood enhanced recovery program. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2007 are estimated to be 22 MMboe. The Remaining Reserve Life is 44 years and the Reserve Life Index is 21.1 years. Pengrowth’s Company Interest production for Weyburn averaged 2,779 boepd in 2007.

     2007 Development Activity

A total of 58 horizontal infill and re-entry wells were drilled in 2007. Of the over 90 forecasted total CO₂ miscible flood patterns, 46 patterns have been developed through the end of 2007. Current CO₂ supply is 125 MMcfpd under contract.

     2008 Development Activity

Building on the success of the infill drilling programs over the last few years, an additional 46 wells are planned for 2008. The 2008 development program also includes ten new CO₂ miscible flood patterns.

Swan Hills

Pengrowth holds a 22.34 percent non-operating working interest in the Swan Hills Unit No. 1 located near the Judy Creek field in north central Alberta. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2007 are estimated to be 17.6 MMboe. The Remaining Reserve Life is 50 years and the Reserve Life Index is 20.1 years. Pengrowth’s Company Interest production for Swan Hills averaged 2,505 boepd in 2007.

     2007 Development Activity

In 2007, seven new 80 acre infill wells were drilled, three in the northwest area and four in the west area of the unit. Two new 80 acre hydrocarbon miscible flood patterns were developed including the drilling of two new wells. Injection into these patterns is scheduled to commence in early 2008. A pilot project 40 acre hydrocarbon miscible flood pattern was developed by down-spacing an existing pattern with five new wells. Water will be injected into the pattern for approximately one year before solvent injection commences in early 2009. In addition, three wells were recompleted and two wells were reactivated.

     2008 Development Activity

The 2008 development plans include drilling eight new 80 acre infill wells, developing three new 80 acre hydrocarbon miscible flood patterns including the drilling of three new wells, and a variety of well recompletions, suspended well reactivations and artificial lift upgrades.

Carson Creek – Light Oil

Carson Creek is located 160 kilometres northwest of Edmonton, Alberta and is comprised of two Pengrowth-operated units (one mainly oil and one mainly gas) which cover approximately 187 square kilometres. The Carson Creek North Unit (mainly oil) in which Pengrowth has an 87.5 percent working interest was discovered in 1958 and the current waterflood was initiated in 1964. Remaining Company Interest Total Proved

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Plus Probable Reserves at December 31, 2007 are estimated to be 15.2 MMboe. The Remaining Reserve Life is 34 years and the Reserve Life Index is 11.9 years. Pengrowth’s Company Interest production for the Carson Creek North Unit averaged 2,031 boepd in 2007.

     2007 Development Activity

Pengrowth’s 2007 activities included drilling one new Beaverhill Lake oil producer with an average initial rate of 75bblpd. Other activities included 136 square kilometres of 3D seismic over the Carson Creek North Unit acreage, reservoir, evaluation, waterflood optimization, and well workovers to improve production.

     2008 Development Activity

Pengrowth anticipates drilling up to six wells in the Carson Creek North Unit as well as ongoing waterflood optimization and well work-over programs.

Fenn Big Valley

Fenn Big Valley is located 130 kilometres northeast of Calgary, Alberta. Pengrowth has high working interests (mostly 100 percent) in several oil pools producing from the Nisku and Leduc formations. The Nisku production currently accounts for approximately 80 percent of the oil production at an average water cut of 97 percent. The field was placed on production in 1953 and has produced approximately 62 percent of the original oil in place under natural water drive. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2007 are estimated to be 6 MMboe. The Remaining Reserve Life is 28 years and the Reserve Life Index is 8.8 years. Pengrowth’s Company Interest production for Fenn Big Valley averaged 1,703 boepd in 2007.

     2007 Development Activity

Pengrowth’s 2007 activity consisted of some well workovers and maintenance. There was no drilling activity in 2007.

     2008 Development Activity

Pengrowth’s 2008 activities will include shooting 90 square kilometres of 3D seismic over the southern and northern regions to supplement the existing 3D seismic over the central region, drilling seven Nisku attic oil targets, and drilling two stepout wells. In addition, CO₂ flood feasibility will be evaluated.

Deer Mountain Unit No. 1

Deer Mountain is located 190 kilometres northwest of Edmonton, Alberta, and is comprised of a Pengrowth-operated unit which covers approximately 26 square kilometres and four non-unit wells. An incremental 70.44 percent working interest and operatorship was obtained from ConocoPhillips on January 22, 2007. Pengrowth now has an 85.42 percent working interest in Deer Mountain Unit No. 1 and 67 to 100 percent working interest in the non-unit wells. A waterflood scheme has been operating in Deer Mountain Unit No. 1 since September 1968. Injection water consists of produced water from the field and some fresh water make-up from a local river. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2007 are estimated to be 5.3 MMboe. The Remaining Reserve Life is 45 years and the Reserve Life Index is 19.7 years. Pengrowth’s Company Interest production for Deer Mountain averaged 618 boepd in 2007.

     2007 Development Activity

Pengrowth’s 2007 activities included acid-fracturing four producing wells, continuing waterflood management as well as evaluation of alternative water sources for the waterflood.

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     2008 Development Activity

Pengrowth’s 2008 activities will include completion of the field modifications to utilize subsurface water instead of surface water for the waterflood, drilling one new Beaverhill Lake producer, workover of a water injector, re-activation of a well and facilities, and acid fracturing two more producers.

Heavy Oil Properties

Jenner – Heavy Oil

The Jenner Oil Property is located approximately 250 kilometres east of Calgary, Alberta. Pengrowth has an average working interest of 94.5 percent in the north pool and an average working interest of 86.6 percent in the south pool. Pengrowth operates all of the production within this property. Oil quality ranges from 14° to 20° API and is produced from Upper Mannville Sands. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2007 are estimated to be 7.7 MMboe. The Remaining Reserve Life is 23 years and the Reserve Life Index is 7.2 years. Pengrowth’s Company Interest production for Jenner averaged 3,144 boepd in 2007.

     2007 Development Activity

Pengrowth’s 2007 development activities were focused on production and the optimization of operating costs.

     2008 Development Activity

The 2008 development activities will include the drilling of several horizontal and vertical wells, in addition to various water handling improvements and production optimization.

Bodo

The Bodo heavy oil properties straddle the Alberta-Saskatchewan border and produce mainly 12° API oil from the McLaren formation and 15° API oil from the Lloydminster formation. Pengrowth operates several batteries to treat oil, as well as a number of compressor stations to process solution and non-associated gas. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2007 are estimated to be 7.7 MMboe. The Remaining Reserve Life is 41 years and the Reserve Life Index is 12.6 years. Pengrowth’s Company Interest production for Bodo averaged 1,862 boepd in 2007.

     2007 Development Activity

No development activity occurred in 2007; however, operating activity focused on waterflood management improvements and the polymer flood pilot.

     2008 Development Activity

Ongoing surveillance of both the waterflood and polymer flood will continue, and optimization of the flood will be evaluated and executed in 2008. Continued simulation of the polymer flood using the recent production/injection information will improve the analysis of the polymer flood. The benefit of a polymer flood over conventional waterflood is improved oil recovery.

Tangleflags

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

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The EOR 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 below the injection wells near the base of the reservoir. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2007 are estimated to be 5.3 MMboe. The Remaining Reserve Life is 25 years and the Reserve Life Index is 7.3 years. Pengrowth’s Company Interest production for Tangleflags averaged 1,951 boepd in 2007.

     2007 Development Activity

Pengrowth’s 2007 activities included starting thirteen wells from a late 2006 infill drilling program that was designed to take advantage of residual heat from the mature steam chamber. The wells have been brought on stream slowly to mitigate risk of produced sand. Therefore, the final result of this infill program is not yet known. Several wells were recompleted to take advantage of incremental oil and heat that is escaping the steam chamber.

     2008 Development Activity

In 2008, we expect to closely monitor and manage steam injection and associated operating costs. A few additional recompletions are planned.

Conventional Gas Properties

Olds

The Olds property is Pengrowth’s largest operated gas property, located 95 kilometres north of Calgary, Alberta. Pengrowth’s interests include 100 percent ownership in the Olds Gas Unit No. 1. In addition, Pengrowth has a 75 percent average working interest in non-Unit reserves. The Olds Unit produces sour natural gas from the Wabamun Formation, with H₂S concentrations ranging from less than one to 35 percent. The non-Unit reserves are contained within formations from the Wabamun to the Edmonton group, and are predominantly sweet natural gas. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2007 are estimated to be 26.6 MMboe. The Remaining Reserve Life is 48 years and the Reserve Life Index is 16.4 years. Pengrowth’s Company Interest production for Olds averaged 4,952 boepd in 2007.

Pengrowth operates and owns 100 percent of 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 volumes processed.

     2007 Development Activity

The 2007 activities in Olds focused on pipeline and compression improvements that essentially kept production constant for the year. Solvent washes on several of the Wabamun wells were also performed, with increases of up to 700 Mcfpd in initial production. Subsurface modeling of the Wabamun began in order to identify un-drained sections.

     2008 Development Activity

Development plans for 2008 include three to five new drills, six to ten recompletions and workovers, as well as continued compression improvements.

Harmattan

The Harmattan gas field is located approximately 90 kilometres northwest of Calgary, Alberta. It is comprised of wells and pools in formations from the Cardium to the Wabamun, as well as two partner-operated Elkton Units. The production is predominantly sweet natural gas with working interests averaging 55 percent in the non-Unit

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lands and 25 percent in the Units. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2007 are estimated to be 10.9 MMboe. The Remaining Reserve Life is 36 years and the Reserve Life Index is 10.9 years. Pengrowth’s Company Interest production for Harmattan averaged 2,993 boepd in 2007.

     2007 Development Activity

Several high rate Elkton wells have been drilled in the Harmattan area in recent years, and in 2007 Pengrowth drilled a successful Elkton well capable of over two MMcfpd. Results are still being analyzed, and follow-up locations are being evaluated. The well will be tied-in in early 2008. A second drill successfully tested in the Lower Mannville zone, and is currently producing at a restricted rate of 1.3 MMcfpd. Extensive modeling was also done on pipelines and compression, with the view of bringing Pengrowth production currently going to third party facilities to the Olds plant. Land activity included a successful farm-in on an industry partner with work to be completed in 2008.

     2008 Development Activity

The activity for 2008 includes two to three new drills, along with several recompletions. The pipeline and compression work modeled in 2007 will also be implemented.

Dunvegan Gas Unit No. 1

The Dunvegan Gas Unit No. 1 is located 430 kilometres northwest of Edmonton, Alberta in the Peace River area. The partner-operated Dunvegan natural gas field in which Pengrowth has a 10.37 percent working interest has over 200 producing wells and covers an area of 213 square kilometres. Approximately 95 percent of the Unit’s identified natural gas reserves are contained in the Mississippian Debolt formation. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2007 are estimated to be 6.2 MMboe. The Remaining Reserve Life is 40 years and the Reserve Life Index is 10.4 years. Pengrowth’s Company Interest production for Dunvegan averaged 1,835 boepd in 2007.

     2007 Development Activity

There were seven successful wells drilled in 2007 as well as compression and other optimization activity.

     2008 Development Activity

The 2008 activity will include ten new drilling locations, five optimization/recompletion projects, and additional compression.

Quirk Creek

The Quirk Creek asset is located approximately 50 kilometres southwest of Calgary, Alberta, and is comprised of several highly permeable pools contained within thrust sheets carrying Mississippian reservoirs. Pengrowth holds a 68 percent working interest in four producing Rundle deep plate gas wells, a 31 percent working interest in ten producing Rundle upper plate gas wells, a 25 percent working interest in three producing gas wells in Millarville and a 30.5 percent working interest in the Quirk Creek Natural Gas Plant. The natural gas production averages nine percent sour natural gas, with associated liquids. Quirk Creek has been producing since the late 1960’s, but a new well drilled in 2006, the first in 25 years, extended the structure’s potential. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2007 are estimated to be 5.1 MMboe. The Remaining Reserve Life is 38 years and the Reserve Life Index is 10.1 years. Pengrowth’s Company Interest production for Quirk Creek averaged 820 boepd in 2007.

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     2007 Development Activity

Activity in 2007 focused on plant upgrades. The 2007 plant turnaround identified problems with a sulphur condenser and a waste heat reboiler, which proved to be time-consuming to repair.

     2008 Development Activity

Activity will focus on the preparations needed to drill one to three new wells in early 2009, targeting a new thrust sheet as well as currently producing sheets.

Kaybob

The Kaybob Notikewin Unit No. 1 is located approximately 240 kilometres 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 the Unit began in 1962. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2007 are estimated to be 4.1 MMboe. The Remaining Reserve Life is 38 years and the Reserve Life Index is 13.7 years. Pengrowth’s Company Interest production for Kaybob averaged 736 boepd in 2007.

     2007 Development Activity

No development activity occurred in respect of the Kaybob property in 2007.

     2008 Development Activity

Pengrowth anticipates drilling three Kaybob Notikewin Unit wells in 2008.

McLeod River

The McLeod River property is located approximately 110 kilometres west of Edmonton, Alberta. Pengrowth holds various interests in 87 wells in the property ranging from 16.7 to 100 percent. Conventional gas is produced from the Rock Creek, Gething, Notikewin and Cardium formations. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2007 are estimated to be 3.7 MMboe. The Remaining Reserve Life is 41 years and the Reserve Life Index is 7.1 years. Pengrowth’s Company Interest production for McLeod River averaged 1,316 boepd in 2007.

     2007 Development Activity

Pengrowth’s 2007 development activity included the drilling of a Cardium oil well.

     2008 Development Activity

The activities for 2008 include one Gething recompletion as well as purchasing 2D seismic over the McLeod River area. Pengrowth will also be conducting a study to evaluate the rock properties to determine the best completion and work-over methods to improve well productivity in the area.

Blackstone

Blackstone is located approximately 180 kilometres northwest of Red Deer, Alberta. Pengrowth holds a 50 percent working interest in one producing conventional gas well. This well was drilled into the Blackstone Beaverhill Lake A Pool and was placed on production in January 2002. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2007 are estimated to be 3.6 MMboe. The Remaining Reserve Life is 24 years and the Reserve Life Index is 10.3 years. Pengrowth’s Company Interest production for Blackstone averaged 1,025 boepd in 2007.

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     2007 Development Activity

There was no development activity on the Blackstone property in 2007.

     2008 Development Activity

No activity is anticipated on the Blackstone property in 2008.

Carson Creek – Conventional Gas

Carson Creek is located 160 kilometres northwest of Edmonton, Alberta and is comprised of two Pengrowth-operated Units (one mainly oil and one mainly gas) which cover approximately 187 square kilometres. The Carson Creek Beaverhill Lake Unit No. 1 (mainly gas), in which Pengrowth has a 95.1 percent working interest, was discovered in 1958. From 1962 to 1985, a lean gas cycling scheme to strip natural gas liquids from the liquid-rich natural gas was operational; during this period the lean gas was re-injected. Gas re-injection now only occurs during plant disruption. There are also non-Unit lands in which Pengrowth has a 24 to 95 percent working interest. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2007 are estimated to be 3.0 MMboe. The Remaining Reserve Life is 39 years and the Reserve Life Index is 5.2 years. Pengrowth’s Company Interest production for Carson Creek gas averaged 1,430 boepd in 2007.

Pengrowth has a 95.12 percent working interest in the Carson Creek Gas plant, which processes the gas production.

     2007 Development Activity

The main development activity in 2007 included the drilling of one non-Unit gas well with an initial rate of 450 Mcfpd, additional activity consisted of compression work and well re-activations.

     2008 Development Activity

The activity anticipated for 2008 consists of drilling one to two Swan Hills gas wells.

Shallow Gas Properties

Twining/Three Hills Creek

The Twining/Three Hills Creek property is located 130 kilometres northeast of Calgary, Alberta. Although production is mainly gas, there is oil production from this area. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2007 are estimated to be 13.7 MMboe. The Remaining Reserve Life is 50 years and the Reserve Life Index is 10.2 years. Pengrowth’s Company Interest production for Twining/Three Hills Creek averaged 3,939 boepd in 2007.

     2007 Development Activity

Development activity in 2007 included the drilling of six oil wells and one natural gas well that added 664 Mboe of reserves and 258 boepd of production.

     2008 Development Activity

Pengrowth’s 2008 development activities include drilling up to twelve oil wells and four gas wells.

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Coal Bed Methane (CBM)

Pengrowth’s CBM activity is focused in the Ghost Pine, Fenn Big Valley, Twining and Olds areas which are 100 to 160 kilometres northeast of Calgary, Alberta. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2007 are estimated to be 9.3 MMboe. The Remaining Reserve Life is 41 years and the Reserve Life Index is 11.3 years. Pengrowth’s Company Interest production for CBM averaged 1,032 boepd in 2007.

     2007 Development Activity

A total of 16 wells were drilled or re-completed in the Horseshoe Canyon Formation and Pengrowth drilled its first Mannville CBM well in the Fenn Big Valley area. The North Twining CBM compressor system was commissioned in February of 2007 and gathering systems were installed in the Twining and Ghost Pine areas that allowed 58 wells drilled in 2006 to be put on stream in 2007. Pengrowth also participated in 60 partner operated wells and earned working interests in two CBM compressor facilities. Many of the wells came on stream late in 2007 which resulted in December production averaging 2,059 boepd.

     2008 Development Activity

Plans for 2008 include drilling 44 Horseshoe Canyon wells and four Mannville horizontal wells.

Monogram Gas Unit

The Monogram Gas Unit is located approximately 140 miles southeast of Calgary, Alberta. Pengrowth holds a 53.82 percent working interest in the partner-operated Unit. Gas production from the Unit is in the shallow Medicine Hat, Milk River and Second White Specks formations. The Monogram Unit was unitized June 1, 1975. There were some test holes drilled in the 1950’s but the first wells drilled within the Unit boundary were 13 wells drilled in 1971. By the end of 1989, 448 wells had been drilled with 844 drilled by the end of 2007. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2007 are estimated to be 8.0 MMboe. The Remaining Reserve Life is 32 years and the Reserve Life Index is 8.9 years. Pengrowth’s Company Interest production for Monogram averaged 2,015 boepd in 2007.

     2007 Development Activity

There were 120 infill wells drilled in the last quarter of 2007. All will be tied in and producing in 2008.

     2008 Development Activity

The 2008 plan is to drill 47 directional and 13 vertical wells in the first quarter and another 115 wells in the third and fourth quarters for a total of 175 wells in 2008.

Jenner – Shallow Gas

The Jenner shallow gas property is located 250 kilometres east of Calgary, Alberta. Production from this property is primarily from the Milk River, Medicine Hat and Second White Specks formations within the Jenner, Atlee Buffalo and Atlee fields. Pengrowth has an average working interest of 63.3 percent and operates the majority of the production. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2007 are estimated to be 7.4 MMboe. The Remaining Reserve Life is 33 years and the Reserve Life Index is 9.4 years. Pengrowth’s Company Interest production for Jenner Shallow Gas averaged 1,922 boepd in 2007.

     2007 Development Activity

Pengrowth’s 2007 development activities were focused around improving efficiencies in gas well de-watering and reducing operating costs.

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     2008 Development Activity

The 2008 development activities will be a continuation from the successes achieved in 2007 and will include the completion of a Pengrowth owned and operated swab water disposal facility. Numerous down spacing opportunities exist within the property and will be prepared for execution.

Lethbridge

Pengrowth’s operations in the Lethbridge, Alberta area cover a large area and include operating over 250 wells, many of which are 100 percent working interest. All wells produce sweet gas from the Milk River and Bow Island formations at an average production rate of 29 Mcfpd. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2007 are estimated to be 3.7 MMboe. The Remaining Reserve Life is 50 years and the Reserve Life Index is 7.6 years. Pengrowth’s Company Interest production for Lethbridge averaged 1,193 boepd in 2007.

     2007 Development Activity

During 2007, Pengrowth performed 20 coil cleanouts, mostly during the fourth quarter. The coil cleanouts on ten of the wells indicated a production increase of between 26 and 260 Mcfpd. With this type of production increase, the low-cost coil cleanouts are paid out in a few days.

     2008 Development Activity

The planned activities for 2008 are a continued well workover program, installing smaller production tubing to improve de-watering of wells, optimize or reconfigure compressors and recomplete or commingle Milk River zones of selected wells.

Offshore Gas Properties

Sable Offshore Energy Project (SOEP)

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

In 2007, gross production started at 300 MMcfpd and increased to just under 500 MMcfpd by May as a result of the new compression facility. For the remainder of the year, production stayed at or above 400 MMcfpd with the exception of a planned turn-around in October. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2007 are estimated to be 11.7 MMboe. The Remaining Reserve Life is 9 years and the Reserve Life Index is 4.3 years. Pengrowth’s Company Interest production for SOEP averaged 6,895 boepd in 2007.

     2007 Development Activity

The 2007 activities at SOEP included the continued computer modeling of the fields to identify the best methods to maximize gas recovery, the completion of the compressor installation and a series of well workovers. Two well workovers scheduled for 2007 have been delayed as the total production rate remains better than anticipated.

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     2008 Development Activity

Projects for 2008 include an improved water handling system for the North Triumph platform and two sand cleanouts if the wells decline enough. Also, one or two drilling locations for the 2009/2010 drilling season will be finalized. In 2009, there will be a drilling rig off the east coast of Canada drilling at another project; it is anticipated that the rig could drill one or two locations for SOEP while it is in the area.

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Statement of Oil and Gas Reserves and Reserves Data

Disclosure of Reserves Data

The information in this section is based upon an evaluation by GLJ with an effective date of December 31, 2007 contained in the GLJ Report dated February 8, 2008, and was prepared in accordance with NI 51-101, with the exception of information relating to income tax and the after tax future net revenues associated with our reserves, which were determined by Pengrowth. The effective date of the information in this section is December 31, 2007 and the preparation date of the information is January 15, 2008. The information in this section summarizes the oil, liquids and natural gas reserves of Pengrowth and the net present values of future net revenue for these reserves using GLJ’s forecast prices and costs and constant 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.

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, 2007 contained in the GLJ Report dated February 8, 2008. 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 Trust’s future net revenues associated with the reserves contained in this Annual Information Form do not reflect the impact of the proposed changes to royalties payable to the Government of Alberta.Based on the interpretations of the proposed royalty changes by GLJ, it is anticipated that the new royalty regime will result in a 12 to 18 percent increase in the total royalties paid to all parties by Pengrowth as compared to the current royalty structure. This increase is expected to result in a decline in the net present value, discounted at 10 percent, of the future net revenues associated with (i) Pengrowth’s Proved Reserves of three to five percent; and (ii) Pengrowth’s Proved Plus Probable Reserves of three to five percent, in both cases using the January 2008 commodity price assumptions of GLJ.See “General Development of Pengrowth Energy Trust – Recent Developments – Changes to Royalty Legislation Affecting Pengrowth and its Unitholders”.

The Alberta Royalty Tax Credit program was 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 Report which have been prepared in accordance with the standards contained in the Canadian Oil and Gas Evaluation (“COGE”) Handbook and the reserves definitions contained in NI 51-101 and the Canadian Oil and Gas Evaluation Handbook. The GLJ Report incorporates estimates of future well abandonment obligations but does not include estimates of remediation costs.The GLJ forecasts of future net 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 future net cash flow and present value of future net revenue after income taxes were determined by Pengrowth after taking into account the impact of the SIFT Legislation.Our estimate of income tax in the foregoing analysis makes use of the following assumptions:

• SIFT tax starting January 2011 at 26.5 percent (and 25 percent in 2012 and thereafter) and corporate taxes as currently expected;

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• Annual general and administration expenses at the current level;

• Interest expense at the current level;

• Inclusion of tax pools and deductions at the trust level as well as at the operating entity level;

• Royalties paid to the Trust in the amount of the operating income;

• Distributions to Unitholders; and

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

The net cash flows estimated in the GLJ Report 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 cash flows from operating activities reported by the Trust in its statement of cash flows. The GLJ Report does not estimate general and administrative expenses, interest and management fees.

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.

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Reserves Data (Forecast Prices and Costs)

Summary of Oil and Gas Reserves
as of December 31, 2007
(Forecast Prices and Costs)

	Light and Medium Oil						Heavy Oil						Natural Gas Liquids
	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)		(Mbbls)		(Mbbls)		(Mbbls)
Proved Reserves
Proved Developed Producing		73,509		73,350		63,961		14,682		14,674		13,196		19,920		19,813		14,312
Proved Developed Non-Producing		482		482		406		30		30		29		504		504		325
Proved Undeveloped		18,986		18,985		15,690		2,194		2,194		1,899		1,361		1,361		1,053
Total Proved Reserves		92,977		92,817		80,057		16,906		16,898		15,124		21,786		21,677		15,691
Probable Reserves		31,211		31,180		26,533		4,885		4,883		4,273		7,208		7,185		5,195
Total Proved Plus Probable Reserves		124,188		123,997		106,590		21,792		21,781		19,397		28,994		28,862		20,885

	Natural Gas						Coal Bed Methane						Total Oil Equivalent Basis(1)
	Company		Gross		Net		Company		Gross		Net		Company		Gross		Net
	Interest		Interest		Interest		Interest		Interest		Interest		Interest		Interest		Interest
Reserves Category	(MMcf)		(MMcf)		(MMcf)		(MMcf)		(MMcf)		(MMcf)		(Mboe)		(Mboe)		(Mboe)
Proved Reserves
Proved Developed Producing		547,462		543,054		437,824		21,257		20,460		19,101		202,898		201,755		167,624
Proved Developed Non-Producing		21,168		21,084		16,044		2,712		2,632		2,405		4,997		4,968		3,835
Proved Undeveloped		50,351		50,224		41,057		14,049		13,911		12,341		33,275		33,230		27,542
Total Proved Reserves		618,981		614,363		494,925		38,018		37,002		33,847		241,169		239,953		199,000
Probable Reserves		195,282		193,874		155,116		17,402		17,115		15,579		78,752		78,414		64,450
Total Proved Plus Probable Reserves		814,263		808,237		650,041		55,420		54,117		49,426		319,921		318,367		263,450

Note:
(1)	Natural gas has been converted to barrels of oil equivalent on the basis of six Mcf of natural gas being equal to one barrel of oil.

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Summary of Net Present Value
of Future Net Revenue
as of December 31, 2007
Before and After Income Taxes
(Forecast Prices and Costs)

											Unit Value Before Income Tax
	Before Income Taxes Discounted At (%/Year)										Discounted At 10%/Year(1)
	0%		5%		10%		15%		20%
Reserves Category	($MM)		($MM)		($MM)		($MM)		($MM)		$/boe		$/Mcfe
Proved Reserves
Proved Developed Producing		6,212		4,744		3,885		3,321		2,921		23.18		3.86
Proved Developed Non-Producing		134		100		79		65		55		20.57		3.43
Proved Undeveloped		1,126		688		459		322		234		16.66		2.78
Total Proved Reserves		7,473		5,532		4,423		3,708		3,210		22.22		3.70
Probable Reserves		2,960		1,602		1,033		740		565		16.03		2.67
Total Proved Plus Probable Reserves		10,433		7,134		5,456		4,448		3,775		20.71		3.45

	After Income Taxes Discounted At (%/Year)
	0%		5%		10%		15%		20%
Reserves Category	($MM)		($MM)		($MM)		($MM)		($MM)
Proved Reserves
Proved Developed Producing		5,478		4,344		3,638		3,149		2,793
Proved Developed Non-Producing		99		77		63		53		46
Proved Undeveloped		707		439		293		206		149
Total Proved Reserves		6,284		4,860		3,994		3,408		2,988
Probable Reserves		1,813		1,001		667		493		387
Total Proved Plus Probable Reserves		8,097		5,861		4,661		3,901		3,375

Note:
(1)	Unit values are based on Pengrowth’s Net reserves

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Additional Information Concerning Future Net Revenue
(undiscounted)
as of December 31, 2007
(Forecast Prices and Costs)

Future Net

Revenue

Capital

Before

Future net

Operating

Development

Abandonment

Income

Income

Revenue

Revenue

Royalties(1)

Costs

Costs

Costs(2)

Taxes

Tax

After Income

Reserves category

($MM)

($MM)

($MM)

($MM)

($MM)

($MM)

($MM)

Taxes($MM)

Proved Reserves

15,750

2,600

4,898

566

214

7,473

1,189

6,284

Total Proved Plus Probable Reserves

21,467

3,584

6,391

819

240

10,433

2,336

8,097

Notes:

(1) Royalties payable to the provinces of Alberta, British Columbia, Saskatchewan and Nova Scotia. Does not include the impact of the proposed royalty regime announced by the Government of Alberta on October 25, 2007, to become effective on January 1, 2009. Based on the interpretations by GLJ of the proposed royalty changes and based on the January 2008 commodity price assumptions of GLJ, it is anticipated that the new royalty regime will result in a 12 to 18 percent increase in the total royalties paid to all parties by Pengrowth as compared to the current royalty structure.

(2) Includes downhole abandonment cost but does not include surface reclamation costs. See “Pengrowth – Operational Information – Additional Information Concerning Abandonment & Reclamation Costs”.

Net Present Value of Future Net Revenue
By Production Group
as of December 31, 2007
(Forecast Prices and Costs)

		Future Net
		Revenue Before
		Income Taxes
		(discounted at 10%/yr)		Unit Value(3)
Reserves Category	Production Group	($MM)		($/Boe)		($/Mcf)
Total Proved Reserves	Light and Medium Crude Oil (including solution gas and other by-products)(1)		2,365		25.57		4.26
	Heavy Oil (including solution gas and other by-products)(1)		305		18.07		3.01
	Natural Gas (including by-products but excluding solution gas from oil wells)(2)		1,645		19.85		3.31
	Non-conventional Oil & Gas Activities		108		15.94		2.66
	Total		4,423		22.22		3.70
Total Proved Plus Probable Reserves	Light and Medium Crude Oil (including solution gas and other by-products)(1)		2,881		23.53		3.92
	Heavy Oil (including solution gas and other by-products)(1)		369		17.03		2.84
	Natural Gas (including by-products but excluding solution gas from oil wells)(2)		2,065		18.89		3.15
	Non-conventional Oil & Gas Activities		141		14.52		2.42
	Total		5,456		20.74		3.46

Notes:

(1)	NGL’s associated with the production of solution gas are included as a by-product.
(2)	NGL’s associated with the production of natural gas are included as a by-product.
(3)	Unit values are based on Pengrowth’s Net reserves.

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Reserves Data (Constant Prices and Costs)

Summary of Oil And Gas Reserves
as of December 31, 2007
(Constant Prices and Costs)

	Height and Medium Oil						Heavy Oil						Natural Gas Liquids
	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)		(Mbbls)		(Mbbls)		(Mbbls)
Proved Reserves
Proved Developed Producing		73,715		73,550		64,184		14,591		14,583		13,185		19,922		19,814		14,274
Proved Developed Non- Producing		1,040		1,040		914		95		95		89		559		558		381
Proved Undeveloped		19,014		19,013		15,555		2,194		2,194		1,899		1,363		1,363		1,053
Total Proved Reserves		93,769		93,603		80,653		16,880		16,872		15,173		21,845		21,736		15,708
Probable Reserves		31,338		31,311		26,655		4,863		4,861		4,260		7,203		7,180		5,186
Total Proved Plus Probable Reserves		125,107		124,914		107,308		21,744		21,733		19,433		29,048		28,916		20,893

	Natural Gas						Coal Bed Methane						Total Oil Equivalent Basis(1)
	Company		Gross		Net		Company		Gross		Net		Company		Gross		Net
	Interest		Interest		Interest		Interest		Interest		Interest		Interest		Interest		Interest
RESERVES CATEGORY	(MMcf)		(MMcf)		(MMcf)		(MMcf)		(MMcf)		(MMcf)		(Mboe)		(Mboe)		(Mboe)
Proved Reserves
Proved Developed Producing		546,528		542,127		437,085		21,173		20,376		19,026		202,845		201,698		167,661
Proved Developed Non- Producing		21,555		21,462		16,328		2,797		2,716		2,481		5,752		5,722		4,519
Proved Undeveloped		50,778		50,646		41,437		14,049		13,911		12,341		33,376		33,330		27,470
Total Proved Reserves		618,861		614,234		494,850		38,019		37,003		33,848		241,974		240,751		199,650
Probable Reserves		195,196		193,799		155,060		17,403		17,116		15,579		78,838		78,505		64,541
Total Proved Plus Probable Reserves		814,057		808,033		649,910		55,422		54,119		49,427		320,812		319,256		264,191

Note:

(1) Natural gas has been converted to barrels of oil equivalent on the basis of six Mcf of natural gas being equal to one barrel of oil.

- 40 -

Summary of Net Present Value
of Future Net Revenue
as of December 31, 2007
Before and After Income Tax
(Constant Prices and Costs)

											Unit Value Before Income
											Tax Discounted at
	Before Income Taxes Discounted at (%/Year)										10%/Year(1)
	0%		5%		10%		15%		20%
Reserves Category	($MM)		($MM)		($MM)		($MM)		($MM)		$/boe		$/Mcfe
Proved Reserves
Proved Developed Producing		6,463		4,900		3,984		3,383		2,959		23.76		3.96
Proved Developed Non-Producing		170		124		96		79		66		21.34		3.56
Proved Undeveloped		1,205		747		505		359		263		18.37		3.06
Total Proved Reserves		7,839		5,770		4,585		3,821		3,288		22.96		3.83
Probable Reserves		2,810		1,574		1,034		747		572		16.02		2.67
Total Proved Plus Probable Reserves		10,649		7,345		5,619		4,567		3,861		21.27		3.54

	After Income Taxes Discounted at (%/u/c year)
	0%		5%		10%		15%		20%
Reserves Category	($MM)		($MM)		($MM)		($MM)		($MM)
Proved Reserves
Proved Developed Producing		5,614		4,423		3,681		3,171		2,802
Proved Developed Non-Producing		122		83		75		63		54
Proved Undeveloped		668		413		279		197		141
Total Proved Reserves		6,404		4,929		4,035		3,431		2,997
Probable Reserves		1,823		1,054		717		534		422
Total Proved Plus Probable Reserves		8,227		5,983		4,752		3,965		3,419

Note:

(1) Unit values are based on Pengrowth’s Net reserves.

- 41 -

Additional Information Concerning Future Net Revenue
(undiscounted)
as of December 31, 2007
(Constant Prices and Costs)

Future Net

Capital

Future Net

Revenue

Operating

Development

Abandonment

Revenue Before

After Income

Revenue

Royalties(1)

Costs

Costs

Costs(2)

Income Taxes

Income Tax

Taxes

Reserves Category

($MM)

($MM)

($MM)

($MM)

($MM)

($MM)

($MM)

($MM)

Proved Reserves

15,186

2,526

4,131

526

164

7,839

1,435

6,404

Total Proved Plus Probable Reserves

20,154

3,402

5,175

758

170

10,649

2,422

8,227

Notes:
(1)	Royalties payable to the provinces of Alberta, British Columbia, Saskatchewan and Nova Scotia. Does not include the impact of the proposed royalty regime announced by the Government of Alberta on October 25, 2007, to become effective on January 1, 2009. Based on the interpretations by GLJ of the proposed royalty changes and based on the January 2008 commodity price assumptions of GLJ, it is anticipated that the new royalty regime will result in a 12 to 18 percent increase in the total royalties paid to all parties by Pengrowth as compared to the current royalty structure.
(2)	Includes downhole abandonment cost but does not include surface reclamation costs. See “Pengrowth – Operational Information – Additional Information Concerning Abandonment & Reclamation Costs”.

Net Present Value of Future Net Revenue
By Production Group
as of December 31, 2007
(Constant Prices and Costs)

		Future Net Revenue
		Before Income Taxes
		(discounted at 10%/yr)		Unit Value(3)
Reserves Category	Production Group	($MM)		($/boe)		($/Mcf)
Total Proved Reserves	Light and Medium Crude Oil (including solution gas and other by-products)(1)		2,755		29.58		4.93
	Heavy Oil (including solution gas and other by-products) (1)		241		14.19		2.37
	Natural Gas (including by-products but excluding solution gas from oil wells)(2)		1,500		18.11		3.02
	Non-conventional Oil & Gas Activities		89		13.16		2.19
	Total		4,585		22.96		3.83
Total Proved Plus Probable Reserves	Light and Medium Crude Oil (including solution gas and other by-products) (1)		3,340		27.11		4.52
	Heavy Oil (including solution gas and other by-products)(1)		291		13.42		2.24
	Natural Gas (including by-products but excluding solution gas from oil wells)(2)		1,873		17.14		2.86
	Non-conventional Oil & Gas Activities		114		11.75		1.96
	Total		5,619		21.29		3.55

Notes:
(1)	NGL’s associated with the production of solution gas are included as a by-product.
(2)	NGL’s associated with the production of natural gas are included as a by-product.
(3)	Unit values are based on Pengrowth’s Net reserves.

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Pricing Assumptions

     Forecast Prices used in Estimates

The forecast price and cost assumptions assume the continuance of current laws and regulations and changes in wellhead selling prices, and take into account inflation with respect to future operating and capital costs. The forecast prices are provided in the table below and reflect GLJ’s standard price forecast as referred to in the GLJ Report.

	Oil								Natural Gas		Natural Gas Liquids(1)
	WTI		Edmonton		Cromer		Hardisty
	Cushing		Par Price		Medium		Heavy 120		AECO Gas						Pentanes		Inflation		Exchange
	Oklahoma		400API		29.30API		API		Price		Propane		Butane		Plus		Rates(2)		Rate(3)
Year	($US/bbl)		($Cdn/bbl)		($Cdn/bbl)		($Cdn/bbl)		($Cdn/MMbtu)		($Cdn/bbl)		($Cdn/bbl)		($Cdn/bbl)		(%/Year)		($US/Cdn)
2007(4)		72.24		77.02		66.30		44.37		6.65		46.85		58.35		77.33		—		—
2008		92.00		91.10		79.26		54.02		6.75		58.30		72.88		92.92		2.0		1.00
2009		88.00		87.10		75.78		51.61		7.55		55.74		69.68		88.84		2.0		1.00
2010		84.00		83.10		72.30		49.19		7.60		53.18		66.48		84.76		2.0		1.00
2011		82.00		81.10		70.56		47.98		7.60		51.90		64.88		82.72		2.0		1.00
2012		82.00		81.10		70.56		47.98		7.60		51.90		64.88		82.72		2.0		1.00
2013		82.00		81.10		70.56		49.04		7.60		51.90		64.88		82.72		2.0		1.00
2014		82.00		81.10		70.56		50.09		7.80		51.90		64.88		82.72		2.0		1.00
2015		82.00		81.10		70.56		51.15		7.97		51.90		64.88		82.72		2.0		1.00
2016		82.02		81.12		70.57		52.21		8.14		51.91		64.89		82.74		2.0		1.00
2017		83.66		82.76		72.00		53.29		8.31		52.97		66.21		84.42		2.0		1.00
Thereafter	+2.0%/yr		+2.0%/yr		+2.0%/yr		+2.0%/yr		+2.0%/yr		+2.0%/yr		+2.0%/yr		+2.0%/yr			2.0		1.00

Notes:
(1)	FOB Edmonton.
(2)	Inflation rates for forecasting prices and costs.
(3)	The exchange rates used to generate the benchmark reference prices in this table.
(4)	Actual average prices for 2007.

     Constant Prices used in Estimates

The constant price assumptions assume the continuance of current laws, regulations and operating costs in effect on the date of the GLJ Report. Product prices were not escalated beyond December 31, 2007. Operating and capital costs have not been increased on an inflationary basis. The prices are as follows:

Oil

Natural Gas

Natural Gas Liquids(1)

WTI

Edmonton

Cromer

LLB Crude

Cushing

Par Price

Medium

Oil at

AECO Gas

Pentanes

Exchange

Oklahoma

400API

29.30API

Hardisty

Price

Propane

Butane

Plus

Rate(2)

Year

($US/bbl)

($Cdn/bbl)

($Cdn/bbl)

($Cdn/bbl)

($Cdn/MMbtu)

($Cdn/bbl)

($Cdn/bbl)

($Cdn/bbl)

($US/Cdn)

December 31, 2007

95.92

93.39

74.26

53.74

6.63

59.77

74.71

94.24

1.012

Notes:
(1)	FOB Edmonton.
(2)	The exchange rate used to generate the benchmark reference prices in this table.

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Reserves Reconciliation

The following tables provide a reconciliation of Pengrowth’s gross reserves of crude oil, natural gas and NGLs for the year ended December 31, 2007, presented using forecast prices and costs. All reserves are located in Canada.

Reserves Reconciliation
By Principle Product Type
(Forecast Prices and Costs)

	Light and Medium Oil									Heavy Oil									Natural Gas Liquids
																									Gross
							Gross									Gross									Proved
	Gross			Gross			Proved Plus			Gross			Gross			Proved Plus			Gross			Gross			Plus
	Proved			Probable			Probable			Proved			Probable			Probable			Proved			Probable			Probable
	(Mbbls)			(Mbbls)			(Mbbls)			(Mbbls)			(Mbbls)			(Mbbls)			(Mbbls)			(Mbbls)			(Mbbls)
December 31, 2006		84,648			27,467			112,115			14,236			4,090			18,326			22,400			6,682			29,082
Extensions		932			(141	)		791			30			10			40			496			(1	)		495
Infill Drilling		1,188			956			2,144			—			—			—			235			160			395
Improved Recovery		482			421			903			—			—			—			25			15			40
Technical Revisions		3,119			(1,421	)		1,698			742			(177	)		565			591			174			765
Discoveries		—			—			—			—			—			—			23			3			26
Acquisitions		14,256			4,893			19,149			5,939			1,542			7,481			2,828			629			3,457
Dispositions		(2,227	)		(993	)		(3,220	)		(1,432	)		(582	)		(2,014	)		(1,509	)		(478	)		(1,987	)
Economic Factors		—			—			—			—			—			—			—			—			—
Production		(9,582	)		—			(9,582	)		(2,616	)		—			(2,616	)		(3,411	)		—			(3,411	)
December 31, 2007		92,817			31,180			123,997			16,898			4,883			21,781			21,677			7,185			28,862
	Natural Gas									Coal Bed Methane									Total Oil Equivalent Basis(1)
																									Gross
							Gross									Gross									Proved
	Gross			Gross			Proved Plus			Gross			Gross			Proved Plus			Gross			Gross			Plus
	Proved			Probable			Probable			Proved			Probable			Probable			Proved			Probable			Probable
	(MMcf)			(MMcf)			(MMcf)			(MMcf)			(MMcf)			(MMcf)			(Mboe)			(Mboe)			(Mboe)
December 31, 2006		608,105			191,206			799,311			14,230			9,427			23,657			225,007			71,677			296,684
Extensions		16,729			5,195			21,924			14,055			4,883			18,938			6,588			1,548			8,136
Infill Drilling		11,350			7,846			19,196			—						—			3,314			2,424			5,738
Improved Recovery		508			221			729			—			—			—			592			472			1,064
Technical Revisions		14,661			(19,175	)		(4,514	)		1,791			(1,543	)		248			7,193			(4,877	)		2,316
Discoveries		519			234			753			338			112			450			165			62			227
Acquisitions		155,961			36,584			192,545			8,434			4,235			12,669			50,422			13,867			64,289
Dispositions		(99,088	)		(28,236	)		(127,324	)		—			—			—			(21,682	)		(6,760	)		(28,442	)
Economic Factors		—			—			—			—			—			—			—			—			—
Production		(94,384	)		—			(94,384	)		(1,845	)		—			(1,845	)		(31,648	)		—			(31,648	)
December 31, 2007		614,363			193,874			808,237			37,002			17,115			54,117			239,953			78,413			318,366

Note:
(1)	Natural gas has been converted to barrels of oil equivalent on the basis of six Mcf of natural gas being equal to one barrel of oil.

- 44 -

At December 31 2007, Company Interest Total Proved Plus Probable Reserves were 319.9 MMboe as compared to 297.8 MMboe reported at year end 2006 and 219.4 MMboe reported at year end 2005. The following additional GLJ reserves reconciliation is presented for year end December 31, 2007.

Company Interest Reserves Reconciliation
on Total Oil Equivalent Basis
(Forecast Prices and Costs)

							Proved Plus
	Proved Producing			Proved			Probable
	Reserves			Reserves			Reserves
	(Mboe)(1)			(Mboe)(1)			(Mboe)(1)
December 31, 2006		188,961			225,875			297,774
Extensions		4,898			6,588			8,136
Infill Drilling		3,956			3,314			5,738
Improved Recovery		755			592			1,180
Technical Revisions		11,094			7,170			2,094
Discoveries		109			165			227
Acquisitions		44,721			51,046			65,115
Dispositions		(19,696	)		(21,682	)		(28,442	)
Production		(31,901	)		(31,901	)		(31,901	)
December 31, 2007		202,897			241,169			319,921

Note:
(1)	Natural gas has been converted to barrels of oil equivalent on the basis of six Mcf of natural gas being equal to one barrel of oil.

Significant factors on the reserves reconciliation were as follows:

• Reserve additions from drilling activity, improved recovery and technical revisions replaced 2007 production by 56 percent and 54 percent for Total Proved and Proved Plus Probable Reserves, respectively. Based on all changes, including acquisitions and dispositions, reserve replacement was 148 percent and 169 percent for Total Proved and Proved Plus Probable Reserves, respectively.

• The net increase of 36.7 MMboe from acquisitions and dispositions accounted for approximately 68 percent of the Total Proved Plus Probable Reserves added in 2007. Acquisition adds were almost entirely from the ConocoPhillips properties acquired in January 2007. Acquisitions were offset by the planned sale of non-core assets closing at various times during 2007.

• New reserves were added from development activity. Most significant were drilling extensions for Horseshoe Canyon CBM and infill drilling and drilling extensions at Twining, Harmattan and Monogram. Reserve increases in the Proved Producing category also resulted from reclassification of Proved and Probable Undeveloped Reserves primarily for additional drilling and tie-in of Horseshoe Canyon CBM, infill drilling at Monogram and infill drilling and improved recovery in the Weyburn and Swan Hills miscible flood projects.

• Various performance related revisions were made to previous estimates resulting in a net positive change. The largest revisions to Proved Reserves occurred at Sable Island (+1,308 Mboe), Fenn Big Valley (+965 Mboe), Jenner (+887 Mboe) and Winnifred (-520 Mboe).

Additional Information Relating to Reserves Data

Undeveloped Reserves

Undeveloped Reserves are those reserves expected to be recovered from known accumulations where a significant expenditure is required to render them capable of production.

Proved and Probable Undeveloped Reserves have been estimated in accordance with procedures and standards contained in the COGE Handbook. In general, Undeveloped Reserves are scheduled to be developed within the

- 45 -

next two years. Much of the remaining capital scheduled beyond two years is related to the Weyburn, Judy Creek and Swan Hills EOR projects, which have staged development plans.

Timing of Initial Undeveloped Reserves Booking
Company Gross Reserves
Reserves First Attributed By Year

	Units	Prior		2005		2006		2007		Total
Proved Undeveloped
Light & Medium Oil	Mbbl		8,498		7,221		1,334		1,932		18,985
Heavy Oil	Mbbl		1,852		—		—		342		2,194
Natural Gas	MMcf		7,236		3,508		18,575		20,905		50,224
Natural Gas Liquids	Mbbl		120		—		843		398		1,361
Coal Bed Methane	MMcf		—		—		2,555		11,356		13,911
Total	Mboe(1)		11,754		7,730		5,698		8,048		33,230
Probable Undeveloped										��
Light & Medium Oil	Mbbl		5,995		3,123		1,315		3,065		13,498
Heavy Oil	Mbbl		1,343		—		200		726		2,269
Natural Gas	MMcf		2,744		3,598		33,258		25,386		64,986
Natural Gas Liquids	Mbbl		112		648		1,286		670		2,716
Coal Bed Methane	MMcf		—		—		1,985		8,170		10,155
Total	Mboe(1)		7,907		4,371		8,674		10,054		31,006

Note:
(1)	Natural gas has been converted to barrels of oil equivalent on the basis of six Mcf of natural gas being equal to one barrel of oil.

Proved Undeveloped Reserves

Pengrowth’s Proved Undeveloped Reserves comprise roughly 14 percent of the Total Proved Reserves on a barrel of oil equivalency basis. Pengrowth Interest Proved Undeveloped Reserves of 33.3 MMboe were assigned by GLJ in accordance with NI 51-101. In general, Proved Undeveloped Reserves were assigned to certain properties because capital commitments have been made to convert the Undeveloped Reserves to Proved Producing Reserves. Proved Undeveloped Reserves have been primarily assigned for future miscible flood expansion and development drilling.

Judy Creek comprises roughly 17 percent of the Proved Undeveloped Reserves. Miscible flood expansion is an on-going activity, which is forecasted to continue until 2011. Similarly, at Swan Hills, miscible flood expansion, as well as some infill drilling, accounts for another 16 percent of Pengrowth’s Proved Undeveloped Reserves assignments. The Swan Hills Unit reserves have a 50 year reserve life. The incremental recovery is reflected in the GLJ Report and miscible flood expansion is forecasted to continue until 2026. In the Weyburn Unit, an additional 14 percent of the Proved Undeveloped Reserves assignment reflects the capital allocated to the CO₂ miscible flood. Working interest partners have committed to a CO₂ supply until 2025. Further development of the flood area, from the existing 46 patterns to full development with 65 patterns in the proved case, is forecast to occur until 2012. Development of all 90 patterns in the probable case continues until 2019. Given the early stages of the CO₂ pilot at Judy, we are not forecasting any full scale CO₂ flooding at Judy Creek.

The Olds Gas Unit contains about seven percent of the total Proved Undeveloped Reserves assigned by GLJ relating to further infill drilling that is forecasted to occur until 2011 in the proved reserve case and 2012 in the proved plus probable reserve case. Ongoing development is scheduled in heavy oil properties where approximately five percent of Pengrowth’s Proved Undeveloped Reserves are assigned to the waterflood expansion in East Bodo that is forecast to occur in stages until 2012. Multi-well shallow gas infill programs are scheduled for 2008 and beyond at Jenner and Monogram, which contain roughly six percent of the total Proved Undeveloped Reserves. Pengrowth’s newly developing CBM production requires further drilling extensions at Twining and Fenn Big Valley. Because of the extensive land holdings, this is forecast to occur over the next three years and represents approximately five percent of the Total Proved Undeveloped Reserves. Carson Creek contains about 4 percent of Pengrowth’s Proved Undeveloped Reserves, which are attributed to future development drilling which is budgeted for 2008.

- 46 -

Probable Undeveloped Reserves

Probable Undeveloped Reserves were assigned by GLJ in accordance with the requirements and standards of NI 51-101 and the COGE Handbook. Pengrowth’s Probable Undeveloped Reserves amount to 31.1 MMboe and represent about 10 percent of the Total Proved Plus Probable Reserves. Probable Undeveloped Reserves are assigned for similar reasons and generally to the same properties as Proved Undeveloped Reserves, but also meet the requirements of the reserve classification to which they belong. Pengrowth’s largest Probable Undeveloped Reserves are distributed among certain properties as a percent of the total as follows: Olds Gas Unit (16 percent), Weyburn Unit (16 percent), Swan Hills Unit (eight percent), Judy Creek Units (five percent), Twining (four percent), Monogram Gas Unit (four percent), Sable Offshore Energy Project (three percent), Deer Mountain (three percent), East Bodo (three percent) and Fenn Big Valley CBM (three percent).

Future Development Costs

The following table outlines development costs deducted in the estimation of future net revenue calculated utilizing both constant and forecast prices and costs, undiscounted and using a discount rate of 10 percent per annum for the years indicated. All of such development costs are estimated to be incurred in Canada.

													Undiscounted		Discounted
	2008		2009		2010		2011		2012		Remainder		Total		at 10% Total
Reserve Category	($MM)		($MM)		($MM)		($MM)		($MM)		($MM)		($MM)		($MM)
Proved Reserves (Constant Prices and Costs)		183		103		63		33		18		126		526		393
Proved Reserves (Forecast Prices and Costs)		183		105		65		35		19		158		566		408
Proved & Probable Reserves (Forecast Prices and Costs)		230		180		100		47		29		234		819		584

Pengrowth expects to fund future development costs with a combination of cash flow, debt and equity. There are no reserves that are expected to be limited in their recovery due to their cost of development. Pengrowth has established a $355 million development capital expenditure program for 2008 to fund its land acquisition, development and exploration activities.

Finding, Development and Acquisition Costs

Finding and Development Costs

During 2007, Pengrowth spent $283.1 million on development and optimization activities, which added 17.8 MMboe of Proved Reserves and 17.4 MMboe of Total Proved Plus Probable Reserves including revisions. The largest additions were for infill drilling at Twining, Monogram and Weyburn, drilling extensions at Harmattan, Cactus Lake and Fenn Big Valley and for Horseshoe Canyon CBM development in southern Alberta.

In total, Pengrowth participated in drilling 511 gross wells (174.7 net wells) with a 97 percent success rate.

At Judy Creek, infill drilling and ongoing development and optimization of the hydrocarbon miscible flood projects continue to be a focus for Pengrowth along with routine maintenance capital expenditures for facility upgrades. Similar infill drilling and miscible flood development occurred in the Swan Hills Unit No. 1.

The Carson Creek assets were acquired in late 2006 and activity began to increase during 2007. Two wells were drilled and optimization work has started. A 3D seismic program was shot over the oil Unit which identified several drilling locations budgeted for 2008.

Further development and optimization occurred in the Weyburn field in southeast Saskatchewan. A large infill drilling program was carried out in 2007 along with new pattern development in the CO₂ miscible flood project area. A third recycle compressor was also installed and other facility maintenance and upgrades were carried out.

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In 2007, Pengrowth participated in numerous Horseshoe Canyon CBM wells in the Twining, Lone Pine Creek and Fenn Big Valley areas of southern Alberta. All 63 wells of the 2006 drilling program were tied-in and brought on stream in 2007. In addition, Pengrowth drilled and completed its first horizontal Mannville CBM well in Fenn Big Valley during 2007. The well will be coming on stream in early 2008 and more Mannville CBM drilling is planned.

Various multi-well infill drilling programs were conducted during 2007 to increase production and maximize recoveries. In the heavy oil area, the 13 well vertical infill program drilled late in 2006 in the Tangleflags SAGD project were completed and brought on stream in early 2007. An 18 well drilling program targeting gas in the Viking and Mannville formations was successful in the Cosine and Primate areas with all 18 wells completed as gas wells. Ongoing shallow gas development occurred with multi-well infill programs at Three Hills/Twining and Monogram. In the Dunvegan Gas Unit, another 10 infill wells were drilled. Development drilling and facility optimization occurred in the Olds/Harmattan area.

Acquisitions and Divestitures

Pengrowth experienced another active year in 2007 making a significant strategic asset acquisition and disposing of certain non-core assets in an ongoing effort to high-grade its portfolio. Pengrowth spent $1,036 million on acquisitions adding 51.0 MMboe of Proved and 65.1 MMboe of Proved Plus Probable Reserves. Total proceeds from dispositions during 2007 was $476 million. The proceeds received by December 31, 2007 were $459 million. The difference in the value and the proceeds were mainly due to Pengrowth receiving payments for production from the effective date to closing. The proceeds were used to repay debt, including the partial repayment of a $600 million bridge facility, which has since been repaid in its entirety. These transactions resulted in a decrease of 21.7 MMboe Proved and 28.4 MMboe Proved Plus Probable Reserves.

In January 2007, Pengrowth closed the acquisition of four subsidiaries of Burlington Resources Ltd., a subsidiary of ConocoPhillips. Many of the assets fit well with Pengrowth’s existing core areas or provided sufficient size to establish new focus areas. Pengrowth’s operations in southern Alberta were expanded with the addition of gas and oil production in the Bantry, Jenner, Lethbridge, Fenn Big Valley and Harmattan areas. The addition of the Goose River and Deer Mountain assets was a strategic fit with Pengrowth’s presence in the Judy Creek, Carson Creek and Swan Hills area, while the Red Earth assets provided a new growth area for oil production.

Pengrowth conducted two formal disposition programs during 2007. The programs consisted of numerous relatively small, non-core properties scattered across Saskatchewan, Alberta and northeast British Columbia. The sale packages closed at various times during the year. In addition, Pengrowth sold two assets, Freefight and Ante Creek, from the ConocoPhillips acquisition.

Future Development Capital

If an issuer chooses to disclose finding and development costs, NI 51-101 requires that the calculation include changes in forecasted future development costs (“FDC”) relating to the reserves. FDC reflect the amount of capital estimated by the independent evaluator that will be required to bring non-producing, undeveloped or probable reserves on stream. These forecasts of FDC will change with time due to ongoing development activity, inflationary changes in capital costs and acquisition or disposition of assets. Pengrowth provides the calculation of finding, development and acquisition costs both with and without change in FDC.

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2007 Finding, Development and Acquisition Costs
Company Interest Reserves

			Proved plus
	Proved		Probable
FD&A Costs Excluding Future Development Capital
Exploration and Development Capital Expenditures ($thousands)	$	283,100	$	283,100
Exploration and Development Reserve Additions including Revisions (Mboe)		17,830		17,376
Finding and Development Cost ($/boe)	$	15.88	$	16.29
Net Acquisition Capital ($thousands)	$	577,100	$	577,100
Net Acquisition Reserve Additions (Mboe)		29,364		36,673
Net Acquisition Cost ($/boe)	$	19.65	$	15.74
Total Capital Expenditures including Net Acquisitions ($thousands)	$	860,200	$	860,200
Reserve Additions including Net Acquisitions (Mboe)		47,194		54,049
Finding Development and Acquisition Cost ($/boe)	$	18.23	$	15.92
FD&A Costs Including Future Development Capital
Exploration and Development Capital Expenditures ($thousands)	$	283,100	$	283,100
Exploration and Development Change in FDC ($thousands)	$	8,000	$	20,000
Exploration and Development Capital including Change in FDC ($thousands)	$	291,100	$	303,100
Exploration and Development Reserve Additions including Revisions (Mboe)		17,830		17,376
Finding and Development Cost ($/boe)	$	16.33	$	17.44
Net Acquisition Capital ($thousands)	$	577,100	$	577,100
Net Acquisition FDC ($thousands)	$	115,000	$	145,000
Net Acquisition Capital including FDC ($thousands)	$	692,100	$	722,100
Net Acquisition Reserve Additions (Mboe)		29,364		36,673
Net Acquisition Cost ($/boe)	$	23.57	$	19.69
Total Capital Expenditures including Net Acquisitions ($thousands)	$	860,200	$	860,200
Total Change in FDC ($thousands)	$	123,000	$	165,000
Total Capital including Change in FDC ($thousands)	$	983,300	$	1,025,300
Reserve Additions including Net Acquisitions (Mboe)		47,194		54,049
Finding Development and Acquisition Cost including FDC ($/boe)	$	20.83	$	18.97

Note:

(1) Natural gas has been converted to barrels of oil equivalent on the basis of six Mcf of natural gas being equal to one barrel of oil.

Other Oil and Gas Information

Oil and Gas Wells

As at December 31, 2007 Pengrowth had an interest in 9,604 gross (5,038 net) producing oil and natural gas wells and 1,627 gross (976 net) non-producing oil and natural gas wells.

	Producing				Non-Producing
	Gross		Net		Gross		Net
Crude Oil Wells
Alberta		2,346		1,473		473		277
British Columbia		151		105		47		43
Saskatchewan		1,134		279		187		81
Nova Scotia		—		—		—		—
Natural Gas Wells
Alberta		5,515		2,827		571		322
British Columbia		124		77		25		27
Saskatchewan		51		48		87		47
Nova Scotia		19		1		—		—

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	Producing				Non-Producing
	Gross		Net		Gross		Net
Other(1)
Alberta		250		217		165		115
British Columbia		—		—		50		46
Saskatchewan		14		10		22		19
Total		9,604		5,038		1,627		976

Note:

(1) Pengrowth cannot classify these wells as either oil or gas.

Properties with No Attributed Reserves

The following table sets forth the gross and net acres of unproved properties held by Pengrowth as at December 31, 2007 and the net area of unproved properties for which Pengrowth expects its rights to explore, develop and exploit to expire during the next year.

Unproved Properties
as at December 31, 2007

					Net Area May Expire
Location	Gross Acres		Net Acres		During 2008
Alberta		1,095,994		754,253		129,887
British Columbia		255,172		116,763		13,847
Ontario		4,766		—		—
Saskatchewan		90,989		76,335		30,039
Montana		3,520		3,520		3,520
Nova Scotia		200,650		15,957		—
Total		1,651,091		966,828		177,293

The expiring acreage is being evaluated and attempts will be made to continue the acreage based on current activity which is focused on exploitation of up-hole potential in existing wells.

Additional Information Concerning Abandonment & Reclamation Costs

The total future abandonment and reclamation costs are based on management’s estimate of costs to remediate, reclaim and abandon wells and facilities having regard to Pengrowth’s working interest and the estimated timing of the costs to be incurred in future periods. Pengrowth has developed a process to calculate these estimates, which considers applicable regulations, actual and anticipated costs, type and size of the well or facility and the geographic location. GLJ’s estimate of downhole abandonment costs are included in their report and therefore in their estimate of future net revenue. All other abandonment and reclamation costs are not reflected in their estimate of future net revenue. Pengrowth anticipates incurring abandonment costs on a total of approximately 6,900 net wells.

Pengrowth has estimated the net present value (discounted at 10 percent per annum) of its total asset retirement obligations to be $270 million as at December 31, 2007, based on a total future liability (inflated at two percent per annum) of $2,015 million. These costs are anticipated to be paid over 50 years with the majority of the costs incurred between 2039 and 2054.

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The following tables summarize Pengrowth’s total asset retirement obligations as at December 31, 2007:

Asset Retirement Obligations

	2008		2009		2010		Remainder		Total
	($M)		($M)		($M)		($M)		($M)
Total Abandonment, Reclamation, Remediation & Dismantling		17,287		18,046		21,363		1,958,381		2,015,077
Discounted at 10 percent		16,483		15,642		16,834		220,908		269,867

GLJ’s estimate of reserves includes $194 million ($67 million when discounted at 10 percent) of the asset retirement obligations in the above table.

Costs Incurred

The following table outlines property acquisition, exploration and development costs incurred during the financial year ended December 31, 2007. These costs include only those costs which are cash or cash equivalent.

	Amount
Nature of Cost	($M)
Acquisition Costs(1)
Proved		823,566
Unproved		212,317
Exploration Costs		21,192
Development Costs		261,866
Total		1,318,941

Note:

(1) Based on the values assigned to property, plant and equipment in the purchase price allocations for the CP Acquisition and for several minor property acquisitions.

Exploration and Development Activities

The following table summarizes the results of development and exploration activities during the financial year ended December 31, 2007.

	Development				Exploration				Total
	Gross		Net		Gross		Net		Gross		Net
Wells
Gas		383		130.7		6		2.2		389		132.9
Oil		84		19.9		6		5.3		90		25.2
Service		15		8.4		—		—		15		8.4
Dry		12		5.6		5		2.6		17		8.2
Total		494		164.6		17		10.1		511		174.7

Production Estimates

The following tables summarize the average daily volume of Gross production estimated by GLJ for the year ended December 31, 2008 for all properties held on December 31, 2007 using constant and forecast prices and costs, all of which will be produced in Canada. These estimates assume certain activities take place, such as the development of Undeveloped Reserves, and that there are no dispositions. Pengrowth estimates its 2008 production to be between 80,000 and 82,000 boepd.

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	Estimated Production
	Constant Prices and Costs				Forecast Prices and Costs
			Total Proved Plus				Total Proved Plus
	Total Proved		Probable		Total Proved		Probable
Light and Medium Crude Oil (bblpd)		24,933		26,169		24,933		26,169
Heavy Oil (bblpd)		6,485		6,711		6,485		6,711
Natural Gas (Mcfpd)		245,006		255,631		245,007		255,631
Natural Gas Liquids (bblpd)		8,250		8,526		8,250		8,526

Production History (Netback)

The following tables summarize, for each quarter of the Trust’s most recent financial year, certain information in respect of production, product prices received, royalties paid, operating expenses and resulting operating netbacks of Pengrowth:

	Quarter Ended
	March 31,			June 30,			September 30,			December 31,
	2007			2007			2007			2007
Light Crude Oil
Average Daily Oil Production(1) (bblpd)		27,461			27,083			24,903			25,892
Sales Price (net of hedging gains/losses) ($/bbl)		67.24			71.81			75.10			73.69
Processing and other income ($/bbl)		0.39			0.42			0.90			0.69
Royalties ($/bbl)		(9.88	)		(11.90	)		(10.65	)		(13.86	)
Amortization of injectants ($/bbl)		(3.84	)		(3.51	)		(3.69	)		(3.14	)
Production Costs(2) ($/bbl)		(13.31	)		(15.11	)		(16.93	)		(15.69	)
Operating Netback ($/bbl)		40.60			41.71			44.73			41.69
Heavy Oil
Average Daily Oil Production(1) (bblpd)		6,773			7,254			7,205			7,434
Sales Price (net of hedging gains/losses) ($/bbl)		41.54			43.52			47.30			45.47
Processing and other income ($/bbl)		0.18			0.18			0.50			0.19
Royalties ($/bbl)		(5.23	)		(5.33	)		(6.90	)		(5.91	)
Production Costs(2) ($/bbl)		(13.15	)		(15.37	)		(9.43	)		(12.92	)
Operating Netback ($/bbl)		23.34			23.00			31.47			26.83
NGLs
Average Daily NGL Production(1) (bblpd)		9,918			8,519			9,883			9,319
Sales Price (net of hedging gains/losses) ($/bbl)		49.67			56.42			61.69			67.64
Royalties ($/bbl)		(14.05	)		(17.53	)		(18.82	)		(23.61	)
Production Costs(2) ($/bbl)		(12.02	)		(13.57	)		(10.96	)		(14.29	)
Operating Netback ($/bbl)		23.60			25.32			31.91			29.74
Natural Gas
Average Daily Gas Production(1) (Mcfpd)		275,495			280,667			261,976			250,117
Sales Price (net of hedging gains/losses) ($/Mcf)		7.91			7.61			6.67			6.90
Processing and other income ($/Mcf)		0.15			0.16			0.19			0.18
Royalties ($/Mcf)		(1.67	)		(1.47	)		(0.92	)		(1.22	)
Production Costs(2) ($/Mcf)		(2.10	)		(2.24	)		(1.58	)		(2.11	)
Operating Netback ($/Mcf)		4.29			4.06			4.36			3.75

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	Quarter Ended
	March 31,			June 30,			September 30,			December 31,
	2007			2007			2007			2007
Barrels of Oil Equivalent Basis(3)
Average Daily Production(1) (boepd)		90,068			89,633			85,654			84,331
Sales Price (net of hedging gains/losses) ($/boe)		53.30			54.39			53.34			54.58
Processing and other income ($/boe)		0.58			0.66			0.90			0.76
Royalties ($/boe)		(10.06	)		(10.30	)		(8.67	)		(11.01	)
Amortization of injectants ($/boe)		(1.17	)		(1.06	)		(1.07	)		(0.97	)
Production Costs(2) ($/boe)		(12.78	)		(14.13	)		(11.84	)		(13.80	)
Operating Netback ($/boe)		29.87			29.56			32.66			29.56

Notes:

(1)	Before the deduction of royalties.
(2)	Includes transportation costs. Net of processing and other income.
(3)	Natural gas has been converted to barrels of oil equivalent on the basis of six Mcf of natural gas being equal to one boe.

Replacement of Properties

In the event that Pengrowth determines that the sale of any of its interests in properties, and the release of the royalty would be in the best interest of the Unitholders, the Royalty Indenture permits it to make sales without the requirement of approval of the Unitholders, provided that the aggregate properties sold in any given year total less than 25 percent of the assets of Pengrowth, determined as at the date of disposition of the properties based upon an independent engineering appraisal. Any sale exceeding this threshold must be approved by an extraordinary resolution of the Unitholders.

Net Asset Value (NAV) at December 31, 2007

In the following table, Pengrowth’s before tax net asset value is estimated with reference to the present value of future net cash flows before income tax from Total Proved Plus Probable Reserves, as estimated by GLJ and calculated using forecast prices and costs.

	($ thousands,
	unless otherwise indicated)
Value of Total Proved Plus Probable Reserves discounted at 10%		5,455,881
Undeveloped lands(1)		239,893
Working capital deficit(2)		(34,423	)
Reclamation funds		18,094
Long-term debt		(1,203,236	)
Fair value of risk management contracts(3)		(79,401	)
Other liabilities(4)		(87,192	)
Asset retirement obligations(5)		(206,868	)
Net asset value		4,102,748
Units outstanding (000’s)		246,846
NAV per unit	$	16.62

Notes:

(1)	Pengrowth’s internal estimate, calculated using the average land sale prices paid in 2007 in Alberta, Saskatchewan and British Columbia.
(2)	Excludes distributions payable, current portion of risk management contracts and future income taxes.
(3)	Represents the total fair value of risk management contracts at December 31, 2007.
(4)	Other liabilities include convertible debt and non-current contract liabilities.
(5)	The asset retirement obligation is based on Pengrowth’s estimate of future site restoration and abandonment liabilities, discounted at 10 percent, less that portion of the asset retirement obligations costs that are included in the value of Total Proved Plus Probable Reserves.

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TRUST UNITS

The Trust Indenture

The Trust Units, along with the class A trust units, are issued under the terms of the Trust Indenture. A maximum of 500,000,000 Trust Units and class A trust units, in the aggregate, may be created and issued pursuant to the Trust Indenture, of which 246,844,532 Trust Units and 1,888 class A trust units are issued and outstanding as at December 31, 2007. Each Trust Unit and class A trust unit represents a fractional undivided beneficial interest in the Trust.

The Trust Indenture, among other things, provides for the establishment of the Trust, the issue of Trust Units and class A trust units, the permitted investments of the Trust, the procedures respecting distributions to Unitholders, the appointment and removal of Computershare as trustee, Computershare’s authority and restrictions thereon, the calling of meetings of Unitholders, the conduct of business at such meetings, notice provisions, the form of trust unit certificates and the termination of the Trust. The Trust Indenture may be amended from time to time. Most amendments to the Trust Indenture, including the early termination of the Trust and the sale or transfer of the property of the Trust as an entirety or substantially as an entirety, require approval by an extraordinary resolution of the Unitholders. An extraordinary resolution of the Unitholders requires the approval of not less than 66 2/3 percent of the votes cast at a meeting of Unitholders held in accordance with the Trust Indenture at which two or more holders of at least 5 percent of the aggregate number of Trust Units and class A trust units then outstanding are represented. Computershare, as trustee, is permitted to amend the Trust Indenture without the consent or approval of the Unitholders for certain purposes, including: (i) ensuring that the Trust complies with applicable laws or government requirements, including satisfaction of certain provisions of the Tax Act; (ii) ensuring that additional protection is provided for the interests of Unitholders as Computershare may consider expedient; and (iii) making typographical or other non-substantive changes that are not adverse to the interests of Computershare and the Unitholders.

The Trust is an energy investment trust formed under the laws of the Province of Alberta which offers and sells the Trust Units to the public. The Trust Units are not “deposits” within the meaning of theCanadian Deposit Insurance Corporation Act(Canada) (“CDIC Act”) and are not insured under the provisions of the CDIC Act or any other legislation. Furthermore, the Trust is not a trust company and, accordingly, is not registered under any trust and loan company legislation as it does not carry on or intend to carry on business of a trust company.

The Trustee

Computershare, as trustee, is generally empowered by the Trust Indenture to exercise any and all rights and powers that could be exercised by the beneficial owner of the assets of the Trust. Computershare’s specific responsibilities include, but are not limited to, the following: (i) reviewing and accepting subscriptions for Trust Units and class A trust units and issuing Trust Units and class A trust units subscribed for; (ii) subscribing for Royalty Units; (iii) issuing Trust Units in exchange for Royalty Units tendered to it for exchange; and (iv) maintaining records and providing timely reports to Unitholders. Computershare is authorized to delegate its powers and duties as trustee except as prohibited by law.

Computershare, as trustee, must exercise its powers and carry out its functions under the Trust Indenture honestly, in good faith and in the best interests of the Trust and the Unitholders, and must exercise that degree of care, diligence and skill that a reasonably prudent person would exercise in comparable circumstances. Computershare is not required to devote its entire time to the business and affairs of the Trust.

Computershare, as trustee, shall be reappointed or replaced every two years as may be determined by a majority of the votes cast at an annual meeting of the Unitholders. Computershare may resign upon 60 days notice to the Corporation. Computershare may be removed by extraordinary resolution of the Unitholders or by the Corporation in certain specific circumstances. Such resignation or removal shall become effective upon the acceptance of appointment by a successor.

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Stock Exchange Listings

The outstanding Trust Units are listed and posted for trading on the NYSE under the symbol “PGH” and on the TSX under the symbol “PGF.UN”. The class A trust units are not listed or posted for trading on the facilities of any stock exchange and are not transferable.

Ownership Restrictions

There are no restrictions on the ownership of the Trust Units. The class A trust units may only be held by individuals, corporations or other entities that are not “non-residents” of Canada as that term is defined in the Tax Act.

Redemption Right

The Trust Units and class A trust units are redeemable by Computershare, as trustee, on demand by a Unitholder, when properly endorsed for transfer and when accompanied by a duly completed and properly executed notice requesting redemption, at a redemption price equal to the lesser of: (i) 95 percent of the average closing price of the Trust Units on the market designated by the Board of Directors for the ten days after the Trust Units or class A trust units are surrendered for redemption and (ii) the closing price of the Trust Units on such market on the date the Trust Units or class A trust units are surrendered for redemption. The redemption right permits Unitholders to redeem Trust Units and class A trust units for maximum proceeds of $25,000 in any calendar month provided that such limitation may be waived at the discretion of the Board of Directors. Redemptions in excess of the cash limit must be satisfied by way of a distributionin specieof a pro rata share of Royalty Units and other assets, excluding facilities, pipelines or other assets associated with oil and natural gas production, which are held by the Trust at the time the Trust Units or class A trust units are to be redeemed. The price of Trust Units and class A trust units, as applicable, for redemption purposes is based upon the closing trading price of the Trust Units irrespective of whether the units being redeemed are Trust Units or class A trust units.

Conversion Rights

There are no conversion rights attached to the Trust Units. The class A trust units may be converted into Trust Units on a one for one basis at any time upon demand by the holder thereof.

Voting at Meetings of Unitholders

Meetings of Unitholders may be called on 21 days notice and may be called at any time by Computershare, as trustee, or upon written request of Unitholders holding in the aggregate not less than 5 percent of the aggregate number of Trust Units and class A trust units then outstanding, and shall be called by Computershare and held annually. All activities necessary to organize any such meeting will be undertaken by the Corporation on behalf of Computershare. At all meetings of the Unitholders each holder is entitled to one vote in respect of each Trust Unit or Class A trust unit held. Unitholders may attend and vote at all meetings of the Unitholders either in person or by proxy and a proxy holder need not be a Unitholder. Two persons present in person either holding personally or representing as proxies at least 5 percent of the aggregate number of Trust Units and class A trust units then outstanding constitute a quorum for the transaction of business at all such meetings. Except as otherwise provided in the Trust Indenture, matters requiring the approval of the Unitholders must be approved by extraordinary resolution.

Unitholders are entitled to pass resolutions that will bind Computershare, as trustee, with respect to a limited list of matters, including but, not limited to, the following: (i) the removal or appointment of Computershare as trustee; (ii) the removal or appointment of the auditor of the Trust; (iii) the amendment of the Trust Indenture; (iv) the approval of subdivisions or consolidations of Trust Units or class A trust units; (v) the sale of the assets of the Trust as an entirety or substantially as an entirety; and (vi) the termination of the Trust.

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Unitholders can also consider the appointment of an inspector to investigate whether Computershare has performed its duties arising under the Trust Indenture. Such an inspector shall be appointed if a resolution approving the appointment of such inspector is passed by a majority of the votes duly cast at a meeting held for that purpose.

Voting at Meetings of Corporation

Since Unitholders do not directly hold the common shares of the Corporation or the Royalty Units, they are not permitted to vote directly at meetings of the holders of the common shares and Royalty Units. However, Computershare, as trustee, is required by the Trust Indenture to vote such common shares or Royalty Units in accordance with, and subject to, the direction provided by Unitholders at meetings of the Unitholders. Computershare is not permitted to vote any common shares or Royalty Units without first receiving such direction.

Termination of the Trust

The Unitholders may vote to terminate the Trust at any meeting of such holders, subject to the following:

• a vote may be held only if: (i) requested in writing by the holders of not less than 25 percent of the Trust Units and class A trust units, in the aggregate; or (ii) if the Trust Units and the class A trust units have become ineligible for investment by RRSPs, RRIFs, RESPs and DPSPs;

• the termination must be approved by extraordinary resolution of the Unitholders; and

• a quorum representing 5 percent of the issued and outstanding Trust Units and class A trust units, in the aggregate, must be present or represented by proxy at the meeting at which the vote is taken.

If the termination is approved, Computershare, as trustee, will sell the assets of the Trust, discharge all known liabilities and obligations, and distribute the remaining assets to the Unitholders. Computershare will distribute directly to the Unitholders any assets which Computershare is unable to sell by the date set for termination.

Unitholder Limited Liability

The Trust Indenture provides that no Unitholder will be subject to any personal liability in connection with the Trust or its obligations and affairs, and the satisfaction of claims of any nature arising out of or in connection therewith is only to be made out of the Trust’s assets. Additionally, the Trust Indenture states that no Unitholder is liable to indemnify or reimburse Computershare for any liabilities incurred by Computershare with respect to any taxes payable by or liabilities incurred by the Trust or Computershare, and all such liabilities will be enforceable only against, and will be satisfied only out of the Trust’s assets. It is intended that the operations of the Trust will be conducted, upon the advice of counsel, in such a way and in such jurisdictions as to avoid as far as possible any material risk of liability on the Unitholders for claims against the Trust. Legislation has been enacted in Alberta which reduces the risk to Unitholders from the legal uncertainties regarding the potential liability of Unitholders.

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THE ROYALTY INDENTURE

Royalty Units

Royalty units are issued under the terms of the Royalty Indenture dated July 27, 2006 among the Corporation and Computershare. A maximum of 500,000,000 Royalty Units can be created and issued pursuant to the Royalty Indenture, of which 128,049,331 Royalty Units were issued and outstanding as at December 31, 2007. The Royalty Units represent fractional undivided interests in the royalty created by the Corporation in favour of holders of the Royalty Units, consisting of a 99 percent share of “royalty income”.

The Royalty Indenture, among other things, provides for the grant of the royalty, the issue of Royalty Units, the imposition on, and acceptance by the Corporation of, certain obligations and business restrictions, the calling of meetings of Royalty Unitholders, the conduct of business thereat, notice provisions, the appointment and removal of the trustee, and the establishment and use of the “reserve” as discussed below.

The Royalty Indenture may be amended or varied only by extraordinary resolution of the holders of Royalty Units, or by the Corporation and Computershare, as trustee, for certain specifically defined purposes so long as, in the opinion of Computershare, the Royalty Unitholders and the holders of Royalty Units are not prejudiced as a result.

The Royalty

The royalty consists of a 99 percent share of “royalty income”. Under the terms of the Royalty Indenture, the Corporation is entitled to retain a 1 percent share of “royalty income” and all miscellaneous income (the “Residual Interest”) to the extent this amount exceeds the aggregate of debt service charges, general and administrative expenses, and management fees. In 2007 and 2006, this Residual Interest, as computed, did not result in any income being retained by the Corporation. The Royalty Indenture provides that “royalty income” means the aggregate of any special distributions and gross revenue less, without duplication, the aggregate of the following amounts:

• operating costs and capital expenditures;

• general and administrative costs;

• management fees and debt service charges;

• taxes or other charges payable by the Corporation; and

• any amounts paid into the “reserve”.

Gross revenues generally consist of cash proceeds from the sale of petroleum substances produced from the properties of the Corporation and all other money and things of value received by or incurring to the Corporation by virtue of its legal and beneficial ownership of the properties, but not including processing, transportation, gathering, storage or treatment revenues, proceeds from the sale of properties or amounts received by the Corporation in connection with the borrowing of funds. Special distributions essentially consist of proceeds from the sale of properties that the Corporation is unable to reinvest in suitable replacement properties.

The “reserve” is established by the Corporation with miscellaneous revenues (such as processing and transportation revenues) and allowable portions of gross revenue, and must be used to fund the payment of operating costs, capital expenditures, future abandonments, environmental and reclamation costs, general and administrative costs, royalty income, management fees and debt service charges. The allowable portions of gross revenue consist of (i) amounts determined by the Corporation in accordance with prudent business practices for the payment of future operating costs and reclamation obligations, and (ii) amounts, not to exceed 20% of gross revenue, determined by the Corporation in accordance with prudent business practices to provide for the payment

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of future capital expenditures or for the payment of royalty income in any future period or periods. Any amounts remaining in the reserve when there are no longer any properties that are subject to the royalty, and all of the above obligations have been satisfied, are to be paid to the holders of Royalty Units in proportion to their respective interests.

The Corporation is required to pay to the holders of Royalty Units, on each cash distribution date, 99 percent of “royalty income” received by the Corporation from the properties for the period ending on the last day of the second month immediately preceding that cash distribution date, after the deduction of the foregoing amounts. The holders of Royalty Units, including the Trust, will reimburse the Corporation for 99 percent of the non-deductible government royalties and other non-deductible government charges payable by the Corporation in respect of production from, or ownership of, the properties. The Corporation will at all times be entitled to set off its right to be so reimbursed against its obligation to pay the royalty.

To date, the Corporation has not incurred income taxes but is subject to the Saskatchewan resource surcharge. Any taxes payable by the Corporation will reduce royalty income, and thus the distributions received by Unitholders and holders of Royalty Units.

The Trustee

Computershare is the trustee for holders of Royalty Units under the Royalty Indenture and will remain the trustee thereunder unless it resigns or is removed by Unitholders. Computershare or its successor may resign on 60 days prior notice to the Corporation, and may be removed by extraordinary resolution of the Unitholders and Royalty Unitholders collectively. Computershare’s successor must be approved in the same manner.

Computershare, in accordance with its power to delegate under the Trust Indenture, has appointed the Corporation as the administrator of the Trust to assume those functions of the trustee which are largely discretionary pursuant to the Royalty Indenture, subject to the powers and duties of the Manager pursuant to the management agreement.

EXCHANGEABLE SHARES

At the shareholders’ meeting and Royalty Unitholders’ meeting conducted on April 22, 2004, amendments to the Unanimous Shareholder Agreement were approved to facilitate the issuance of exchangeable shares. The amendments approved will give the Board of Directors greater flexibility to issue a series of exchangeable shares of the Corporation which could meet the Corporation’s objectives of creating a security that is economically similar to Trust Units, marketable in Canada, the United States and internationally, with favourable income tax consequences in the offered jurisdictions and that can be issued by the Trust without exceeding the residency restrictions under the mutual fund trust requirements of the Tax Act. Among other things, exchangeable shares may provide a valuable alternative source of equity to the Corporation to finance ongoing capital commitments of the Corporation, new acquisitions and for other general corporate purposes. The exchangeable shares will be securities of the Corporation that have rights upon a liquidation, wind-up or dissolution of the Corporation (a “Liquidation Event”) that are economically similar to the rights of Unitholders under the Trust Indenture and Royalty Indenture, except in relation to assets other than Royalty Units that may be held by the Trust and the impact of general claims against the Corporation. As a result of the amendments approved, exchangeable shares will have the same rights as the rights of the holders of common shares of the Corporation to vote, to dividends or to share splits in lieu of dividends and to the assets of the Corporation upon the occurrence of a Liquidation Event.

In addition to the foregoing objective, the exchangeable shares may be eligible for investment by certain classes of investors for whom there are limitations with respect to holding Trust Units. The exchangeable shares may also facilitate business combinations and acquisitions and may be issued to the Manager should there be a wind-up or termination of the Management Agreement.

The creation of exchangeable shares was originally approved by Unitholders at the annual and special meetings held on June 17, 2003. It was contemplated at that time if a Liquidation Event were to occur, that holders of exchangeable shares would exercise their exchange right for Trust Units and would participate along with Trust

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Unitholders in accordance with provisions prescribed by the royalty indenture and the Trust Indenture. However, a series of exchangeable shares may, from time to time, be issued that would limit the right of exchange to holders of exchangeable shares who are resident in Canada or the right of exchange may otherwise be prescribed in terms of class B trust units and the conditions of ownership thereof.

In order not to disenfranchise any holders of exchangeable shares and to create clear rights with respect to the assets of the Corporation subject to claims against the Corporation, Unitholder approval was obtained to make appropriate amendments to the Royalty Indenture to create insolvency rights with respect to the assets of the Corporation which are economically similar to the rights of Trust Unitholders under the Trust Indenture and the Royalty Indenture. Although economically similar, these rights are distinct from the rights of holders of Trust Units in that the holders of exchangeable shares shall only have a claim against the assets of the Corporation if a Liquidation Event shall occur and shall have no claim against the cash or other assets of the Trust. The exchangeable shares, shall in the same manner as the common shares, be subject to claims made against the Corporation generally.

Upon a Liquidation Event, an amount will be withheld from the assets or monies available for distribution to royalty Unitholders under the royalty indenture to be paid to holders of the exchangeable shares and common shares representing the proportion of the economic interests in the Corporation represented by the exchangeable shares and in the common shares compared with the beneficial economic interest in the Corporation held by the Trust Unitholders (through the royalty units held by the Trust).

No exchangeable shares are currently issued or outstanding.

DISTRIBUTIONS

General

We currently make monthly payments to our Unitholders on the 15th day of each month or the first business day following the 15th day. The record date for any distribution is ten business days prior to the distribution date or such other date as may be determined by the Board of Directors. In accordance with stock exchange rules, an ex-distribution date occurs two trading days prior to the record date to permit time for settlement of trades of securities and distributions must be declared a minimum of seven trading days before the record date.

Historical Distributions

We currently have set the level of monthly cash distributions at $0.225 per Trust Unit. However, distributions can and may fluctuate in the future. The availability of cash flow for the payment of distributions is derived mainly from producing and selling our oil, natural gas and related products and as such will at all times be dependent upon a number of factors, including resource prices, production rates and contributions to the reserve fund. The Board of Directors will continue to examine distributions on a monthly basis while considering overall market conditions prior to setting the distribution level each month. The Board of Directors cannot assure you that cash flow will be available for distribution to Unitholders in the amounts anticipated or at all. See“Risk Factors”.

Distributions declared in 2007 and for the preceding five fiscal years were as follows:

	2007			2006		2005		2004		2003		2002
First Quarter	$	0.75		$	0.75	$	0.69	$	0.63	$	0.75	$	0.41
Second Quarter		0.75			0.75		0.69		0.64		0.67		0.54
Third Quarter		0.75			0.75		0.69		0.67		0.63		0.52
Fourth Quarter		0.675	(1)		0.75		0.75		0.69		0.63		0.60
Total	$	2.93		$	3.00	$	2.82	$	2.63	$	2.68	$	2.07

Notes:
(1)	On October 15, 2007, November 15, 2007 and December 15, 2007, the monthly distribution paid to Unitholders was $0.225 per Trust Unit, representing a reduction of 10 percent from the monthly distribution of $0.25 per Trust Unit for the first three quarters of 2007.

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(2) Based on actual distributions declared.

Since December 31, 2001, all amounts distributed to Unitholders have been treated as a return of capital, except for amounts classified as taxable income as set out in the following table:

	2007			2006			2005			2004			2003			2002
Taxable Income(1) (per Trust Unit)	$	2.78		$	2.40		$	2.22		$	1.43		$	1.47		$	0.45
(percent of distributions classified as taxable income)		(95	%)		(80	%)		(80	%)		(55	%)		(55	%)		(22	%)

Note:
(1)	For Canadian residents, amounts treated as a return of capital generally are not required to be included in a Unitholder’s income but such amounts will reduce the adjusted cost base to the Unitholder of the Trust Units.

At the special meeting of the Royalty Unitholders held on April 23, 2002, the Royalty Unitholders approved the amendment of the Royalty Indenture to permit the Board of Directors to establish a holdback, within the Corporation, of up to 20 percent of its gross revenue if the Board of Directors determines that it would be advisable to do so in accordance with prudent business practices to provide for the payment of future capital expenditures or for the payment of royalty income in any future period. Accordingly, the Corporation would be able to apply these amounts towards capital should it be prudent to do so or keep the funds in another form to be paid out in the future, potentially stabilizing the profile of distributions paid by the Trust. Subsequent to this Royalty Unitholder action, the Board of Directors authorized the establishment of a holdback to fund future capital obligations and future payments of royalty income to the Trust comprised of funds retained within the Corporation. The Board of Directors may change the distributions or the amount withheld in the future depending on a number of factors including future commodity prices, capital expenditure requirements and the availability of debt and equity capital.

The return on an investment in Trust Units is not comparable to the return on an investment in a fixed-income security. The recovery of the initial investment made by Unitholders is at risk, and the anticipated return on the Unitholder’s investment is based on many performance assumptions. Although we intend to make distributions of a portion of our available cash, these cash distributions may be reduced or suspended.Cash distributions are not guaranteed.Our ability to make cash distributions and the actual amount distributed will depend on numerous factors including, among other things: our financial performance, debt obligations, working capital requirements and future capital requirements, all of which are susceptible to a number of risks. In addition, the market value of the Trust Units may decline as a result of many factors, including our inability to meet our cash distribution targets in the future, and that decline may be significant. Prospective purchasers of Trust Units also should consider the particular risk factors that may affect the industry in which we operate, and therefore the stability of the distributions they would receive. See “Risk Factors”. This section also describes our assessment of those risk factors, as well as potential consequences to Unitholders if a risk should occur.

The after-tax return from an investment in Trust Units to Unitholders, for Canadian income tax purposes, can be made up of both a return on, and a return of, capital. That composition may change over time, thus affecting an investor’s after-tax return. Returns on capital are generally taxed as ordinary income or as dividends in the hands of a Unitholder. Returns of capital are generally tax-deferred for Unitholders who are resident in Canada for purposes of the Tax Act (and reduce such Unitholder’s adjusted cost base in the Trust Unit for purposes of the Tax Act). Returns of capital to a Unitholder who is not resident in Canada for purposes of the Tax Act or is a partnership that is not a “Canadian partnership” for purposes of the Tax Act will be subject to Canadian withholding tax. Prospective Unitholders should consult their own tax advisors with respect to the Canadian income tax considerations in their own circumstances. See “Certain Canadian Federal Income Tax Considerations” and “United States Federal Income Tax Considerations” in this Annual Information Form.

Restrictions on Distributions

The ability of the Trust to make cash distributions or return capital contributions to Unitholders may be directly or indirectly affected in certain events as a result of certain restrictions, including restrictions set forth in (i) the credit

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agreement relating to the Credit Facility; (ii) the note purchase agreements relating to the 2003 U.S. Senior Notes, the 2007 U.S. Senior Notes and the U.K. Senior Notes; and (iii) the Debentures. In particular, the funds required to satisfy the interest payable on the foregoing obligations, as well as the amounts payable upon the redemption or maturity of such obligations, as applicable, or upon an Event of Default (as defined below), will be deducted and withheld from the amounts that would otherwise be payable as distributions to Unitholders.

Revolving Credit Facility

The credit agreement relating to the Credit Facility stipulates that the Trust shall not make or agree to make cash or other distributions or return capital contributions to Unitholders when a “Default” (subject to certain exceptions) or an “Event of Default” has occurred or is continuing or would reasonably be expected to occur as a result of such distribution or return of capital. “Events of Default” are defined in the credit agreement to include those events of default which are typically referred to in a loan agreement of such type and include, among other things: (i) the failure to repay amounts owing under the Credit Facility; (ii) the voluntary or involuntary insolvency of the Trust or its subsidiaries; (iii) the default of obligations owing under other debt arrangements; (iv) the change of control of the Trust; or (v) the Trust’s divestiture of some or all of its debt or equity interest in the Corporation. “Default” is defined in the credit agreement to mean any event or circumstance which, with the giving of notice or lapse of time or otherwise, would constitute an Event of Default.

In addition to the standard representations, warranties and covenants commonly contained in a credit facility of this nature, the Credit Facility includes the following key financial covenants:

• the ratio of Consolidated Senior Debt (as defined below) to Consolidated EBITDA (as defined below) at the end of any fiscal quarter shall not exceed 3:1, except that upon the completion of a Material Acquisition (as defined below), and for a period extending to the end of the second full fiscal quarter thereafter, this limit increases to 3.5:1;

• the ratio of Consolidated Total Debt (as defined below) to Consolidated EBITDA at the end of any fiscal quarter shall not exceed 3.5:1; except that upon the completion of a Material Acquisition, and for a period extending to the end of the second full fiscal quarter thereafter, this limit increases to 4:1; and

• the ratio of Consolidated Senior Debt (as defined below) to Total Capitalization (as defined below) shall not exceed 50 percent, except that upon the completion of a Material Acquisition, and for a period extending to the end of the second full fiscal quarter thereafter, this limit increases to 55 percent.

With respect to these financial covenants, the following definitions apply to the Trust and its subsidiaries on a consolidated basis:

Consolidated Senior Debt:	All obligations, liabilities and indebtedness that would be classified as debt on the consolidated balance sheet of the Trust, including, without limitation, certain items including all indebtedness for borrowed money, but excluding certain items.
Consolidated Total Debt:	The aggregate of Consolidated Senior Debt and Subordinated Debt.
Consolidated EBITDA:	The aggregate of the last four quarters’ net income from operations plus the sum of:
	•   income taxes;
	•   interest expense;
	•   all provisions for federal, provincial or other income and capital taxes;
	•   depreciation, depletion and amortization expense; and
	•   other non-cash amounts.

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Material Acquisition:	An acquisition or series of acquisitions which increases the consolidated tangible assets of Pengrowth by more than 5 percent.
Subordinated Debt:	Debt which, by its terms, is subordinated to the obligations to the lenders under the Credit Facility.
Total Capitalization:	The aggregate of Consolidated Total Debt and the Unitholders’ equity (calculated in accordance with GAAP as shown on the Trust’s consolidated balance sheet)

Senior Unsecured Notes

The holders of the 2003 U.S. Senior Notes, the 2007 U.S. Senior Notes and the U.K. Senior Notes are entitled to certain remedies upon the occurrence of an “Event of Default”, which remedies may restrict the ability of the Trust to make distributions to Unitholders. The note agreements relating to the 2003 U.S. Senior Notes, the 2007 U.S. Senior Notes and the U.K. Senior Notes contain certain restrictions on the ability of the Corporation to make payments to the Trust if, at the time thereof or if after giving effect thereto, a “Default” or “Event of Default” would exist. In addition, in connection with the note agreements relating to the 2003 U.S. Senior Notes, the 2007 U.S. Senior Notes and the U.K. Senior Notes the Trust agreed that if it has actual knowledge that Default or an Event of Default has occurred and is continuing, it will not make any payment in respect of any distribution to unitholders. An “Event of Default” is defined in the note purchase agreements to include those events of default which are typically referred to in a note purchase agreement of a similar nature (including failure to pay principal and interest when due, default in compliance with other covenants, inaccuracy of representations and warranties, cross default to other indebtedness, certain events of insolvency or the rendering of judgments against the Trust of the notes in excess of certain threshold amounts). “Default” is defined in the note agreements to mean any event or circumstance which, with the giving of notice or lapse of time or both, would constitute an Event of Default.

In addition to standard representations, warranties and covenants, the 2003 U.S. Senior Notes, the 2007 U.S. Senior Notes and the U.K. Senior Notes also contain the following key financial covenants:

• the ratio of Consolidated EBITDA (as defined below) to interest expense for the four immediately preceding fiscal quarters shall be not less than 4:1;

• with respect to the 2003 U.S. Senior Notes and the U.K. Senior Notes only, the Consolidated Total Debt (as defined below) is limited to 60 percent of the Consolidated Total Established Reserves (as defined below) determined and calculated not later than the last day of the first fiscal quarter of the next succeeding fiscal year of the Trust;

• with respect to the 2007 U.S. Senior Notes only, the Consolidated Total Debt (as defined below) to Total Capitalization (as defined below) shall not exceed 55 percent at the end of each fiscal quarter; and

• the ratio of Consolidated Total Debt to Consolidated EBITDA for each period of four consecutive fiscal quarters shall not exceed 3.5:1.

With respect to these financial covenants, the following definitions apply to the Trust and its subsidiaries on a consolidated basis:

Consolidated EBITDA:	The sum of the last four quarters of: (i) net income determined in accordance with GAAP; (ii) all provisions for federal, provincial or other income and capital taxes; (iii) all provisions for depletion, depreciation, and amortization; (iv) interest expense; and (v) non-cash items.
Consolidated Total Debt:	Has substantially the same meaning as “Consolidated Senior Debt” in the definitions relating to the Credit Facility.
Consolidated Total Established Reserves:	The sum of: (i) 100 percent of the present value of Pengrowth’s proved reserves; and (ii) 50 percent of the present value of Pengrowth’s probable reserves.

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Total Capitalization: Consolidated Total Debt plus Unitholder equity in the Trust.

Convertible Debentures

In connection with the business combination with Esprit Energy Trust, Pengrowth assumed all obligations relating to the Debentures then outstanding. As at December 31, 2007, Pengrowth had $74.7 million principal amount of Debentures outstanding. Each $1,000 principal amount of Debentures is convertible at the option of the holder at any time into Trust Units at a conversion price of $25.54 per Trust Unit. The Debentures mature on December 31, 2010. After December 31, 2008, Pengrowth may elect to redeem all or a portion of the outstanding Debentures at a price of $1,050 per Debenture or $1,025 per Debenture after December 31, 2009. On December 12, 2006 Pengrowth redeemed a portion of the 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). See the discussion above under the heading “General Development of Pengrowth Energy Trust – Recent Developments – Changes to Tax Legislation Affecting Pengrowth and its Unitholders and its Debentureholders” for the recent changes to the Tax Act which eliminate Canadian withholding tax on interest paid or credited to non-residents.

The holders of the Debentures are entitled to certain remedies upon an “Event of Default”, which remedies may restrict the ability of the Trust to make distributions to Unitholders. In particular, the Trust is prohibited from declaring or making distributions to Unitholders upon the occurrence of an Event of Default unless and until each such default has been cured or waived or ceases to exist. Furthermore, the Trust is prohibited from declaring any distribution to Unitholders if, at the time the Corporation resolves, as administrator of the Trust, to make the said declaration, the Corporation has actual knowledge that the paying of the said distribution would result in an Event of Default. An “Event of Default” will occur if any one or more of the following described events has occurred and is continuing with respect to the Debentures: (a) failure for ten days to pay interest on the Debentures when due; (b) failure to pay principal or premium, if any, when due on the Debentures, whether at maturity, upon redemption, by declaration or otherwise; (c) certain events of bankruptcy, insolvency or reorganization of the Trust under applicable bankruptcy or insolvency laws; or (d) default in the observance or performance of any material covenant or condition of the Debenture Indenture and continuance of such default for a period of 30 days after notice in writing has been given by the trustee under the Debenture Indenture, as amended, to the Trust specifying such default and requiring the Trust to rectify the same.

The Debenture Indenture, as amended, includes, amongst others, the following covenants:

• the Trust is required to punctually pay or cause to be paid all principal, premium and interest amounts as prescribed by the Debenture Indenture, as amended;

• the Trust is required to pay the trustee under the Debenture Indenture reasonable remuneration for its services as trustee and repay on demand all monies which have been paid by the trustee in execution of its obligations thereunder;

• the Trust is required to provide the trustee under the Debenture Indenture with notification immediately upon obtaining knowledge of any Event of Default;

• the Trust is required to carry on its business in a proper, efficient and business-like manner and in accordance with good business practices;

• the Trust is required to deliver to the trustee under the Debenture Indenture, within 120 days of the end of each calendar year, an officer’s certificate as to compliance with the terms and conditions of the Debenture Indenture; and

• the Trust is prohibited from issuing additional debentures, which are convertible at the option of the holder into Trust Units of equal ranking to the Debentures if the principal amount of all

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issued and outstanding convertible debentures of the Trust would exceed 25 percent of the Trust’s total market capitalization after the issuance of such additional debentures.

CERTAIN CANADIAN FEDERAL INCOME TAX CONSIDERATIONS

Taxation of the Trust

SIFT Legislation

On October 31, 2006, the Minister of Finance (Canada) (“Finance”) announced new proposals (the “October 31 Proposals”) that will change the manner in which certain flow-through entities, including mutual fund trusts, referred to as “specified investment flow-through” entities or “SIFTs”, and the distributions from such entities are taxed. The October 31 Proposals will apply a tax at the trust level on distributions of certain income from such a SIFT entity at a rate of tax comparable to the combined federal and provincial corporate tax rate and will result in the distributions from SIFT entities being treated as dividends to the recipient. The October 31 Proposals became law when Bill C-52 received Royal Assent on June 22, 2007.

It is expected that the Trust will be characterized as a SIFT trust and as a result will be subject to the SIFT Legislation. The SIFT Legislation will not apply to SIFTs that were publicly traded on October 31, 2006 (“Grandfathered SIFTs”), such as Pengrowth, until January 1, 2011. However, the SIFT Legislation indicates that any “undue expansion” of a Grandfathered SIFT between October 31, 2006 and January 1, 2011 (the “Interim Period”), may cause the application of the SIFT Legislation to the Grandfathered SIFT to occur before January 1, 2011. Following the October 31, 2006 announcement, Finance issued a press release on December 15, 2006 wherein it provided guidelines (the “Normal Growth Guidelines”) as to what would be considered “normal growth” as opposed to “undue expansion”. The Normal Growth Guidelines are incorporated by reference into the SIFT Legislation.

Under the existing provisions of the Tax Act, Pengrowth can generally deduct in computing its income for a taxation year any amount of income that it distributes to Unitholders in the year and, on that basis, Pengrowth is generally not liable for any material amount of tax. The SIFT Legislation will change the manner in which the Trust and its distributions are taxed beginning January 1, 2011 (provided that the Trust is not considered to have undergone an “undue expansion” during the Interim Period, as set out in the Normal Growth Guidelines, which could result in the SIFT Legislation applying to the Trust at an earlier date). More specifically, the Trust will not be able to deduct certain portions of its distributed income (referred to as “specified income”) and will become subject to a distribution tax on such specified income at a special tax rate that approximates the tax rate applicable to a taxable Canadian corporation. The SIFT Legislation characterizes specified income to include: (i) income (other than dividends that the Trust could, if it were a corporation, deduct under the Tax Act) from the Trust’s non-portfolio properties; and (ii) taxable capital gains from the Trust’s dispositions of non-portfolio properties. Under the current SIFT Legislation, the proposed tax will be 29.5 percent in 2011 and 28 percent in 2012, based upon a 13 percent provincial tax rate and a federal tax rate of 16.5 percent reducing to 15 percent in 2012.T On February 26, 2008, the Minister released the Budget. The Budget proposes to replace this 13% provincial tax rate with the applicable provincial income tax rates for each province in which the SIFT has a permanent establishment, based on a provincial allocation formula. To simplify the application of the SIFT Legislation, we have assumed a provincial tax rate of 10%, being the applicable rate in Alberta where we anticipate 78 percent of our revenue will be generated in 2008. In accordance with this assumption and subject to the availability of tax pools, the application of the SIFT Legislation will reduce the amount of cash available to the Trust to distribute to its Unitholders by an amount equal to 26.5 percent in 2011 (and by 25 percent in 2012 and thereafter) multiplied by the amount of the pre-tax income distributed by the Trust. There can be no assurance that the Budget will become law and, until it does, the proposed reduction to the provincial tax rate will not become effective.

Distributions of the Trust’s income received by Unitholders beginning January 1, 2011 will be characterized as taxable dividends received from a taxable Canadian corporation and for a person resident in Canada, the taxable dividends will also qualify as eligible dividends.

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Pursuant to the SIFT Legislation, the distribution tax will only apply in respect of distributions of income and will not apply to returns of capital. Accordingly, Pengrowth has the opportunity to reduce the impact of the SIFT Legislation after January 1, 2011 by applying available tax pools to enable a portion of distributions to be paid by way of a return of capital. As a result of the enactment of the SIFT Legislation, the Trust recorded a future income tax reduction in the second quarter of 2007 to reflect temporary differences in the Trust. See note 11 to our audited annual consolidated financial statements for the year ended December 31, 2007.

The SIFT Legislation indicates that no change will be recommended to the 2011 date in respect of any SIFT whose equity capital grows as a result of issuances of new equity (which includes trust units, debt that is convertible into trust units, and potentially other substitutes for such equity), before 2011, by an amount that does not exceed the greater of $50 million and an objective “safe harbour” amount based on a percentage of the SIFT’s market capitalization as of the end of trading on October 31, 2006 (measured in terms of the value of a SIFT’s issued and outstanding publicly-traded units, not including debt, options or other interests that were convertible into units of the SIFT). However, under the SIFT Legislation, in the event that the Trust issues additional Trust Units or convertible debentures (or other equity substitutes) on or before 2011, the Trust may become subject to the SIFT Legislation prior to 2011.No assurance can be provided that the SIFT Legislation will not apply to the Trust prior to 2011.Loss of this status may result in material adverse tax consequences for the Trust and its Unitholders. However, it is assumed for the purposes of this Annual Information Form, that the Trust will not be subject to the SIFT Legislation until January 1, 2011.

The Normal Growth Guidelines provide that a SIFT’s safe harbour will be 40 percent of the October 31, 2006 benchmark for the period from November 1, 2006 to the end of 2007 and will be 20 percent of the October 31, 2006 benchmark for 2008, 2009 and 2010. Pengrowth’s market capitalization on October 31, 2006 was approximately $4.8 billion. Pengrowth has issued additional equity after October 31, 2006 of approximately $517 million. Accordingly, Pengrowth may currently issue additional equity without offending the Normal Growth Guidelines of approximately $1.4 billion, and may issue approximately $960 million of additional equity for each of 2008, 2009 and 2010. Unused portions may be carried forward until December 31, 2010. Pengrowth has adhered to the normal growth limits from October 31, 2006 to the date hereof.

The SIFT Legislation will result in material and adverse tax consequences to the Trust and its Unitholders (most particularly investors that are tax exempt or non-residents of Canada as such Unitholders are not entitled to the benefit of the eligible dividend tax treatment that is available to taxable Canadian individuals). It is expected that the imposition of tax at the trust level under the October 31 Proposals will materially reduce the amount of cash available for distributions to Unitholders.

Taxation of Unitholders Resident in Canada

Under the existing provisions of the Tax Act, a Unitholder that is a resident of Canada for purposes of the Tax Act is generally required to include in computing income for a particular taxation year that portion of the net income of the Trust that is paid or payable to the Unitholder in that taxation year and such income to the Unitholder will generally be considered to be ordinary income from property.

Pursuant to the SIFT Legislation, amounts in respect of the Trust’s income payable to Unitholders that is not deductible by the Trust will be treated as a taxable dividend from a taxable Canadian corporation. Dividends received or deemed to be received by an individual (other than certain trusts) will be included in computing the individual’s income for tax purposes and will be subject to the enhanced gross-up and dividend tax credit rules under the Tax Act normally applicable to eligible dividends received from taxable Canadian corporations. Dividends received or deemed to be received by a holder that is a corporation will generally be deductible in computing the corporation’s taxable income. Certain corporations, including private corporations or subject corporations (as such terms are defined in the Tax Act), may be liable to pay a refundable tax under Part IV of the Tax Act of 33 1/3 percent on dividends received or deemed to be received to the extent that such dividends are deductible in computing taxable income. Unitholders that are trusts governed by registered retirement savings plans, registered retirement income funds, registered education savings plans and deferred profit sharing plans as defined in the Tax Act (referred to herein as “Exempt Plans”) will generally continue not to be liable for tax in

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respect of any distributions received from the Trust. Although the SIFT Legislation will not increase the tax payable by Exempt Plans in respect of dividends deemed to be received from the Trust, it is expected that the imposition of tax at the Trust level under the SIFT Legislation will materially reduce the amount of cash available for distributions to Unitholders.

Returns of capital are, and will be under the SIFT Legislation, generally tax deferred for Unitholders who are resident in Canada for purposes of the Tax Act and will reduce such Unitholder’s adjusted cost base in the Trust Units for purposes of the Tax Act.

Taxation of Unitholders who are Non-Residents of Canada

Under the existing provisions of the Tax Act, any distribution of income by the Trust to a non-resident of Canada (“Non-Resident Unitholder”) will be subject to Canadian withholding tax at the rate of 25 percent unless such rate is reduced under the provisions of a convention between Canada and the Non-Resident Unitholder’s jurisdiction of residence. A Non-Resident Unitholder resident in the United States who is entitled to claim the benefit of the Canada-U.S. Convention, will generally be entitled to have the rate of withholding reduced to 15 percent of the amount of any income distributed. Under the Canada-U.S. Convention, certain tax-exempt organizations resident in the U.S. may be entitled to an exemption from Canadian withholding tax.

Pursuant to the SIFT Legislation, amounts in respect of the Trust’s income payable to Non-Resident Unitholders that are not deductible to the Trust will be treated as a taxable dividend from a taxable Canadian corporation. Such dividends will be subject to Canadian withholding tax at a rate of 25 percent, unless such rate is reduced under the provisions of a convention between Canada and the Non-Resident Unitholder’s jurisdiction of residence. A Non-Resident Unitholder resident in the United States who is entitled to claim the benefit of the Canada-US Convention generally will be entitled to have the rate of withholding reduced to 15 percent of the amount of such dividend. Although the SIFT Legislation may not increase the tax payable by Non-Resident Unitholders in respect of dividends deemed to be paid by the Trust, it is expected that the imposition of tax at the Trust level under the SIFT Legislation will materially reduce the amount of cash available for distributions to Unitholders.

Returns of capital to a Unitholder who is not a resident of Canada for purposes of the Tax Act or is a partnership that is not a “Canadian partnership” for purposes of the Tax Act are, and will be under the SIFT Legislation, subject to a 15 percent Canadian withholding tax.

On September 21, 2007, Canada and the United States signed the Protocol to the Canada-U.S. Convention. The Protocol must be ratified in Canada and the US prior to becoming effective. Canada ratified the Protocol on December 14, 2007, however, the Protocol has not yet been ratified by the US. The Protocol will come into force when the ratification procedures have been completed in Canada and the US. The Protocol contains new Article IV(7)(b), a treaty benefit denial rule, which would increase the Canadian withholding tax on Pengrowth’s distributions (which for the purposes of this paragraph includes deemed dividends pursuant to the SIFT Legislation) to Non-Resident Unitholders who are residents of the US for the purposes of the Canada-US Convention. Article IV(7)(b) of the Protocol is not suppose to come into force until the first day of the third calendar year that ends after the Protocol is in force. Article IV(7)(b) of the Protocol generally denies benefits under the Canada-US Convention in circumstances where (i) a Non-Resident Unitholder who is a resident of the US for the purposes of the Canada-US Convention receives an amount, such as a distribution, from an entity that is a resident of Canada, such as the Trust, (ii) the Trust is treated as a fiscally transparent entity for US federal income tax purposes, which is the case inasmuch as Pengrowth is treated as a partnership for US federal income tax purposes, and (iii) the tax treatment of the amount (or distribution) received by the Non-Resident Unitholder would, for US federal income tax purposes, be different if Pengrowth were not treated as fiscally transparent for US federal income tax purposes. The effect of Article IV(7)(b) of the Protocol is that the Canadian withholding tax rate on distributions of income would be 25 percent instead of 15 percent or such lower rate that is otherwise available under the Canada-U.S. Convention. Returns of capital would still be subject to a 15 percent Canadian withholding tax and such rate is not modified by the Protocol. The Protocol also contains measures which, generally speaking, are designed to limit the benefits under the Canada-U.S. Convention to “treaty shopping” transactions or arrangements.

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Subject to certain limitations set forth in the United States Internal Revenue Code of 1986, as amended, United States holders may elect to claim a foreign tax credit against their United States federal income tax liability for net Canadian income tax withheld from distributions received in respect of Trust Units that is not refundable to the United States holder and for any Canadian income taxes paid by us. The SIFT Legislation will apply a tax at the trust level on distributions of certain income from a SIFT trust. It is unclear whether this tax will constitute an income tax or a tax imposed “in lieu” thereof for purposes of the foreign tax credit rules; if it does not constitute such a tax it will not be creditable. The limitation on foreign taxes eligible for credit is calculated separately with respect to specific classes of income. Distributions with respect to Trust Units will be “passive category income” or “general category income” for purposes of computing the foreign tax credit allowable to a United States holder. If the tax at the trust level on distributions of certain income from a SIFT trust constitutes a creditable tax, such distributions likely would be “general category income” for purposes of computing the foreign tax credit allowable to a United States holder. The rules and limitations relating to the determination of the foreign tax credit are complex and prospective purchasers are urged to consult their own tax advisors to determine whether or to what extent they would be entitled to such credit. United States persons that do not elect to claim foreign tax credits may instead claim a deduction for their share of Canadian income taxes paid by us or withheld from distributions by us.This Annual Information Form may not describe the United States tax consequences of the purchase, holding or disposition of the Trust Units fully. Non-Resident Unitholders should obtain independent tax advice as necessary.

The SIFT Legislation will have a material and adverse impact on the Trust and its Unitholders. Unitholders are urged to consult their own tax advisors having regard to their own particular circumstances including the impact of the SIFT Legislation on the Trust and Unitholders. See “Risk Factors — The SIFT Legislation is expected to materially and adversely affect the Trust, the Unitholders and the value of the Trust Units.”

UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS

The following discussion is a summary of certain United States federal income tax consequences of the ownership and disposition of Trust Units. This discussion is based on theU.S. Internal Revenue Code of 1986, as amended (the “Code”), administrative pronouncements, judicial decisions, existing and proposed Treasury regulations, and interpretations of the foregoing, all as of the date hereof. All of the foregoing authorities are subject to change (possibly with retroactive effect), and any such change may result in United States federal income tax consequences to a Unitholder that are materially different from those described below. No rulings from the United States Internal Revenue Service (the “IRS”) have been or will be sought with respect to the matters described below, and consequently, the IRS may not take a similar view of the consequences described below.

The following discussion does not purport to be a full description of all United States federal income tax considerations that may be relevant to a United States holder (as defined below) in light of such Unitholder’s particular circumstances and only addresses Unitholders who hold Trust Units as capital assets within the meaning of Section 1221 of the Code. Furthermore, this discussion does not address the United States federal income tax considerations applicable to Unitholders subject to special rules, such as (i) persons that are not United States holders, (ii) certain financial institutions, real estate investment trusts, regulated investment companies or insurance companies, (iii) persons subject to the alternative minimum tax, (iv) traders in securities that elect to use a mark-to-market method of accounting, (v) dealers in securities or currencies, (vi) persons holding Trust Units in connection with a hedging transaction, “straddle,” conversion transaction or other integrated transaction, (vii) persons whose “functional currency” is not the United States dollar and (viii) U.S. expatriates. In addition, except as otherwise indicated, this discussion does not include any description of any estate and gift tax consequences, or the tax laws of any state, local or foreign government that may be applicable.

As used herein, the term “United States holder” means a beneficial owner of a Trust Unit that is (i) an individual citizen or resident of the United States, (ii) a corporation or other entity taxable as a corporation organized in or under the laws of the United States or any political subdivision thereof, (iii) an estate the income of which is subject to United States federal income taxation without regard to the source or (iv) a trust if a United States court has primary supervision over its administration and one or more United States persons have the authority to

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control all substantial decisions of the trust, or if the trust has a valid election in effect under applicable Treasury Regulations to be treated as a United States person.

If a partnership (or an entity taxable as a partnership for United States federal income tax purposes) holds our Trust Units, the United States federal income tax treatment of a partner generally will depend on the status of the partner and the activities of the partnership. A United States person that is a partner of a partnership (or an entity taxable as a partnership for United States federal income tax purposes) holding our Trust Units should consult its own tax advisors.

UNITED STATES HOLDERS SHOULD CONSULT THEIR TAX ADVISORS WITH REGARD TO THE APPLICATION OF UNITED STATES FEDERAL INCOME TAX LAWS TO THEIR PARTICULAR SITUATIONS, AS WELL AS ANY TAX CONSEQUENCES ARISING UNDER THE LAWS OF ANY STATE, LOCAL OR FOREIGN TAXING JURISDICTION.

Classification of Pengrowth Energy Trust as a Partnership

We have elected under applicable Treasury Regulations to be treated as a partnership for United States federal income tax purposes. Although there is no plan or intention to do so, we have the right to elect under applicable Treasury Regulations to be treated as a corporation for United States federal income tax purposes, if such election were determined to be beneficial.

A partnership generally is not treated as a taxable entity and incurs no United States federal income tax liability. Instead, as discussed below, each partner in an entity treated as a partnership for tax purposes is required to take into account its allocable share of items of income, gain, loss and deduction of the partnership in computing its United States federal income tax liability, regardless of whether cash or other distributions are made. Distributions by a partnership to a partner are generally not taxable unless the amount of any cash distributed is in excess of the partner’s adjusted basis in its partnership interest (see “Certain Income Tax Considerations — United States Federal Income Tax Considerations — Tax Consequences of Trust Unit Ownership” below). Each Unitholder will be treated as a partner in the Trust for United States federal income tax purposes.

Section 7704 of the Code provides that publicly-traded partnerships such as the Trust will, as a general rule, be taxed as corporations. However, an exception (the “Qualifying Income Exception”) exists with respect to publicly-traded partnerships of which 90 percent or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes interest (from other than a financial business), dividends, rents from real property, oil and gas royalty income, gains from the sale of oil and gas properties, and gains derived from the exploration, development, mining or production, processing, refining, transportation or the marketing of oil and gas. Royalty income received by the Trust from Pengrowth should be treated as qualifying income. We believe that at least 90 percent of our income for the current year will be qualifying income and that we have met the qualifying income exception since we first elected to be treated as a partnership for United States federal income tax purposes in 1997. We expect that we will continue to meet the qualifying income exception in 2008 and thereafter. However, no assurance can be given that the qualifying income exception will in fact be met.

Possible Classification as a Corporation; PFIC Rules

If we fail to meet the Qualifying Income Exception (other than a failure which is determined by the IRS to be inadvertent and which is cured within a reasonable time after discovery), we will be treated as if we transferred all of our assets (subject to liabilities) to a newly formed corporation (on the first day of the year in which we fail to meet the Qualifying Income Exception) in return for stock in that corporation, and then distributed that stock to our owners in liquidation of their interests in us. That deemed transfer and liquidation would likely be taxable to United States holders. Thereafter, we would be treated as a corporation for federal income tax purposes. United States holders would be required to file IRS Form 926 to report the deemed transfer and any other transfers made to the Trust while it is treated as a corporation.

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If we were treated as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would not be passed through to United States holders. Instead, United States holders would be taxed upon the receipt of distributions, either pursuant to the passive foreign investment company (“PFIC”) rules discussed below or, if those rules are not applicable (or if the United States holder makes certain elections pursuant to those rules), as either taxable dividend income (to the extent of our current or accumulated earnings and profits calculated by reference to our tax basis in our assets without regard to the price paid for Trust Units by subsequent United States holders) or (in the absence of earnings and profits) a nontaxable return of capital (to the extent of the United States holder’s tax basis in its Trust Units) or taxable capital gain (after the United States holder’s tax basis in the Trust Units is reduced to zero). If we were treated as a corporation, it is possible that we would be considered a PFIC, in which case special rules (discussed below), potentially quite adverse to United States holders, would apply.

Consequences of Possible PFIC Classification

A non-United States entity treated as a corporation for United States federal income tax purposes will be a PFIC in any taxable year in which, after taking into account the income and assets of the corporation and certain subsidiaries pursuant to the applicable “look through” rules, either (1) at least 75 percent of its gross income is “passive” income (the “income test”) or (2) at least 50 percent of the average value of its assets is attributable to assets that produce passive income or are held for the production of passive income (the “assets test”).

We currently believe that, if classified as a corporation, we would not be a PFIC. Because PFIC status is fundamentally factual in nature, generally cannot be determined until the close of the taxable year in question and is determined annually, no assurance can be given that, if we were a corporation, we would not be now, and would not be in the future, a PFIC.

If we were classified as a PFIC, for any year during which a United States holder owns Trust Units, the United States holder would generally be subject to special rules (regardless of whether we continue to be a PFIC) with respect to (1) any “excess distribution” (generally, any distribution received by the United States holder on Trust Units in a taxable year that is greater than 125 percent of the average annual distributions received by the United States holder in the three preceding taxable years or, if shorter, the United States holder’s holding period for the Trust Units) and (2) any gain realized upon the sale or other disposition of Trust Units. Under these rules:

• the excess distribution or gain would be allocated ratably over the United States holder’s holding period;

• the amount allocated to the current taxable year and any year prior to the first year in which we were a PFIC would be taxed as ordinary income in the current year;

• the amount allocated to each of the other taxable years in the United States holder’s holding period would be subject to tax at the highest rate of tax in effect for the applicable class of taxpayer for that year; and

• an interest charge for the deemed deferral benefit would be imposed with respect to the resulting tax attributable to each such other taxable year.

A United States holder would also generally be subject to similar rules with respect to distributions to us by, and dispositions by us of the stock of, any direct or indirect subsidiary of the Trust that is also a PFIC.

Certain elections may be available to a United States holder if we were classified as a PFIC. We will provide United States holders with information concerning the potential availability of such elections if we determine that we are or will become a PFIC.

The discussion below is based on the assumption that we will be treated as a partnership for United States federal income tax purposes.

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Tax Consequences of Trust Unit Ownership

Flow-through of Taxable Income

Each United States holder will be required to report on its income tax return its allocable share (based on the percentage of Trust Units owned by that United States holder) of our income, gains, losses and deductions for the taxable year of the Trust ending with or within the taxable year of the United States holder without regard to whether corresponding cash distributions are received by such United States holder. Consequently, a United States holder may be allocated income from the Trust even if it has not received a cash distribution from us.

We intend to make available to each United States holder, within 75 days after the close of each calendar year, a Substitute Schedule K-1 containing its share of our income, gain, loss and deduction for the preceding Trust taxable year.

We treat the Royalty between us and Pengrowth as a royalty interest for all legal purposes, including United States federal income tax purposes. The Royalty Indenture in some respects differs from more conventional “net profits” interests as to which the courts and the IRS have ruled regarding the U.S. federal income tax treatment as a royalty, and as a result the propriety of such treatment is not free from doubt. It is possible that the IRS could contend, for example, that we should be considered to have a working interest in the properties of Pengrowth. If the IRS were successful in making such a contention, the United States federal income tax consequences to United States holders could be different, perhaps materially worse, than indicated in the discussion herein, which generally assumes that the Royalty Indenture will be respected as a royalty.

Treatment of Distributions

Distributions by us to a United States holder generally will not be taxable to the United States holder for federal income tax purposes to the extent of its tax basis in its Trust Units immediately before the distribution. Cash distributions in excess of a United States holder’s tax basis generally will be considered to be gain from the sale or exchange of the Trust Units, taxable in accordance with the rules described under “Certain Income Tax Considerations – United States Federal Income Considerations – Disposition of Trust Units” below.

Basis of Trust Units

A United States holder’s initial tax basis for its Trust Units will be the amount paid for the Trust Units. That basis will be increased by its share of our income and decreased (but not below zero) by distributions to it from us, by the United States holder’s share of our losses and deductions, and by its share of our expenditures that are not deductible in computing our taxable income and are not required to be capitalized. See “Certain Income Tax Considerations – United States Federal Income Tax Considerations – Disposition of Trust Units–Recognition of Gain or Loss” below.

Limitations on Deductibility of Losses

There are limitations on the ability of a United States holder to deduct any losses we generate from our activities under the basis limitation rules, the at-risk rules and the passive activity loss rules. Special passive activity loss rules apply to a publicly-traded partnership such as the Trust, and preclude passive activity losses generated by us from being used against passive income generated by other passive activities or against portfolio income generated by us.

It is not anticipated that we will generate losses. Nevertheless, should losses result, United States holders should consult their own tax advisors as to the applicability to them of such loss limitations.

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Limitations on Interest Deductions

The deductibility of a non-corporate taxpayer’s “investment interest expenses” is generally limited to the amount of such taxpayer’s “net investment income.” Investment interest expense includes (i) interest on indebtedness properly allocable to property held for investment and (ii) the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income. The computation of a United States holder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or own Trust Units. Net investment income includes gross income from property held for investment and amounts treated as portfolio income pursuant to the passive loss rules less deductible expenses (other than interest) directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment.

Foreign Tax Credits

Subject to certain limitations set forth in the Code, United States holders may elect to claim a credit against their United States federal income tax liability for net Canadian income tax withheld from distributions received in respect of the Trust Units that is not refundable to the United States holder. Subject to these limitations, United States holders will also be entitled to claim a foreign tax credit for any Canadian income taxes paid by us. The limitation on foreign taxes eligible for credit is calculated separately with respect to specific classes of income. Distributions will be “passive category income” or “general category income” for purposes of computing the foreign tax credit allowable to a United States holder. Beginning January 1, 2011, the SIFT Legislation will apply a tax at the trust level on distributions of certain income from a SIFT trust. It is unclear whether this tax will constitute an income tax or a tax imposed “in lieu” thereof for purposes of the foreign tax credit rules; if it does not constitute such a tax it will not be creditable. The rules and limitations relating to the determination of the foreign tax credit are complex and prospective purchasers are urged to consult their own tax advisors to determine whether or to what extent they would be entitled to such credit. United States persons that do not elect to claim foreign tax credits may instead claim a deduction for their share of Canadian income taxes paid by us or withheld from distributions by us.

Functional Currency

Because our functional currency is the Canadian dollar, a United States holder will be required to translate our items of income and deduction, which will be initially determined by us in the Canadian dollar, into United States dollars prior to including its share thereof on its United States federal income tax return. Under regulations that have been proposed by the United States Treasury Department, a United States holder who owns directly and indirectly less than five percent of the Trust Units can elect not to take into account as additional income foreign currency translation income or loss (which would be ordinary income or loss) in respect of certain of our financial assets and liabilities on the receipt of certain distributions and upon certain dispositions. The proposed Treasury Regulations state that the IRS will consider positions consistent with the proposed regulations to be reasonable interpretations of the Code until the proposed regulations are finalized. There can be no assurance as to the time at which any regulations will be finalized or as to the effect of any such regulations.

Tax Treatment of Trust Operations

Accounting Method and Taxable Year

We use the year ending December 31 as our taxable year and have adopted the accrual method of accounting for United States federal income tax purposes.

Depletion

Under the Code, a United States holder may deduct in its United States federal income tax return a cost depletion allowance with respect to the royalty units issued by Pengrowth to the Trust. United States holders must compute their own depletion allowance and maintain records of the adjusted basis of the royalty units for depletion and

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other purposes. We, however, intend to furnish each United States holder with information relating to this computation.

Cost depletion is calculated by dividing the adjusted basis of a property by the total number of units of oil or gas expected to be recoverable therefrom and then multiplying the quotient by the number of units of oil and gas sold during the year. Cost depletion, in the aggregate, cannot exceed the initial adjusted basis of the property. In this connection, we intend to utilize a tax election, known as a Section 754 election and discussed below, which will allow purchasers of Trust Units to be entitled to depletion deductions based upon their purchase price for the Trust Units.

The depletion allowance must be computed separately by each United States holder for each oil and gas property, within the meaning of Section 614 of the Code. The IRS is currently taking the position that a single net profits interest carved from multiple properties is a single property for depletion purposes. The Royalty Indenture burdens multiple properties. Accordingly, although it may be modified to take into account subsequent acquisitions, we intend to take the position that the properties subject to the Royalty Indenture constitute a single property for depletion purposes and the income from the net profits interest will be royalty income qualifying for an allowance for depletion. This result is not clear, however, and we would change this position if it should be determined that a different method of computing the depletion allowance is required by law.

Depreciation

The tax basis of our depreciable assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition, of such assets.

Valuation of Our Properties

Certain of the United States federal income tax consequences of the ownership and disposition of Trust Units will depend in part on our estimates of the relative fair market value of our assets. Although we may consult from time to time with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates. These estimates are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by United States holders might change, and United States holders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Section 754 Election

We have made the election permitted by Section 754 of the Code. That election is irrevocable without the consent of the IRS. The election generally requires us, in the case of a sale of the Trust Units in the secondary market, to adjust the tax basis in our assets pursuant to Section 743(b) of the Code to reflect the purchaser’s purchase price of its Trust Units. The Section 743(b) adjustment belongs to the purchaser and not to other partners.

A Section 754 election is advantageous if the purchaser’s tax basis in its Trust Units is higher than its share of our aggregate tax basis in our assets immediately prior to the purchase. In such a case, as a result of the election, the purchaser would have a higher tax basis in its share of our assets for purposes of calculating, among other things, depletion and depreciation. Conversely, a Section 754 election is disadvantageous if the purchaser’s tax basis in such Trust Units is lower than its share of our aggregate tax basis immediately prior to the transfer. Thus, the fair market value of the Trust Units may be affected either favorably or adversely by the election.

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Disposition of Trust Units

Recognition of Gain or Loss

Gain or loss will be recognized on a sale of Trust Units equal to the difference between the amount realized and the United States holder’s tax basis for the Trust Units sold. Subject to the discussion of recapture income, the gain or loss recognized by a United States holder on the sale or exchange of Trust Units will generally be taxable as capital gain or loss, and will be long-term capital gain or loss if such United States holder’s holding period of the Trust Units exceeds one year. In the case of a non-corporate United States holder, any such long-term capital gain may be subject to tax at a reduced rate. Certain limitations apply to the deductibility of capital losses.

A portion of any amount realized on a sale or exchange of Trust Units (which portion could be substantial) will be separately computed and taxed as ordinary income under Section 751 of the Code to the extent attributable to the recapture of depletion or depreciation deductions. Ordinary income attributable to depletion deductions and depreciation recapture could exceed net taxable gain realized upon the sale of the Trust Units and may be recognized even if there is a net taxable loss realized on the sale of the Trust Units. Thus, a United States holder may recognize both ordinary income and a capital loss upon a taxable disposition of Trust Units.

The IRS has ruled that a person who acquires interests in an entity, such as the Trust, which is treated as a partnership for United States federal income tax purposes in separate transactions at different prices must combine those interests and maintain a single adjusted tax basis. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be ratably allocated to the interests sold and retained using an “equitable apportionment” method. Although the ruling is unclear as to how the holding period of these interests is determined once they are combined, regulations allow a seller of such an interest who can identify the interest sold with an ascertainable holding period to elect to use that holding period. Thus, according to the ruling, a United States holder will be unable to select high or low basis Trust Units to sell as would be the case with corporate stock but, according to the regulations, may designate Trust Units sold for purposes of determining the holding period of the Trust Units sold. A United States holder electing to use this approach must consistently use that approach for all subsequent sales and exchanges of Trust Units. It is not clear whether the ruling applies to the Trust because, similar to corporate stock, separate interests in the Trust are readily ascertainable and may be evidenced by separate certificates. A United States holder considering the purchase of additional Trust Units or the sale of Trust Units purchased in separate transactions should consult its own tax advisor regarding the application of this ruling and the regulations.

Allocations between Transferors and Transferees

In general, in reporting tax information for United States holders our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the United States holders in proportion to the number of Trust Units owned by each of them on the first business day of the month (the “allocation date”). However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business, and other extraordinary items, will be allocated among the United States holders on the allocation date in the month in which that gain or loss is recognized.

Notification Requirements

A United States holder that sells or exchanges Trust Units is required to notify us in writing of that sale or exchange within 30 days after the sale or exchange and in any event by no later than January 15 of the year following the calendar year in which the sale or exchange occurred. We are required to notify the IRS of that transaction and to furnish certain information to the transferor and transferee. However, these reporting requirements do not apply with respect to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker. Additionally, a transferor and a transferee of Trust Units will be required to furnish statements to the IRS, filed with its income tax return for the taxable year in which the sale or exchange occurred, that allocates the consideration paid for the Trust Units. We will provide this information to

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you in the event of a transfer. Failure to satisfy these reporting obligations may lead to the imposition of substantial penalties.

Constructive Termination

We will be considered to have been terminated for United States federal income tax purposes if there is a sale or exchange of 50 percent or more of the total Trust Units within a 12-month period. A termination of the Trust will result in a decrease in tax depreciation available to the United States holders thereafter and in the closing of our taxable year for all United States holders. In the case of a United States holder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than 12 months’ taxable income or loss of the Trust being includable in its taxable income for the year of termination. New tax elections would have to be made by us, including a new election under Section 754 of the Code. Adverse tax consequences could ensue if we were unable to determine that the termination had occurred. Finally, a termination of the Trust could result in taxation of the Trust as a corporation if the Qualifying Income Exception were not met in the short taxable years caused by termination. See “Certain Income Tax Considerations – United States Federal Income Tax Considerations – Classification of the Trust as a Partnership” above.

Treatment of Trust Unit Lending and Short Sales

The special rules of the Code that apply to securities lending transactions do not, by their terms, apply to interests in a partnership. Accordingly, a United States holder whose Trust Units are loaned to a “short seller” to cover a short sale of Trust Units may be considered as having disposed of ownership of those Trust Units. If so, it would no longer be a partner with respect to those Trust Units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period, any of our income, gain, deduction or loss with respect to those Trust Units would not be reportable by the United States holder and any cash distributions received by the United States holder with respect to those Trust Units would be fully taxable as ordinary income. United States holders desiring to assure their status as owners of Trust Units and avoid the risk of gain recognition resulting from the application of these rules should modify any applicable brokerage account agreements to prohibit their brokers from borrowing or loaning their Trust Units.

The Code also contains provisions affecting the taxation of certain financial products and securities, including interests in entities such as us, by treating a taxpayer as having sold an “appreciated” interest, one in which gain would be recognized if it were sold, assigned or otherwise terminated at its fair market value, if the taxpayer or related persons enter into an offsetting notional principal contract, or a futures or forward contract with respect to the interest on substantially identical property. Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the interest, the taxpayer will be treated as having sold that portion if the taxpayer or a related person then acquires the interest or substantially identical property. The Secretary of Treasury is authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Disposition of Trust Units by Redemption

The tax consequences of a redemption of Trust Units are complex and depend in part upon whether some or all of a United States holder’s Trust Units are redeemed. The tax consequences of a redemption of all of a United States holder’s Trust Units should generally be the same as discussed above under “Certain Income Tax Considerations – United States Federal Income Tax Considerations – Disposition of Trust Units – Recognition of Gain or Loss” above. United States holders contemplating a redemption of some or all of their Trust Units should consult their tax advisors.

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Uniformity of Trust Units

Because we cannot match transferors and transferees of Trust Units, we must maintain uniformity of the economic and tax characteristics of the Trust Units to a purchaser of these Trust Units. In the absence of such uniformity, we may be unable to comply completely with a number of federal income tax requirements.

A lack of uniformity, however, can result from a literal application of Treasury regulations concerning the maintenance of capital accounts, including with respect to certain equity based compensation plans and distribution reinvestment programs maintained by us. If any non-uniformity were required by the IRS, it could have a negative impact on the ability of United States holders to claim that any portion of the distributions they receive from us represents a return of tax basis rather than taxable income and or the value of the Trust Units.

Tax-Exempt Organizations

Employee benefit plans (including individual retirement accounts (“IRAs”) and other retirement plans) and most other organizations exempt from federal income tax (each, a “TEO”) are subject to federal income tax on unrelated business taxable income (“UBTI”). Because we expect substantially all income of the Trust to be royalty income, rents from real property or interest, none of which is UBTI, a TEO should not be taxable on any income generated by ownership of the Trust Units except as described in the next paragraphs.

The Royalty Indenture is in several respects unusual, and there is no clear United States income tax guidance regarding its treatment. It is possible that the IRS could contend that some or all of our income under the Royalty Indenture does not qualify as royalty income, but should instead be treated as income from a working interest and therefore UBTI. In addition, the classification of certain facilities owned by us as real property or personal property is a determination subject to uncertainty. If such facilities were determined to be personal property for United States federal income tax purposes, the rent derived therefrom would be UBTI to a TEO. Prospective purchasers of Trust Units that are TEOs are encouraged to consult their tax advisors regarding the foregoing.

Finally, if the Trust finances with indebtedness an acquisition of any property to be held to produce income, income derived from such property in whole or in part will be UBTI to a TEO. Furthermore, if a TEO acquires Trust Units with indebtedness, then a portion of any interest, rents from real property and royalty income received by the TEO attributable to the Trust Units will be treated as UBTI and thus will be taxable to a TEO.

Administrative Matters

Trust Information Returns

We are currently not required to file a United States federal income tax return, since we have no gross income derived from sources within the United States or gross income which is effectively connected with the conduct of a trade or business within the United States. However, the IRS may require a United States holder to provide statements or other information necessary for the IRS to verify the accuracy of the reporting by the United States holder on its income tax return of any items of our income, gain, loss, deduction, or credit. If we were to file a United States tax return in future tax years, the filing would change the manner in which we provide tax information to the United States holders and special procedures would also apply to an audit of such tax return by the IRS.

Registration as a Tax Shelter

The Code requires that “tax shelters” be registered with the Secretary of the Treasury. The temporary Treasury Regulations interpreting the tax shelter registration provisions of the Code are extremely broad. It is arguable that the Trust is not subject to the registration requirement on the basis that it will not constitute a tax shelter. However, we have registered as a tax shelter with the Secretary of the Treasury because of the absence of assurance that we will not be subject to tax shelter registration and in light of the substantial penalties which

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otherwise might be imposed if we failed to register and it were subsequently determined that registration was required. The IRS has issued the Trust the following tax shelter registration number: 99068000003.

ISSUANCE OF A REGISTRATION NUMBER DOES NOT INDICATE THAT AN INVESTMENT IN THE TRUST OR THE CLAIMED TAX BENEFITS HAVE BEEN REVIEWED, EXAMINED OR APPROVED BY THE IRS.

A United States holder who sells or otherwise transfers Trust Units must furnish the tax shelter registration number to the transferee. The penalty for failure of the transferor of a Trust Unit to furnish the registration number to the transferee is $100 for each such failure.

Reportable Transactions

Under Treasury regulations, certain taxpayers participating directly or indirectly in a “reportable transaction” must disclose such participation to the IRS. The scope and application of these rules is not completely clear. An investment in us may be considered participation in a “reportable transaction” if, for example, we recognize certain significant losses in the future and we do not otherwise meet certain applicable exemptions. If an investment in us constitutes participation in a “reportable transaction,” we and each United States holder may be required to file IRS Form 8886 with the IRS, attaching it to their United States federal income tax returns, thereby disclosing certain information relating to us to the IRS. In addition, we may be required to disclose our reportable transactions and to maintain a list of Unitholders and to furnish this list and certain other information to the IRS upon its written request. United States holders are urged to consult their own tax advisors regarding the applicability of these rules to their investment in us.

Foreign Partnership Reporting

A United States holder who contributes more than U.S.$100,000 to us (when added to the value of any other property contributed to us by such person or a related person during the previous 12 months) in exchange for Trust Units, may be required to file Form 8865, Return of United States Persons With Respect to Certain Foreign Partnerships, in the year of the contribution. There may be other circumstances in which a United States holder is required to file Form 8865.

INDUSTRY CONDITIONS

Government Regulation

The oil and natural gas industry is subject to extensive controls and regulation imposed by various levels of government. Although we do not expect that these controls and regulation will affect the operations of Pengrowth in a manner materially different than they would affect other oil and gas companies of similar size, the controls and regulations should be considered carefully by investors in the oil and gas industry. All current legislation is a matter of public record and Pengrowth is unable to predict what additional legislation or amendments may be enacted.

Pricing and Marketing – Oil

In Canada, producers of oil negotiate sales contracts directly with oil purchasers, with the result that the market determines the price of oil. Such price depends, in part, on oil type and quality, prices of competing fuels, distance to market, the value of refined products, the supply/demand balance, other contractual terms and the world price of oil. Oil exports may be made pursuant to export contracts with terms not exceeding one year, in the case of light crude, and not exceeding two years, in the case of heavy crude, provided that an order approving any such export has been obtained from the National Energy Board. Any oil export to be made pursuant to a contract of longer duration (to a maximum of 25 years) requires an exporter to obtain an export licence from the National Energy Board and the issuance of such licence requires approval of the Governor in Council.

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Pricing and Marketing – Natural Gas

In Canada, the price of natural gas sold in intraprovincial, interprovincial and international trade is determined by negotiation between buyers and sellers. Such price depends, in part, on natural gas quality, prices of competing fuels, distance to market, access to downstream transportation, length of contract term, weather conditions, the supply/demand balance and other contractual terms. Natural gas exported from Canada is subject to regulation by the National Energy Board and the Government of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts must continue to meet certain criteria prescribed by the National Energy Board and the Government of Canada. Natural gas exports for a term of less than two years or for a term of two to 20 years (in quantities of not more than 30,000 m³/day), must be made pursuant to an order of the National Energy Board. Any natural gas export to be made pursuant to a contract of longer duration (to a maximum of 25 years) or a larger quantity requires an exporter to obtain an export licence from the National Energy Board and the issue of such a licence requires the approval of the Governor in Council.

The Governments of Alberta, British Columbia and Saskatchewan also regulate the volume of natural gas which may be removed from those provinces for consumption elsewhere, based on such factors as reserve availability, transportation arrangements and market considerations.

Pricing and Marketing – Natural Gas Liquids

In Canada, the price of NGLs sold in intraprovincial, interprovincial and international trade is determined by negotiation between buyers and sellers. Such price depends, in part, on the quality of the NGLs, prices of competing chemical stock, distance to market, access to downstream transportation, length of contract term, the supply/demand balance and other contractual terms. NGLs exported from Canada are subject to regulation by the National Energy Board and the Government of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts must continue to meet certain criteria prescribed by the National Energy Board and the Government of Canada. NGLs may be exported for a term of no more than one year in respect to propane and butane, and no more than two years in respect to ethane, all exports requiring an order of the National Energy Board.

For crude oil, natural gas and related production from federal or provincial government lands, the royalty regime is a significant factor in the profitability of production operations. Royalties payable on production from lands other than government lands are determined by negotiations between the mineral owner and the lessee, although production from such lands is subject to certain provincial taxes and royalties. Government royalties are determined by governmental regulation and are generally calculated as a percentage of the value of the gross production. The rate of royalties payable generally depends in part on well productivity, geographical location and field discovery date.

From time to time, the provincial governments have established incentive programs for exploration and development. Such programs often provide for royalty reductions, credits and holidays, and are generally introduced when commodity prices are low. The programs are designed to encourage exploration and development activity by improving earnings and cash flow within the industry. The trend in recent years has been for provincial governments to reduce the benefits under such programs and to allow them to expire without renewal, and consequently few such programs are currently operative.

Alberta

Royalty rates in Alberta are proposed to be changed. See “General Development of Pengrowth Energy Trust – Recent Developments – Changes to Royalty Legislation Affecting Pengrowth and its Unitholders”.

Effective January 1, 2007, the Government of Alberta eliminated the ARTC Program by which certain producers of oil or natural gas had been entitled to a credit against the royalties payable to the Government of Alberta. Approximately 78% of Pengrowth’s Company Interest production forecast for 2008 is in the Province of Alberta.

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British Columbia

Royalty rates on oil produced from lands owned by the Government of British Columbia vary from 0 percent to 40 percent for oil produced from pools discovered prior to November 1, 1975, from 0 percent to 30 percent for oil produced from pools discovered between November 1, 1975 and June 1, 1998, and from 0 percent to 24 percent for oil produced from pools discovered after June 1, 1998 (“Third Tier Wells”), depending on the well’s production rates, the market price of oil and other factors. Oil produced from Third Tier Wells are exempt from government royalties for the first 36 months of production.

The royalty reserved to the Government of British Columbia in respect of natural gas production, subject to incentives for deep wells and marginal wells, vary between 15 percent and 25 percent in the case of gas produced from wells drilled prior to June 1, 1998, between 9 percent and 27 percent for wells drilled between June 1, 1998 and December 31, 2001 that are completed within 5 years of the date production rights are issued, and between 12 percent and 27 percent for all other wells, depending on the well’s production rates, the market price of gas and other factors. Approximately 5 percent of Pengrowth’s Company Interest production forecast for 2008 is in the Province of British Columbia.

Saskatchewan

Royalty rates on oil produced from lands owned by the Government of Saskatchewan, subject to various incentives, vary from 20 percent to 45 percent for oil produced from pools discovered prior to January 1, 1974, from 10 percent to 35 percent for oil produced from pools discovered between January 1, 1974 and August 31, 2002, and from 5 percent to 30 percent for oil produced from pools discovered after August 31, 2002, depending on the depth of the well, production rates, the market price of oil and other factors.

Royalty rates on natural gas produced from lands owned by the Government of Saskatchewan, subject to various incentives, vary from 20 to 45 percent for gas produced from pools discovered prior to October 1, 1976, from 15 to 30 percent for gas produced from pools discovered between October 1, 1976 and August 31, 2002, and from 5 to 30 percent for gas produced from pools discovered after August 31, 2002, depending on the depth of the well, production rates, the market price of gas and other factors. Approximately 8 percent of Pengrowth’s Company Interest production forecast for 2008 is in the Province of Saskatchewan.

Nova Scotia

The Government of Nova Scotia has established a generic royalty regime in respect of oil and gas produced from offshore Nova Scotia. Such regime contemplates a multi-tier royalty in which the royalty rate fluctuates when certain threshold levels of rates of return on capital have been reached. Notwithstanding the generic royalty regime, royalties in respect of offshore Nova Scotia oil and gas production may be determined contractually between the participant and the Government of Nova Scotia. Approximately 9 percent of Pengrowth’s Company Interest production forecast for 2008 is in the Province of Nova Scotia.

Environmental Regulation

The oil and natural gas industry is currently subject to environmental regulation pursuant to provincial and federal legislation. Environmental legislation provides for restrictions and prohibitions on releases or emissions of various substances produced or utilized in association with certain oil and gas industry operations. In addition, legislation requires that well and facility sites are abandoned and reclaimed to the satisfaction of provincial authorities. Compliance with such legislation can require significant expenditures. A breach of such legislation may result in the imposition of material fines and penalties, the revocation of necessary licenses and authorizations or civil liability for pollution damage.

Pengrowth’s facilities and other operations emit greenhouse gases, making it possible that Pengrowth will be subject to Federal and Provincial legislation. Canada is a signatory to the United Nations Framework Convention on Climate Change and has ratified the Kyoto Protocol established thereunder to set legally binding targets to

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reduce nation-wide emissions of carbon dioxide, methane, nitrous oxide and other GHGs. In April 2007, the Federal Government proposed a new climate change plan that calls for GHG emissions to be reduced by 20 percent below current levels by 2020. This bill has not been passed yet. Facilities have a number of strategies to achieve these targets, including emission tradings, in-house reductions, or invest in a technology fund to research and develop GHG reduction technologies.

In Alberta, new climate change regulations became effective July 1, 2007. These regulations require Alberta facilities that emit more than 100k tonnes of greenhouse gases a year to reduce emissions intensity by 12 percent over the average emission levels of 2003, 2004 and 2005. Companies can make their reductions through improvements to their operations; by purchasing Alberta-based credits or by contributing to the Climate Change and Emissions Management Fund. Pengrowth currently operates two facilities that fall within this new requirement.

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RISK FACTORS

If any of the following risks occur, our production, revenues and financial condition could be materially harmed, with a resulting decrease in distributions on, and the market price of, our Trust Units. As a result, the trading price of our Trust Units could decline, and you could lose all or part of your investment.Additional risks are described under the heading “Business Risks” in the Management’s Discussion Analysis for the year ended December 31, 2007.

The SIFT Legislation is expected to materially and adversely affect the Trust, the Unitholders and the value of the Trust Units.

It is expected that the SIFT Legislation will subject the Trust to trust level taxation beginning on January 1, 2011, which will materially reduce the amount of cash available for distributions to the Unitholders. Based on the proposed Canadian federal income tax rates and tax rate on account of provincial taxes, the Trust estimates that the SIFT Legislation will, commencing on January 1, 2011, reduce the amount of cash available to the Trust to distribute to its Unitholders. Under the current SIFT Legislation, the proposed tax will be 29.5 percent in 2011 and 28 percent in 2012, based upon a 13 percent provincial tax rate and a federal tax rate of 16.5 percent reducing to 15 percent in 2012. On February 26, 2008, the Minister released the Budget. The Budget proposes to replace this 13% provincial tax rate with the applicable provincial income tax rates for each province in which the SIFT has a permanent establishment, based on a provincial allocation formula. To simplify the application of the SIFT Legislation, we have assumed a provincial tax rate of 10%, being the applicable rate in Alberta where we anticipate 78 percent of our revenue will be generated in 2008. In accordance with this assumption and subject to the availability of tax pools, the application of the SIFT Legislation will reduce the amount of cash available to the Trust to distribute to its Unitholders by an amount equal to 26.5 percent in 2011 (and by 25 percent in 2012 and thereafter) multiplied by the amount of the pre-tax income distributed by the Trust. There can be no assurance that the Budget will become law and, until it does, the proposed reduction to the provincial tax rate will not become effective. A reduction in the value of the Trust Units would be expected to increase the cost to the Trust of raising capital in the public capital markets. In addition, the SIFT Legislation is expected to substantially eliminate the competitive advantage the Trust currently enjoys compared to corporate competitors in raising capital in a tax efficient manner, while placing the Trust at a competitive disadvantage compared to industry competitors, including U.S. master limited partnerships, which are expected to continue not to be subject to entity-level taxation. The SIFT Legislation is also expected to make the Trust Units less attractive as an acquisition currency. As a result, it may be more difficult for the Trust to compete effectively for acquisition opportunities in the future. There can be no assurance that the Trust will be able to reorganize its legal and tax structure to reduce the expected impact of the SIFT Legislation.

In addition, there can be no assurance that the Trust will be able to maintain its status as a grandfathered SIFT under the SIFT Legislation until 2011. If the Trust exceeds the limits on the issuance of new Trust Units and convertible debt that constitutes normal growth during the transitional period from October 31, 2006 to December 31, 2010, the SIFT Legislation would become effective on a date earlier than January 1, 2011.

Volatility in oil and natural gas prices could have a material adverse effect on results of operations and financial condition, which, in turn, could negatively affect the amount of distributions to our Unitholders.

The monthly distributions we pay to our Unitholders depend, in part, on the prices we receive for our oil and natural gas production. Oil and natural gas prices can fluctuate widely on a month-to-month basis in response to a variety of factors that are beyond our control. These factors include, among others:

• global energy policy, including the ability of OPEC to set and maintain production levels for oil;

• political conditions in the Middle East;

• worldwide economic conditions;

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• weather conditions including weather-related disruptions to the North American natural gas supply;

• the supply and price of foreign oil and natural gas;

• the level of consumer demand;

• the price and availability of alternative fuels;

• the proximity to, and capacity of, transportation facilities;

• the effect of worldwide energy conservation measures; and

• government regulation.

Declines in oil or natural gas prices could have an adverse effect on our operations, financial condition and proved reserves and ultimately on our ability to pay distributions to our Unitholders.

Distributions may be reduced during periods in which the Corporation makes capital expenditures using cash flow, which could also negatively affect the market price of the Trust Units.

Production and development costs incurred with respect to properties, including power costs and the costs of injection fluids associated with tertiary recovery operations, reduce the royalty income that the Trust receives and, consequently, the amounts we can distribute to our Unitholders.

The timing and amount of capital expenditures will directly affect the amount of income available for distribution to our Unitholders. Distributions may be reduced, or even eliminated, at times when significant capital or other expenditures are made. To the extent that external sources of capital, including the issuance of additional Trust Units, become limited or unavailable, the Corporation’s ability to make the necessary capital investments to maintain or expand oil and gas reserves and to invest in assets, as the case may be, will be impaired. To the extent that the Corporation is required to use cash flow to finance capital expenditures or property acquisitions, the cash we receive from the Corporation on the Royalty Units will be reduced, resulting in reductions to the amount of cash we are able to distribute to our Unitholders.

Actual reserves will vary from reserve estimates, and those variations could be material, and negatively affect the market price of the Trust Units and distributions to our Unitholders.

The value of the Trust Units will depend upon, among other things, the Corporation’s reserves. In making strategic decisions, we generally rely upon reports prepared by our independent reserve engineers. Estimating reserves is inherently uncertain. Ultimately, actual production, revenues and expenditures for the underlying properties will vary from estimates and those variations could be material. Changes in the prices of, and markets for, oil and natural gas from those anticipated at the time of making such assessments will affect the return on, and value of, our Trust Units. The reserve and cash flow information contained in the documents incorporated by reference represent estimates only. Petroleum engineers consider many factors and make assumptions in estimating reserves. Those factors and assumptions include:

• historical production from the area compared with production rates from similar producing areas;

• the assumed effect of government regulation;

• assumptions about future commodity prices, exchange rates, production and development costs, capital expenditures, abandonment costs, environmental liabilities, and applicable royalty regimes;

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• initial production rates;

• production decline rates;

• ultimate recovery of reserves;

• marketability of production; and

• other government levies that may be imposed over the producing life of reserves.

If any of these factors and assumptions prove to be inaccurate, our actual results may vary materially from our reserve estimates. Many of these factors are subject to change and are beyond our control. In particular, changes in the prices of, and markets for, oil and natural gas from those anticipated at the time of making such assessments will affect the return on, and value of, our Trust Units. In addition, all such assessments involve a measure of geological and engineering uncertainty that could result in lower production and reserves than anticipated. A significant portion of our reserves are classified as “undeveloped” and are subject to greater uncertainty than reserves classified as “developed”.

In accordance with normal industry practices, we engage independent petroleum engineers to conduct a detailed engineering evaluation of our oil and gas properties for the purpose of estimating our reserves as part of our year-end reporting process. As a result of that evaluation, we may increase or decrease the estimates of our reserves. We do not consider an increase or decrease in the estimates of our reserves in the range of up to 5 percent to be material or inconsistent with normal industry practice. Any significant reduction to the estimates of our reserves resulting from any such evaluation could have a material adverse effect on the value of our Trust Units.

Continued uncertainty in the credit markets may restrict the availability or increase the cost of borrowing required for future development and acquisitions.

Continued uncertainty in domestic and international credit markets could materially affect our ability to access sufficient capital for our capital expenditures and acquisitions and, as a result, may have a material adverse effect on our ability to execute our business strategy and on our financial condition. There can be no assurance that financing will be available or sufficient to meet these requirements or for other corporate purposes or, if financing is available, that it will be on terms appropriate and acceptable to us.

If the Corporation is unable to acquire additional reserves, the value of the Trust Units and distributions to our Unitholders may decline.

Our future oil and natural gas reserves and production, and therefore the cash flows of the Trust, will depend upon our success in acquiring additional reserves. If we fail to add reserves by acquiring or developing them our reserves and production will decline over time as they are produced. When reserves from our properties can no longer be economically produced and marketed, our Trust Units will have no value unless additional reserves have been acquired or developed. If we are not able to raise capital on favourable terms, we may not be able to add to or maintain our reserves. If we use our cash flow to acquire or develop reserves, we will reduce our cash available to be distributed. There is strong competition in all aspects of the oil and gas industry, including reserve acquisitions. We will actively compete for reserve acquisitions and skilled industry personnel with other oil and gas companies and energy trusts. However, many of our competitors have greater resources than we do and we cannot assure you that we will be successful in acquiring additional reserves on terms that meet our objectives.

Our operation of oil and natural gas wells could subject us to environmental claims and liability which would be funded out of our cash flow and could therefore reduce cash flow otherwise payable to our Unitholders.

The oil and natural gas industry is subject to extensive environmental regulation, which imposes restrictions and prohibitions on releases or emissions of various substances produced in association with certain oil and gas

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industry operations. In addition, Canadian legislation requires that well and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities. A breach of this or other legislation may result in fines or the issuance of a clean-up order. Ongoing environmental obligations will be funded out of our cash flow and could therefore reduce the cash available to be distributed to our Unitholders.

We may be unable to successfully compete with other companies in our industry, which could negatively affect the market price of the Trust Units and distributions to our Unitholders.

There is strong competition in all aspects of the oil and gas industry. Pengrowth will actively compete for capital, skilled personnel, undeveloped lands, reserve acquisitions, access to drilling rigs, service rigs and other equipment, access to processing facilities and pipeline and refining capacity and in all other aspects of its operations with a substantial number of other organizations, many of which may have greater technical and financial resources than Pengrowth. Some of those organizations not only explore for, develop and produce oil and natural gas but also carry on refining operations and market oil and other products on a world-wide basis and, as such, have greater and more diverse resources on which to draw.

Incorrect assessments of value at the time of acquisitions could adversely affect the value of our Trust Units and distributions to our Unitholders.

Acquisitions of oil and gas properties or companies will be based in large part on engineering and economic assessments made by independent engineers. These assessments include a series of assumptions regarding such factors as recoverability and marketability of oil and gas, future prices of oil and gas and operating costs, future capital expenditures and royalties and other government levies which will be imposed over the producing life of the reserves. Many of these factors are subject to change and are beyond our control. All such assessments involve a measure of geologic and engineering uncertainty which could result in lower production and reserves than anticipated.

Our indebtedness may limit the amount of distributions that we are able to pay our Unitholders, and if we default on our debts, the net proceeds of any foreclosure sale would be allocated to the repayment of our lenders, note holders and other creditors and only the remainder, if any, would be available for distribution to our Unitholders.

We are indebted under the Credit Facility, the Debentures, the 2003 U.S. Senior Notes, the 2007 U.S. Senior Notes and the U.K. Senior Notes. Certain covenants in the agreements with our lenders may limit the amount of distributions paid to Unitholders. See “Distributions — Restrictions on Distributions”. Variations in interest rates, exchange rates and scheduled principal repayments could result in significant changes in the amount we are required to apply to the service of our outstanding indebtedness. If we become unable to pay our debt service charges or otherwise cause an event of default to occur, our lenders may foreclose on, or sell, our properties. The net proceeds of any such sale will be allocated firstly to the repayment of our lenders and other creditors and only the remainder, if any, would be payable to the Trust by the Corporation. In addition, we may not be able to refinance some or all of these debt obligations through the issuance of new debt obligations on the same terms, and we may be required to refinance through the issuance of new debt obligations on less favorable terms or through the issuance of additional securities or through other means. In any such event, the amount of cash available for distribution may be diluted or adversely impacted and such dilution or impact may be significant.

We are dependent on our management and the loss of our key management and other personnel could negatively impact our business.

Our Unitholders are entirely dependent on the management of the Manager and the Corporation with respect to the acquisition of oil and gas properties and assets, the development and acquisition of additional reserves, the management and administration of all matters relating to properties and the administration of the Trust. The loss of the services of key individuals who currently comprise the management team of the Manager and the Corporation could have a detrimental effect on the Trust. In addition, increased activity within the oil and gas

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sector can increase the cost of goods and services and make it more difficult to attract and retain qualified professional staff.

A decline in the Corporation’s ability to market its oil and natural gas production could have a material adverse effect on production levels or on the price received for production, which, in turn, could reduce distributions to our Unitholders and affect the market price of the Trust Units.

The marketability of our production depends in part upon the availability, proximity and capacity of gas gathering systems, pipelines and processing facilities. United States federal and state and Canadian federal and provincial regulation of oil and gas production and transportation, general economic conditions, and changes in supply and demand could adversely affect our ability to produce and market oil and natural gas. If market factors dramatically change, the financial impact on us could be substantial. The availability of markets is beyond our control.

The operation of a significant portion of our properties is largely dependent on the ability of third party operators, and harm to their business could cause delays and additional expenses in our receiving revenues, which could negatively affect the market price of the Trust Units and distributions to our Unitholders.

The continuing production from a property, and to some extent the marketing of production, is dependent upon the ability of the operators of our properties. Approximately 45 percent of our properties are operated by third parties, based on daily production. If, in situations where we are not the operator, the operator fails to perform these functions properly or becomes insolvent, revenues may be reduced. Revenues from production generally flow through the operator and, where we are not the operator, there is a risk of delay and additional expense in receiving such revenues.

The operations of the wells located on properties not operated by us are generally governed by operating agreements which typically require the operator to conduct operations in a good and workman-like manner. Operating agreements generally provide, however, that the operator will have no liability to the other non-operating working interest owners for losses sustained or liabilities incurred, except such as may result from gross negligence or willful misconduct. In addition, third-party operators are generally not fiduciaries with respect to the Corporation, the Trust or the Unitholders. The Corporation, as owner of working interests in properties not operated by it, will generally have a cause of action for damages arising from a breach of the operator’s duty. Although not established by definitive legal precedent, it is unlikely that the Trust or our Unitholders would be entitled to bring suit against third-party operators to enforce the terms of the operating agreements. Therefore, our Unitholders will be dependent upon the Corporation, as owner of the working interest, to enforce such rights.

Our distributions could be adversely affected by unforeseen title defects, which could reduce distributions to our Unitholders.

Although title reviews are conducted prior to any purchase of resource assets, such reviews cannot guarantee that an unforeseen defect in the chain of title will not arise to defeat our title to certain assets. Such defects could reduce the amounts distributable to our Unitholders, and could result in a reduction of capital.

Fluctuations in foreign currency exchange rates could adversely affect our business, and adversely affect the market price of the Trust Units as well as distributions to our Unitholders.

World oil prices are quoted in United States dollars and the price received by Canadian producers is therefore affected by the Canadian/United States dollar exchange rate which fluctuates over time. A material increase in the value of the Canadian dollar may negatively impact our net production revenue and cash flow. In 2007, the Canadian dollar generally has increased significantly in value relative to the United States dollar from historical levels, and no assurance can be given that such trend will not continue. To the extent that we have engaged, or in the future engage, in risk management activities related to commodity prices and foreign exchange rates, through entry into oil or natural gas price commodity contracts and foreign exchange contracts or otherwise, we may be subject to unfavourable price changes and credit risks associated with the counterparties with which we contract.

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A decline in the value of the Canadian dollar relative to the United States dollar provides a competitive advantage to United States companies in acquiring Canadian oil and gas properties and may make it more difficult for us to replace reserves through acquisitions.

Being a limited purpose trust makes the Trust largely dependent upon the operations and assets of the Corporation. If the oil and natural gas reserves associated with the Corporation’s resource properties are not supplemented through additional development or the acquisition of oil and natural gas properties, the ability of the Corporation to continue to generate cash flow for distribution to Unitholders may be adversely affected.

The Trust is a limited purpose trust which is dependent upon the operations and assets of the Corporation. The Corporation’s income will be received from the production of crude oil and natural gas from its properties and will be susceptible to the risks and uncertainties associated with the oil and natural gas industry generally. Since the primary focus is to pursue growth opportunities through the development of existing reserves and the acquisition of new properties, the Corporation’s involvement in the exploration for oil and natural gas is minimal. As a result, if the oil and natural gas reserves associated with the Corporation’s resource properties are not supplemented through additional development or the acquisition of oil and natural gas properties, the ability of the Corporation to continue to generate cash flow for distribution to Unitholders may be adversely affected.

Management may have conflicts of interest that may create incentives for the Manager to act contrary to or in competition with the interests of our Unitholders.

The Manager provides the advisory, management and administrative needs of the Trust and the Corporation in consideration for a management fee which is currently based in part on the earnings of the Corporation. This arrangement may create an incentive for the Manager to maximize the earnings of the Corporation, rather than maximize its cash flow from operations, which is the primary basis for calculating distributions available to Unitholders.

The Manager may manage and administer such additional acquired properties, as well as enter into other types of energy related management and advisory activities and may not devote full time and attention to the business of the Corporation and therefore act contrary to or in competition with the interests of our Unitholders.

General and administrative expenses which the Manager incurs in relation to the business of the Corporation and the Trust are required to be paid by the Corporation. These expenses are not subject to a limit other than as may be provided under a periodic review by the Board of Directors and, as a result, there may not be an incentive for the Manager to minimize these expenses.

We may incur material costs as a result of compliance with health, safety and environmental laws and regulations which could negatively affect our financial condition and, therefore, reduce distributions to our Unitholders and decrease the market price of the Trust Units.

Compliance with environmental laws and regulations could materially increase our costs. We may incur substantial capital and operating costs to comply with increasingly complex laws and regulations covering the protection of the environment and human health and safety. In particular, we may be required to incur significant costs to comply with the 1997 Kyoto Protocol to the United Nations Framework Convention on Climate Change, known as the Kyoto Protocol, which is intended to reduce emissions of pollutants into the air.

Lower oil and gas prices increase the risk of write-downs of our oil and gas property investments which could be viewed unfavourably in the market or could limit our ability to borrow funds or comply with covenants contained in our current or future credit agreements or other debt instruments.

Under Canadian accounting rules, the net capitalized cost of oil and gas properties may not exceed a “ceiling limit” which is based, in part, upon estimated future net cash flows from reserves. If the net capitalized costs exceed this limit, we must charge the amount of the excess against earnings. As oil and gas prices decline, our net

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capitalized cost may approach and, in certain circumstances, exceed this cost ceiling, resulting in a charge against earnings. Under United States accounting rules, the cost ceiling is generally lower than under Canadian rules because the future net cash flows used in the United States ceiling test are based on proven reserves only. Accordingly, we would have more risk of a ceiling test write-down in a declining price environment if we reported under United States generally accepted accounting principles. While these write-downs would not affect cash flow, the charge to earnings could be viewed unfavourably in the market or could limit our ability to borrow funds or comply with covenants contained in our current or future credit agreements or other debt instruments.

Changes in Canadian legislation could adversely affect the value of our Trust Units.

The value of the Trust Units is largely related to our income tax treatment. We cannot assure you that income tax laws and government incentive programs relating to the oil and natural gas industry generally and the status of royalty trusts having our structure will not change in a manner that adversely affects your investment.

If the Trust ceases to qualify as a mutual fund trust it would adversely affect the value of our Trust Units.

It is intended that the Trust will at all times qualify as a mutual fund trust for the purposes of the Tax Act.

Notwithstanding the steps taken or to be taken by Pengrowth, no assurance can be given that the status of the Trust as a mutual fund trust will not be challenged by a relevant taxation authority. If the Trust’s status as a mutual fund trust is determined to have been lost, certain negative tax consequences will have resulted for the Trust and its Unitholders. These negative tax consequences include the following:

• The Trust Units would cease to be a qualified investment for trusts governed by RRSPs, RRIFs, RESPs and DPSPs, as defined in the Tax Act. Where, at the end of a month, a RRSP, RRIF, RESP or DPSP holds Trust Units that ceased to be a qualified investment, the RRSP, RRIF, RESP or DPSP, as the case may be, must, in respect of that month, pay a tax under Part XI.1 of the Tax Act equal to 1 percent of the fair market value of the Trust Units at the time such Trust Units were acquired by the RRSP, RRIF, RESP or DPSP. In addition, trusts governed by a RRSP or a RRIF which hold Trust Units that are not qualified investments will be subject to tax on the income attributable to the Trust Units while they are non-qualified investments, including the full capital gains, if any, realized on the disposition of such Trust Units. Where a trust governed by a RRSP or a RRIF acquires Trust Units that are not qualified investments, the value of the investment will be included in the income of the annuitant for the year of the acquisition. Trusts governed by RESPs which hold Trust Units that are not qualified investments can have their registration revoked by the Canada Revenue Agency.

• The Trust would be required to pay a tax under Part XII.2 of the Tax Act. The payment of Part XII.2 tax by the Trust may have adverse income tax consequences for certain Unitholders, including non-resident persons and residents of Canada who are exempt from Part I tax.

• The Trust would not be entitled to use the capital gains refund mechanism otherwise available for mutual fund trusts.

• The Trust Units would constitute “taxable Canadian property” for the purposes of the Tax Act, potentially subjecting non-residents of Canada to tax pursuant to the Tax Act on the disposition (or deemed disposition) of such Trust Units.

The ability of investors resident in the United States to enforce civil remedies may be negatively affected for a number of reasons.

The Trust is an Alberta trust and the Manager and the Corporation are both Alberta corporations. All of these entities have their principal places of business in Canada. All of the directors and officers of the Manager and the majority of the directors and officers of the Corporation are residents of Canada and all or a substantial portion of

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the assets of such persons and of the Trust are located outside of the United States. Consequently, it may be difficult for United States investors to effect service of process within the United States upon the Trust or such persons or to realize in the United States upon judgments of courts of the United States predicated upon civil remedies under the United StatesSecurities Act of 1933, as amended. Investors should not assume that Canadian courts:

• will enforce judgments of United States courts obtained in actions against the Trust or such persons predicated upon the civil liability provisions of the United States federal securities laws or the securities or “blue sky” laws of any state within the United States; or

• will enforce, in original actions, liabilities against the Trust or such persons predicated upon the United States federal securities laws or any such state securities or blue sky laws.

Your rights as a Unitholder differ from the rights associated with other types of investments and we cannot assure you that the distributions you receive over the life of your investment will meet or exceed your initial capital investment.

Trust Units should not be viewed by investors as shares in the Corporation. Trust Units are also dissimilar to conventional debt instruments in that there is no principal amount owing to our Unitholders. Trust Units represent a fractional interest in the Trust. Unitholders will not have the statutory rights normally associated with ownership of shares of a corporation including, for example, the right to bring “oppression” or “derivative” actions. The Trust’s assets are royalty units of, net profits interests in, and common shares of, the Corporation, Esprit Exploration Ltd. and other subsidiaries of the Trust, as well as certain facilities interests, and may also include certain other investments permitted under the Trust Indenture. The price per Trust Unit is a function of anticipated cash flow, the oil and natural gas properties acquired by the Corporation and the ability to effect long-term growth in the value of the Corporation. The market price of the Trust Units is sensitive to a variety of market conditions including, but not limited to, interest rates and the ability of the Corporation to acquire suitable oil and natural gas properties. Changes in market conditions may adversely affect the trading price of our Trust Units.

Trust Units will have no value when reserves from the properties can no longer be economically produced or marketed and, as a result, cash distributions do not represent a “yield” in the traditional sense as they represent both return of capital and return on investment. Unitholders will have to obtain the return of capital invested out of cash flow derived from their investments in the Trust Units during the period when reserves can be economically recovered. Accordingly, we give no assurances that the distributions you receive over the life of your investment will meet or exceed your initial capital investment.

Future acquisitions may result in substantial future dilution of your Trust Units.

One of our objectives is to continually add to our reserves through acquisitions and through development. Our success is, in part, dependent on our ability to raise capital from time to time. Unitholders may also suffer dilution in connection with future issuance of Trust Units.

Canadian and United States practices differ in reporting reserves and production and our estimates may not be comparable to those of companies in the United States.

We report our production and reserve quantities in accordance with Canadian practices and specifically in accordance with NI 51-101. These practices are different from the practices used to report production and to estimate reserves in reports and other materials filed with the SEC by companies in the United States.

We incorporate additional information with respect to production and reserves which is either not generally included or prohibited under rules of the SEC and practices in the United States. We follow the Canadian practice of reporting gross production and reserve volumes; however, we also follow the United States practice of separately reporting these volumes on a net basis (after the deduction of royalties and similar payments). We also follow the Canadian practice of using forecast prices and costs when we estimate our reserves. However, we

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separately estimate our reserves using prices and costs held constant at the effective date of the reserve report in accordance with the Canadian reserve reporting requirements. These latter requirements are similar to the constant pricing reserve methodology utilized in the United States.

We include in the documents incorporated herein by reference estimates of proved and proved plus probable reserves. The SEC generally prohibits the inclusion of estimates of probable reserves in filings made with it by United States oil and gas companies. This prohibition does not apply to the Trust because it is a Canadian foreign private issuer.

You may be required to pay taxes even if you do not receive any cash distributions.

You may be required to pay federal income taxes and, in some cases, state, provincial and local income taxes on your share of our taxable income even if you do not receive any cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability that results from your share of our taxable income.

Unitholders who are United States persons face certain income tax risks.

The United States federal income tax risks related to owning and disposing of our Trust Units include the following:

• We have elected under applicable United States Treasury Regulations to be treated as a partnership for United States federal income tax purposes. Section 7704 of the Internal Revenue Code of 1986, as amended (the “Code”) provides that publicly-traded partnerships such as the Trust will, as a general rule, be taxed as corporations. We will not be treated as a corporation for U.S. federal income tax purposes only if 90 percent or more of its gross income consists of “qualifying income”. Although we expect to satisfy the 90 percent requirement at all times, if we fail to satisfy this requirement, we will be treated as a foreign corporation. Such conversion will be taxable unless a certain filing is made.

• If we were treated as a foreign corporation, we could be a passive foreign investment company or “PFIC”. If we were considered a PFIC, United States holders of Trust Units could be subject to substantially increased United States tax liability, including an interest charge upon the sale or other disposition of the United States holder’s Trust Units, or upon the receipt of “excess distributions” from the Trust. Certain elections may be available to a United States holder if we were classified as a PFIC to alleviate these adverse tax consequences.

• We treat the Royalty between the Trust and the Corporation as a royalty interest for all legal purposes, including United States federal income tax purposes. The Royalty Indenture in some respects differs from more conventional “net profits” interests as to which the courts and the IRS have ruled regarding the federal income tax treatment as a royalty, and as a result the propriety of such treatment is not free from doubt. It is possible that the IRS could contend, for example, that we should be considered to have a working interest in the properties of the Corporation. If the IRS were successful in making such a contention, the United States federal income tax consequences to United States holders could be different, perhaps materially worse, than indicated in the discussion herein, which generally assumes that the Royalty Indenture will be respected as a royalty.

• Gain or loss will be recognized on a sale of Trust Units equal to the difference between the amount realized and the United States holder’s tax basis for the Trust Units sold. Gain or loss recognized by a United States holder on the sale or exchange of Trust Units will generally be taxable as capital gain or loss, and will be long-term capital gain or loss if such United States holder’s holding period of the Trust Units exceeds one year. A portion of any amount realized on a sale or exchange of Trust Units (which portion could be substantial) will be separately

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	computed and taxed as ordinary income under Section 751 of the Code to the extent attributable to the recapture of depletion or depreciation deductions. Ordinary income attributable to depletion deductions and depreciation recapture could exceed net taxable gain realized upon the sale of the Trust Units and may be recognized even if there is a net taxable loss realized on the sale of the Trust Units. Thus, a United States holder may recognize both ordinary income and a capital loss upon a taxable disposition of Trust Units.
•	We have registered as a “tax shelter” with the United States Secretary of the Treasury because of the absence of assurance that we will not be subject to tax shelter registration and in light of the substantial penalties which otherwise might be imposed if we failed to register and it were subsequently determined that registration was required. Registration as a “tax shelter” may increase the risk of an IRS audit of us or a Unitholder. Any Unitholder owning less than a 1 percent profits interest in us has very limited rights to participate in the income tax audit process. Further, any adjustments in our tax returns will lead to adjustments in our Unitholders’ tax returns and may lead to audits of Unitholders’ tax returns and adjustments of items unrelated to us. You will bear the cost of any expense incurred in connection with an examination of your personal tax return.
•	Because we cannot match transferors and transferees of Trust Units, we must maintain uniformity of the economic and tax characteristics of the Trust Units to a purchaser of these Trust Units. In the absence of such uniformity, the Trust may be unable to comply completely with a number of federal income tax requirements. A lack of uniformity, however, can result from a literal application of some Treasury regulations. If any non-uniformity was required by the IRS, it could have a negative impact on the value of the Trust Units.
•	The Trust may not be an appropriate investment for certain types of entities. For example, there is a risk that some of the Trust’s income could be unrelated business taxable income with respect to tax-exempt organizations. Prospective purchasers of Trust Units that are tax-exempt organizations are encouraged to consult their tax advisors regarding investments in Trust Units.
•	The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our Trust Units may be modified by administrative, legislative or judicial interpretation at any time. For example, in response to certain recent developments, members of Congress are considering substantive changes to the existing U.S. tax laws that would affect certain publicly traded partnerships. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively. Although the currently proposed legislation would not appear to affect our tax treatment, we are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our Trust Units.
•	We prorate our items of income, gain, loss and deduction between transferors and transferees of our Trust Units each month based upon the ownership of our Trust Units on the first day of each month, instead of on the basis of the date a particular Trust Unit is transferred. The use of the proration method may not be permitted under existing Treasury Regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to challenge this method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our Unitholders.
•	On September 21, 2007, Canada and the United States signed the Protocol to the Canada-U.S. Convention. On December 14, 2007, Canada completed the steps required to give effect to the Protocol. The Protocol will come into force once it has been ratified by the United States, and the two countries have formally notified each other that their procedures are complete. The Protocol contains new Article IV(7)(b), a treaty benefit denial rule, which would increase the Canadian withholding tax on Pengrowth’s distributions (which for the purposes of this paragraph

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includes deemed dividends pursuant to the SIFT Legislation) to Non-Resident Unitholders who are residents of the U.S. for the purposes of the Canada-U.S. Convention. Article IV(7)(b) of the Protocol will not come into force until the first day of the third calendar year that ends after the Protocol is in force. Article IV(7)(b) of the Protocol generally denies benefits under the Canada-U.S. Convention in circumstances where (i) a Unitholder who is a resident of the U.S. for the purposes of the Canada-U.S. Convention receives an amount, such as a distribution, from an entity that is a resident of Canada, such as Pengrowth, (ii) Pengrowth is treated as a fiscally transparent entity for U.S. federal income tax purposes, which is the case inasmuch as Pengrowth is treated as a partnership for U.S. federal income tax purposes, and (iii) the tax treatment of the amount (or distribution) received by the U.S. Resident Unitholder would, for U.S. federal income tax purposes, be different if Pengrowth were not treated as fiscally transparent for U.S. federal income tax purposes. The effect of Article IV(7)(b) of the Protocol is that the Canadian withholding tax rate on distributions of income would be 25 percent instead of 15 percent or such lower rate otherwise available under the Canada-U.S. Convention. Returns of capital would still be subject to a 15 percent Canadian withholding tax and such rate is not modified by the Protocol. The Protocol also contains measures which, generally speaking, are designed to limit the benefits under the Canada-U.S. Convention to “treaty shopping” transactions or arrangements.

Distributions to our Unitholders may be reduced during periods in which Pengrowth makes capital expenditures using cash flow.

To the extent that Pengrowth uses cash flow to finance acquisitions, development costs and other significant capital expenditures, the cash available to the Trust for the payment of distributions will be reduced. To the extent that external sources of capital, including the issuance of additional Trust Units, becomes limited or unavailable, Pengrowth’s ability to make the necessary capital investments to maintain or expand its oil and gas reserves and to invest in assets, as the case may be, will be impaired.

Changes in government regulations that affect the crude oil and natural gas industry could adversely affect Pengrowth and reduce our distributions to our Unitholders.

The oil and gas industry in Canada is subject to federal, provincial and municipal legislation and regulation governing such matters as land tenure, prices, royalties, production rates, environmental protection controls, the exportation of crude oil, natural gas and other products, as well as other matters. The industry is also subject to regulation by governments in such matters as the awarding or acquisition of exploration and production rights, oil sands or other interests, the imposition of specific drilling obligations, environmental protection controls, control over the development and abandonment of fields and mine sites (including restrictions on production) and possibly expropriation or cancellation of contract rights.

Government regulations may change from time to time in response to economic or political conditions. The exercise of discretion by governmental authorities under existing regulations, the implementation of new regulations or the modification of existing regulations affecting the crude oil and natural gas industry could reduce demand for crude oil and natural gas or increase Pengrowth’s costs, either of which would have a material adverse impact on Pengrowth.

On October 25, 2007, the Government of Alberta unveiled a new royalty regime. The new regime will introduce new royalties for conventional oil, natural gas and bitumen effective January 1, 2009 that are linked to price and production levels and will apply to both new and existing oil sands projects and conventional oil and gas activities.

The Trust’s production, reserves and future net revenues associated therewith as disclosed herein do not reflect the increased royalties contemplated by the proposed new royalty regime and, after taking the new royalty regime into account, such values will be adversely affected. Based on the interpretations by GLJ of the proposed royalty changes and based on the January 2008 commodity price assumptions of GLJ, it is anticipated that the new royalty

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regime will result in a 12 to 18 percent increase in the total royalties paid to all parties by Pengrowth as compared to the current royalty structure. This increase is expected to result in a decline in the net present value, discounted at 10 percent, of the future net revenues associated with (i) Pengrowth’s Proved Reserves of three to five percent; and (ii) Pengrowth’s Total Proved Plus Probable Reserves of three to five percent.

Under the new royalty regime, it is anticipated that there will be a less than one-half of one percent decrease in Pengrowth’s Company Interest reserves and a one to three percent decrease in Pengrowth’s Net reserves, as compared to the current royalty structure. It is anticipated that the new royalty regime will result in a five to seven percent decline in Pengrowth’s cash flow for 2009, the first year in which the royalty changes take effect, as compared to the current royalty structure.

The implementation of the proposed changes to the royalty regime in Alberta is subject to certain risks and uncertainties. The significant changes to the royalty regime require new legislation, changes to existing legislation and regulation and development of proprietary software to support the calculation and collection of royalties. Additionally, certain proposed changes contemplate further public and/or industry consultation. There may be modifications introduced to the proposed royalty structure prior to the implementation thereof. See “General Development of Pengrowth Energy Trust – Recent Developments – Changes to Royalty Legislation Affecting Pengrowth and its Unitholders”.

If Pengrowth expands operations beyond oil and natural gas production in Canada, Pengrowth may face new challenges and risks. If Pengrowth is unsuccessful in managing these challenges and risks, its results of operations and financial condition could be adversely affected, which could affect the market price of the Trust Units and distributions to Unitholders.

Pengrowth’s operations and expertise are currently focused on conventional oil and gas production and development in the Western Canadian Sedimentary Basin, together with its participation in the Sable Offshore Energy Project. In the future, Pengrowth may acquire oil and natural gas properties outside these geographic areas. Expansion of Pengrowth’s activities into new areas may present challenges and risks that it has not faced in the past. If Pengrowth does not manage these challenges and risks successfully, its results of operations and financial condition could be adversely affected.

Delays in business operations could adversely affect the Trust’s distributions to Unitholders and the market price of the Trust Units.

In addition to the usual delays in payment by purchasers of oil and natural gas to the operators of Pengrowth’s properties, and the delays of those operators in remitting payment to Pengrowth, payments between any of these parties may also be delayed by:

• restrictions imposed by lenders;

• accounting delays;

• delays in the sale or delivery of products;

• delays in the connection of wells to a gathering system;

• blowouts or other accidents;

• adjustments for prior periods;

• recovery by the operator of expenses incurred in the operation of the properties; or

• the establishment by the operator of reserves for these expenses.

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Any of these delays could reduce the amount of cash available for distribution to Unitholders in a given period and expose Pengrowth to additional third party credit risks.

Changes in market-based factors may adversely affect the trading price of the Trust Units.

The market price of our Trust Units is sensitive to a variety of market based factors including, but not limited to, interest rates, foreign exchange rates and the comparability of the Trust Units to other yield-oriented securities. Any changes in these market-based factors may adversely affect the trading price of the Trust Units.

The limited liability of Unitholders is uncertain.

Notwithstanding the fact that Alberta has adopted legislation purporting to limit Unitholder liability, because of uncertainties in the law relating to investment trusts, there is a risk that a Unitholder could be held personally liable for obligations of the Trust in respect of contracts or undertakings which the Trust enters into and for certain liabilities arising otherwise than out of contracts including claims in tort, claims for taxes and possibly certain other statutory liabilities. Pengrowth has structured itself and attempted to conduct its business in a manner which mitigates the Trust’s liability exposure and where possible, limits its liability to Trust property. However, such protective actions may not completely avoid Unitholder liability. Notwithstanding Pengrowth’s attempts to limit Unitholder liability, Unitholders may not be protected from liabilities of the Trust to the same extent that a shareholder is protected from the liabilities of a corporation. Further, although the Trust has agreed to indemnify and hold harmless each Unitholder from any costs, damages, liabilities, expenses, charges and losses suffered by a Unitholder resulting from or arising out of the Unitholder not having limited liability, Pengrowth cannot assure prospective investors that any assets would be available in these circumstances to reimburse Unitholders for any such liability. Legislation that purports to limit Unitholder liability has been implemented in Alberta but there is no assurance that such legislation will eliminate all risk of Unitholder liability. Additionally, the legislation does not affect the liability of Unitholders with respect to any act, default, obligation or liability that arose prior to July 1, 2004.

The redemption right of Unitholders is limited.

Unitholders have a limited right to require the Trust to repurchase Trust Units, which is referred to as a redemption right. See “Description of Trust Units — Redemption Right”. It is anticipated that the redemption right will not be the primary mechanism for Unitholders to liquidate their investment. The Trust’s ability to pay cash in connection with a redemption is subject to limitations. Any securities which may be distributedin specieto Unitholders in connection with a redemption may not be listed on any stock exchange and a market may not develop for such securities. In addition, there may be resale restrictions imposed by law upon the recipients of the securities pursuant to the redemption right.

The industry in which Pengrowth operates exposes Pengrowth to potential liabilities that may not be covered by insurance.

Pengrowth’s operations are subject to all of the risks normally associated with the operation and development of oil and natural gas properties, including the drilling of oil and natural gas wells and the production and transportation of oil and natural gas. These risks and hazards include encountering unexpected formations or pressures, blow-outs, craterings and fires, all of which could result in personal injury, loss of life or environmental and other damage to Pengrowth’s property and the property of others. Pengrowth cannot fully protect against all of these risks, nor are all of these risks insurable. Pengrowth may become liable for damages arising from these events against which it cannot insure or against which it may elect not to insure because of high premium costs or other reasons. While Pengrowth has both safety and environmental policies in place to protect its operators and employees and to meet regulatory requirements in areas where they operate, any costs incurred to repair damages or pay liabilities would reduce the funds available for distribution to the Unitholders.

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MARKET FOR SECURITIES

Our Trust Units are listed on the TSX and the NYSE under the symbols “PGF.UN” and “PGH”, respectively.

	Toronto Stock Exchange								New York Stock Exchange
	Trust Unit Price Range								Trust Unit Price Range
	High		Low		Close		Volume		High		Low		Close		Volume
	(Canadian $ per Trust Unit)						(thousands)		(U.S. $ per Trust Unit)						(thousands)
2007
January		20.55		18.62		19.85		15,459		17.41		15.82		16.94		10,566
February		20.85		19.50		19.98		9,312		17.96		16.67		17.23		6,983
March		20.37		18.71		19.45		12,971		17.59		15.95		16.87		9,085
April		19.83		18.82		19.11		9,615		17.74		16.45		17.27		7,127
May		20.62		19.00		19.92		9,382		19.05		17.18		18.73		9,519
June		21.04		19.68		20.27		9,351		19.84		18.50		19.09		7,021
July		20.70		18.71		19.51		8,746		19.85		17.51		18.30		5,870
August		19.50		17.40		18.04		7,886		18.43		16.25		17.06		6,396
September		18.78		16.92		18.64		11,608		18.87		16.65		18.84		7,019
October		18.68		17.65		18.00		8,144		19.10		17.90		18.92		5,681
November		18.45		17.00		18.11		8,417		19.21		17.70		18.13		5,239
December		18.50		17.31		17.62		6,998		18.24		17.30		17.77		3,060

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Our Debentures are listed on the TSX under the symbol “PGF.DB”.

	Toronto Stock Exchange
	Debenture Price Range
	High		Low		Close		Volume
	(Canadian $ per Debenture)						(thousands)
2007
January		102.49		98.51		101.01		1,738
February		102.25		101.00		101.25		828
March		102.55		100.00		100.51		767
April		102.55		99.77		102.00		661
May		104.00		100.60		101.10		279
June		102.50		100.00		100.51		494
July		102.99		100.03		100.04		327
August		100.02		98.00		99.50		590
September		99.75		98.50		99.00		560
October		100.80		99.00		99.75		518
November		101.00		98.50		99.50		633
December		102.89		98.00		100.00		1,149.3

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DIRECTORS AND OFFICERS

The Trust does not have any directors or officers. The following is a summary of information relating to the directors and officers respectively of Pengrowth Management, Manager of the Corporation and the Trust, and of the Corporation, the administrator of the Trust.

Directors and Officers of the Manager

The name, jurisdiction of residence, position held and principal occupation of each director and officer of Pengrowth Management are set out below:

Name and Jurisdiction	Position with
of Residence	Pengrowth Management	Principal Occupation
James S. Kinnear Alberta, Canada	President and Director (since 1982)	President Pengrowth Management Limited
Gordon M. Anderson Alberta, Canada	Vice President, Financial Services (since 2001) Vice President, Treasurer (1998-2001) Treasurer (1995-1998)	Vice President, Financial Services Pengrowth Management Limited
Grant A. Henschel Alberta, Canada	Vice President, Engineering	Vice President, Engineering Pengrowth Management Limited
Leslie F. Kende Alberta, Canada	Vice President, New Ventures	Vice President, New Ventures Pengrowth Management Limited
Robert M. Nicolay Alberta, Canada	Vice President, Business Development	Vice President, Business Development Pengrowth Management Limited
Charles V. Selby Alberta, Canada	Corporate Secretary (since 1993) Treasurer	President Selby Professional Corporation

Each of the foregoing director and officers has had the same principal occupation for the previous five years except for Grant Henschel, who was Senior Associate at Sproule Associates Limited from 2002 to 2004, Leslie Kende, who was Senior Strategic Planner for BP Canada from 2001 to 2003 and Vice President and Director, Acquisitions and Divestitures at Tristone Capital Inc. from 2003 to 2007, and Robert Nicolay, who was Chief Executive Officer of ENMAX Corporation from 1999 to 2005 and President and Chief Executive Officer of the Calgary Olympic Development Association from 2005 to 2007.

Principal Holders of Shares of the Manager

James S. Kinnear, President and a director of Pengrowth Management 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 Pengrowth Management.

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Directors and Officers of the Corporation

The name, jurisdiction of residence, position held and principal occupation of each director and officer of the Corporation are set out below:

			Trust Units
			Controlled or
Name and Jurisdiction	Position with		Beneficially
of Residence	Pengrowth Corporation	Principal Occupation	Owned(1)
James S. Kinnear	President, Chairman, Director and	President		5,996,238
Alberta, Canada	Chief Executive Office (since 1988)	Pengrowth Management Limited
Thomas A. Cumming(2)(4)(5)	Director (since 2000)	Business Consultant		8,678
Alberta, Canada
Wayne K. Foo(2)(3)	Director (since 2006)	President		3,843
Alberta, Canada		Petro Andina Resources Ind.
Kirby L. Hedrick(2)(5)	Director (since 2005)	Business Consultant		4,000
Wyoming, United States of America
Michael S. Parrett(3)(4)(5)	Director (since 2004)	Business Consultant		4,000
Ontario, Canada
A. Terence Poole(3)(5)	Director (since 2005)	Business Consultant		30,000
Alberta, Canada
D. Michael G. Stewart(2)(4)	Director (since 2006)	Principal of the Ballinacurra Group,		13,370
Alberta, Canada		Corporate Director
Nicholas C.H. Villiers	Director (since 2007)	Business Consultant		—
London, England
John B. Zaozirny(3)(4)	Director (since 1988)	Counsel, McCarthy Tétrault		35,100
Alberta, Canada		Barristers and Solicitors
Gordon M. Anderson	Vice President (since 2001)	Vice President, Financial Services		21,066
Alberta, Canada	Vice President, Treasurer (1997-2001)	Pengrowth Management Limited
	Treasurer (1995-1997)
	Chief Financial Officer (1991-1998)
Douglas C. Bowles	Vice President and Controller	Vice President and Controller		11,446
Alberta, Canada	(since March 1, 2006)	Pengrowth Corporation
	Controller (since 2005)
James E.A. Causgrove	Vice President, Production and	Vice President, Production and		23,621
Alberta, Canada	Operations (since 2005)	Operations Pengrowth Corporation
Peter Cheung	Vice President (since 2008)	Vice President and Treasurer		17,428
Alberta, Canada	Treasurer (since 2005)	Pengrowth Corporation
William G. Christensen	Vice President, Strategic Planning and	Vice President, Strategic		15,821
Alberta, Canada	Reservoir Exploitation (since 2005)	Planning and Reservoir Exploitation Pengrowth Corporation
James M. Donihee	Vice-President and Chief of Staff	Vice-President and Chief of Staff		7,086
Alberta, Canada	(since 2007)	Pengrowth Corporation

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			Trust Units
			Controlled or
Name and Jurisdiction	Position with		Beneficially
of Residence	Pengrowth Corporation	Principal Occupation	Owned(1)
Charles V. Selby Alberta, Canada	Vice President and Corporate Secretary (since 2005)	President Selby Professional Corporation		146,916
	Corporate Secretary (since 1993)
Larry B. Strong	Vice President, Geosciences (since 2005)	Vice President, Geosciences		37,118
Alberta, Canada		Pengrowth Corporation
Christopher G. Webster	Chief Financial Officer (since 2005)	Chief Financial Officer		37,065
Alberta, Canada	Treasurer (2000 – 2005)	Pengrowth Corporation

Notes:
(1)	As at December 31, 2007 and excluding Trust Units issuable upon the exercise of outstanding options, rights or deferred entitlement units.
(2)	Member of Reserves, Operations and Environmental, Health and Safety Committee.
(3)	Member of Corporate Governance Committee.
(4)	Member of Compensation Committee.
(5)	Member of Audit Committee.

As at December 31, 2007, the foregoing directors and officers, as a group, beneficially, owned, directly or indirectly, 6,412,796 Trust Units or approximately 2.6 percent of the issued and outstanding Trust Units and held options, rights and deferred entitlement units to acquire a further 856,861 Trust Units. Assuming exercise of all options, rights and deferred entitlement units, the foregoing directors and officers, as a group, would beneficially own, directly and indirectly, 7,269,657 Trust Units or approximately 2.93 percent of the then issued and outstanding Trust Units. The information as to shares beneficially owned, not being within the knowledge of the Corporation, has been furnished by the respective individuals.

The term of each director expires at the next annual meeting of Unitholders.

Each of the foregoing directors and officers has had the same principal occupation for the previous five years except for Terry Poole who was Executive Vice President, Corporate Strategy and Development at Nova Chemicals Corporation from 2001 to 2006; Chris Webster who was Vice President, Treasurer from September 30, 2004 to 2005 and Treasurer from 2001 to September 30, 2004; Larry Strong who was Vice President Geosciences & Officer of Petrofund Corp. from 2004 to 2005 and Senior Vice President of MarkWest Resources Canada from 2001 to 2003; Bill Christensen who was Vice President Planning of Northrock Resources from 2000 to 2005; Jim Causgrove who was Manager, New Growth Opportunities of Chevron Texaco Canada from 2003 to 2005 and Senior Vice President and Chief Operating Officer of Central Alberta Midstream from 2000 to 2003; Doug Bowles who was Financial Reporting Manager from 2003 to 2005 and Senior Planning Analyst from 2001 to 2003 of ExxonMobil Canada; Peter Cheung who was an Investment Banker with RBC Capital Markets from 2000 to 2005; and James Donihee who was Chief Operating Officer of the National Energy Board (Canada) from 2003 to 2007 and prior thereto was the Vice President, Organizational Effectiveness and Military Liason at EnCana Corporation.

Corporate Cease Trade Orders or Bankruptcies

No director, executive officer or controlling security holder of Pengrowth or Pengrowth Management is, as at the date of this Annual Information Form, or has been, within the past 10 years before the date hereof, a director or executive officer of any other issuer that, while that person was acting in that capacity:

(i) was the subject of a cease trade or similar order or an order that denied the relevant company access to any exemption under securities legislation for a period of more than 30 consecutive days; or

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(ii)	was subject to an event that resulted, after the person ceased to be a director or executive officer, in the company being the subject of a cease trade or similar order or an order that denied the relevant company access to any exemption under securities legislation for a period of more than 30 consecutive days; or
(iii)	within a year of that person ceasing to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets.

Personal Bankruptcies

No director, executive officer or controlling security holder of Pengrowth or Pengrowth Management has, within the 10 years before the date hereof, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or became subject to or instituted any proceedings, arrangement or compromise with creditors, or had a receiver, receiver manager or trustee appointed to hold such person’s assets.

Penalties or Sanctions

No director, executive officer or controlling security holder of Pengrowth or Pengrowth Management has:

(i)	been subject to any penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory authority or has entered into a settlement agreement with a securities regulatory authority, other than penalties for late filing of insider reports; or
(ii)	been subject to any other penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor in making an investment decision.

AUDIT COMMITTEE

The Audit Committee is appointed annually by the Board of Directors. The responsibilities and duties of the Audit Committee are set forth in the Audit Committee Terms of Reference attached hereto as Appendix C. The following table sets forth the name of each of the current members of the Audit Committee, whether such member is independent and financially literate, as those terms are defined in Multilateral Instrument 52-110Audit Committees, and the relevant education and experience of each such member:

		Financially
Name	Independent	Literate	Relevant Education and Experience
Thomas A. Cumming	Yes	Yes	Mr. Cumming was President and Chief Executive Officer of the Alberta Stock Exchange from 1988 to 1999. His career also includes 25 years with a major Canadian bank both nationally and internationally. He is currently Chairman of Alberta’s Electricity Balancing Pool, and serves as a Director of the Alberta Capital Market Foundation. He is also a past president of the Calgary Chamber of Commerce. Mr. Cumming is a professional engineer and holds a Bachelor of Applied Science degree in Engineering and Business from the University of Toronto.
Michael S. Parrett	Yes	Yes	Mr. Parrett is currently an independent consultant providing advisory service to various companies in Canada and the United States. Mr. Parrett is Chairman of Gabriel Resources Limited, a member of the board of Fording Inc. and is serving as a Trustee for Fording Canadian Coal Trust. He was formerly President of Rio Algom Limited and prior to that Chief Financial Officer of Rio Algom and Falconbridge Limited. Mr. Parrett is a chartered accountant and holds a Bachelor of Arts in Economics from York University.

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		Financially
Name	Independent	Literate	Relevant Education and Experience
A. Terence Poole	Yes	Yes	Mr. Poole brings extensive senior financial management, accounting, capital and debt market experience to Pengrowth. He retired from Nova Chemicals Corporation in 2006 where he had held various senior management positions including Executive Vice-President, Corporate Strategy and Development. Mr. Poole currently serves on the board of directors for Methanex Corporation and Synenco Energy Inc. Mr. Poole received a Bachelor of Commerce degree from Dalhousie University and holds a Chartered Accountant designation.
Kirby L. Hedrick	Yes	Yes	Mr. Hedrick has extensive engineering and senior management experience in the United States and internationally, retiring in 2000 as Executive Vice-President, Upstream of Phillips Petroleum. He currently serves on the board of directors of Noble Energy Inc. and has recently been appointed to the Wyoming Environmental Quality Council. Mr. Hedrick received a Bachelor of Science and Mechanical Engineering degree from the University of Evansville, Indiana in 1975. He completed the Stanford Executive Program in 1997 and the Stanford Corporate Governance Program in 2003.

Principal Accountant Fees and Services

The following table provides information about the aggregate fees billed to Pengrowth for professional services rendered by KPMG LLP during fiscal 2007 and 2006:

	2007		2006
Audit Fees		1,393		980
Audit Related Fees		—		—
Tax Fees		163		138
All Other Fees		—		—
Total		1,556		1,118

Audit Fees

Audit fees consist of fees for the audit of Pengrowth’s annual financial statements and services that are normally provided in connection with statutory and regulatory filings or engagements.

Audit-Related Fees

Audit-related fees normally include due diligence reviews in connection with acquisitions, research of accounting and audit-related issues and the completion of audits required by contracts to which Pengrowth is a party.

Tax Fees

During 2007 and 2006 the services provided in this category included assistance and advice in relation to the preparation of income tax returns for Pengrowth and its subsidiaries, tax advice and planning and commodity tax consultation.

Pre-approval Policies and Procedures

Pengrowth has adopted the following policies and procedures with respect to the pre-approval of audit and permitted non-audit services to be provided by KPMG LLP. The audit committee approves a schedule which summarizes the services to be provided that the Audit Committee believes to be typical, recurring or otherwise likely to be provided by KPMG LLP. The schedule generally covers the period between the adoption of the schedule and the end of the year, but at the option of the Audit Committee, may cover a shorter or longer period.

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The list of services is sufficiently detailed as to the particular services to be provided to ensure that (i) the Audit Committee knows precisely what services it is being asked to pre-approve and (ii) it is not necessary for any member of Pengrowth’s management to make a judgment as to whether a proposed service fits within the pre-approved services. Services that arise that were not contemplated in the schedule must be pre-approved by the Audit Committee chairman or a delegate of the audit committee. The full Audit Committee is informed of the services at its next meeting.

Pengrowth has not approved any non-audit services on the basis of thede minimisexemptions. All non-audit services are pre-approved by the Audit Committee in accordance with the pre-approval policy referenced herein.

CONFLICTS OF INTEREST

There may be situations in which the interests of the Manager will conflict with those of our Unitholders. The Manager may acquire oil and natural gas properties on behalf of persons other than the Unitholders. The Manager may manage and administer such additional properties, as well as enter into other types of energy-related management and advisory activities. Accordingly, neither the Manager nor some member of its management may carry on their full-time activities on behalf of Unitholders and, when acting on behalf of others, may at times act in contradiction to or competition with the interests of Unitholders. In the event that the interests of the Manager are in conflict with those of our Unitholders, the Manager is obliged to make decisions acting in good faith, having regard to the best interests of Unitholders and in a manner that would not contravene its fiduciary obligations to Unitholders.

Although the Manager provides advisory and management services to the Corporation and the Trust, the Board of Directors supervises the management of the business and affairs of the Corporation and the Trust. As a practical matter, the Manager defers to the Board of Directors on all matters of material significance to the Unitholders. The Board of Directors makes significant operational decisions and all decisions relating to:

• the issuance of additional Trust Units;

• material acquisitions and dispositions of properties;

• material capital expenditures;

• borrowing; and

• the payment of distributable cash.

Properties may not be acquired from officers or directors of the Manager or persons not at arm’s length with such persons at prices which are greater than fair market value and properties may not be sold to officers or directors of the Manager or persons not at arm’s length with such persons at prices which are less than fair market value, in each case as established by an opinion of an independent financial advisor and approved by the independent members of the Board of Directors. There may be circumstances where certain transactions may also require the preparation of a formal valuation and the affirmative vote of Unitholders in accordance with the requirements of Ontario Securities Commission Rule 61-501Insider Bids, Issuer Bids, Going Private Transactions and Related Party Transactions.

Circumstances may arise where members of the Board of Directors serve as directors or officers of corporations which are in competition to the interests of the Corporation and the Trust. No assurances can be given that opportunities identified by such board members will be provided to the Corporation and the Trust.

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LEGAL PROCEEDINGS

Pengrowth is sometimes named as a defendant in litigation. The nature of these claims is usually related to settlement of normal operational or labor issues. The outcome of such claims against Pengrowth is not determinable at this time, however the ultimate resolution is not expected to have a materially adverse effect on Pengrowth as a whole.

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

Other than as discussed herein, there are no material interests, direct or indirect, of directors, executive officers, senior officers, any direct or indirect Unitholder of Pengrowth who beneficially owns, or who exercises control over, more than 10 percent of the outstanding Trust Units or any known associate or affiliate of such persons, in any transaction within the three most recently completed financial years or during the current financial year that has materially affected or will materially affect Pengrowth.

Mr. John Zaozirny, the lead director of the Corporation, is the Vice-Chairman of Canaccord Capital Corporation. Canaccord Capital Corporation participated as a member of the syndicate of underwriters in connection with the September 28, 2006 and December 1, 2006 equity offerings by the Trust of 23,310,000 and 24,265,000 Trust Units, respectively, and received a portion of the underwriters’ fee from each of the offerings.

INTERESTS OF EXPERTS

As of the date hereof, the partners and associates, as a group of Bennett Jones LLP beneficially own, directly or indirectly, less than 1 percent of the outstanding Trust Units. As of the date hereof, the directors and officers of GLJ, as a group, beneficially own, directly or indirectly, less than 1 percent of the outstanding Trust Units.

AUDITORS, TRANSFER AGENT AND REGISTRAR

The transfer agent and registrar for the Trust Units is Computershare Trust Company of Canada at its principal offices in the cities of Montreal, Toronto, Calgary and Vancouver in Canada and Computershare Trust Company, Inc. at its principal offices in the cities of New York, New York and Denver, Colorado in the United States. The auditors of the Trust are KPMG LLP, Chartered Accountants in Calgary, Alberta.

MATERIAL CONTRACTS

The only material contracts entered into by the Corporation or the Trust during the most recently completed financial year, or before the most recently completed financial year that is still in effect, other than during the ordinary course of business, are as follows:

1.	Trust Indenture;
2.	Royalty Indenture;
3.	Unanimous Shareholders Agreement;
4.	Management Agreement;
5.	the Fifth Amended and Restated Credit Agreement dated June 17, 2007 between Pengrowth and a syndicate of eleven financial institutions concerning the Credit Facility;
6.	the Bridge Credit Agreement dated January 22, 2007 between Pengrowth and a syndicate of ten financial institutions entered into in conjunction with the CP Acquisition;
7.	the Acquisition Agreement dated November 28, 2006 in connection with the CP Acquisition;

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8.	the Note Purchase Agreement dated July 26, 2007 concerning the 2007 U.S. Senior Notes;
9	the Note Purchase Agreement dated April 23, 2003 concerning the 2003 U.S. Senior Notes;
10.	the Note Purchase Agreement dated December 1, 2005 concerning the U.K. Senior Notes;
11.	the Debenture Indenture;
12.	the first supplemental trust indenture relating to the Debentures dated October 2, 2006; and
12.	the Distribution Agreement.

Copies of these contracts have been filed by the Trust on SEDAR and are available through the SEDAR website at www.sedar.com.

CODE OF ETHICS

Pengrowth has adopted a code of ethics, as that term is defined in Form 40-F under theU.S. Securities Exchange Act of 1934(the “Code of Ethics”) that applies to Pengrowth’s management, including its Chief Executive Officer, Chief Financial Officer and principal accounting officer. The Code of Ethics is available for viewing on our websitewww.pengrowth.com, and is available in print to any Unitholder who requests it.

The Board of Directors approved changes to the previously approved Code of Business Conduct and Ethics (“Code”) on February 19, 2008. The new Code does not detract from any of the requirements of the prior code and is more encompassing than the old code. All employees are being requested to accept the new Code in writing.

During the year ended December 31, 2007, Pengrowth has not granted any waivers (including implicit waivers) from the terms thereof in respect of its Chief Executive Officer, Chief Financial Officer and principal accounting officer.

OFF-BALANCE SHEET ARRANGEMENTS

Pengrowth has no off-balance sheet arrangements except for forward and future contracts disclosed in the notes to the financial statements and operating leases.

DISCLOSURE PURSUANT TO THE REQUIREMENTS
OF THE NEW YORK STOCK EXCHANGE

As a Canadian reporting issuer with securities listed on the TSX, Pengrowth has in place a system of corporate governance practices which complies with Canadian securities laws and the TSX corporate governance guidelines as well as the corporate governance rules of the NYSE applicable to foreign private issuers. In the context of its listing on the New York Stock Exchange, Pengrowth is classified as a foreign private issuer and therefore only certain of the NYSE rules are applicable to Pengrowth. However, Pengrowth benchmarks its policies and procedures against major North American entities, with a view to adopting the best practices when appropriate to its circumstances.

The Board of Directors of the Corporation has formerly adopted and published a Corporate Governance Policy which affirms Pengrowth’s commitment to maintaining a high standard of corporate governance. This policy is published on Pengrowth’s website at www.pengrowth.com. The Board of Directors of the Corporation has also adopted an Audit Committee Charter, Corporate Governance Committee Terms of Reference, Compensation Committee Terms of Reference, Reserves, Operations and Environment, Health and Safety Committee Terms of Reference, a Code of Business Conduct, a Corporate Disclosure Policy, an Insider Trading Policy and a Whistle Blower Policy each of which is published on Pengrowth’s website, and is available in print to any Unitholder who

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requests it. The Audit Committee Charter is also attached hereto as Appendix C. From time to time, special committees of the Board of Directors are formed with prescribed mandates.

There is only one significant way in which Pengrowth’s corporate governance practices differ from those required to be followed by domestic United States issuers under the NYSE Listed Company Manual. The NYSE Listed Company Manual requires shareholder approval of all equity compensation plans and any material revisions to such plans, regardless of whether the security is to be delivered under such plans are newly issued or purchased on the open market, subject to a few limited exceptions. In contrast, the TSX rules require shareholder approval of equity compensation plans only when such plans involve newly issued securities. If the plan provides a procedure for its amendment, the TSX rules require shareholder approval of amendments only where the amendment involves a reduction in the exercise price or an extension of the term of options held by insiders. As a matter or practice, Pengrowth has obtained the approval of its Unitholders to all of its equity compensation plans, regardless of whether the Trust Units to be delivered under such plans are newly issued or purchased on the open market with the exception of the Trust Unit Award Plan which was implemented as an employee retention mechanism in a very tight prevailing market in the Canadian oil and gas industry.

ADDITIONAL INFORMATION

Additional information, including the Manager’s remuneration and the principal holders of Trust Units, is contained in Pengrowth’s Management Information Circular dated May 1, 2007, which relates to the Annual and Special Meeting of Unitholders held on June 11, 2007. Pengrowth’s next meeting of Unitholders is scheduled to take place in the second quarter of 2008. A current management information circular will be prepared and distributed not less than 20 days before the date of such meeting. Additional financial information is contained in the Trust’s comparative consolidated financial statements for the years ended December 31, 2007 and 2006 which are included in the Trust’s Annual Report for the year ended December 31, 2007.

Additional information relating to Pengrowth Energy Trust may be found on SEDAR at www.sedar.com.

For additional copies of the Annual Information Form and the materials listed in the preceding paragraphs please contact:

Investor Relations	Toronto Investor Relations
Pengrowth Energy Trust	Scotia Plaza, 40 King Street West
Suite 2100, 222 – 3rd Avenue S.W.	Suite 3006, Box 106
Calgary, Alberta T2P 0B4	Toronto, Ontario M5H 3Y2
Telephone: (403) 233-0224	Telephone: (416) 362-1748
(888) 744-1111	(888) 744-1111
Fax: (866) 341-3586

Website:www.pengrowth.com
E-mail:investorrelations@pengrowth.com

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APPENDIX A

Report On Reserves Data By Independent

Qualified Reserves Evaluator On Form 51-101F2

FORM 51-101F2
REPORT ON RESERVES DATA
BY
INDEPENDENT QUALIFIED RESERVES
EVALUATOR OR AUDITOR

To the board of directors of Pengrowth Corporation (the “Company”):

1.	We have prepared an evaluation of the Company’s reserves data as at December 31, 2007. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2007, estimated using forecast prices and costs.
2.	The reserves data are the responsibility of the Company’s management. Our responsibility is to express an opinion on the reserves data based on our evaluation.
	We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”) prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society).
3.	Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions in the COGE Handbook.
4.	The following table sets forth the estimated future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Company evaluated by us for the year ended December 31, 2007, and identifies the respective portions thereof that we have audited, evaluated and reviewed and reported on to the Company’s board of directors:

	Description and
	Preparation Date	Location of Reserves	Net Present Value of Future Net Revenue
Independent Qualified	of Evaluation	(Country or Foreign	(before income taxes, 10% discount rate - $MM)
Reserves Evaluator	Report	Geographic Area)	Audited	Evaluated	Reviewed	Total
GLJ Petroleum Consultants	January 15, 2008	Canada	—	$5,456	—	$5,456

5.	In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook.
6.	We have no responsibility to update our reports referred to in paragraph 4 for events and circumstances occurring after their respective preparation dates.

7. Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material.

However, any variations should be consistent with the fact that reserves are categorized according to the probability of their recovery.

EXECUTED as to our report referred to above:

GLJ Petroleum Consultants Ltd., Calgary, Alberta, Canada, September 15, 2008

(signed)“Doug R. Sutton”

Doug R. Sutton, P.Eng.

Vice-President

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APPENDIX B

Report Of Management And Directors On

Oil And Gas Disclosure On Form 51-101F3

FORM 51-101F3
REPORT OF
MANAGEMENT AND DIRECTORS
ON OIL AND GAS DISCLOSURE

Management of Pengrowth Corporation (the “Company”) are responsible for the preparation and disclosure of information with respect to the oil and gas activities of Pengrowth Energy Trust (the “Pengrowth Trust”) in accordance with securities regulatory requirements. This information includes reserves data which are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2007, estimated using forecast prices and costs.

An independent qualified reserves evaluator has evaluated the Company’s reserves data. The report of the independent qualified reserves evaluator will be filed with securities regulatory authorities concurrently with this report.

The Reserves, Operations and Environmental, Health and Safety Committee of the board of directors of the Company has

(a) reviewed the Company’s procedures for providing information to the independent qualified reserves evaluator;

(b)	met with the independent qualified reserves evaluator to determine whether any restrictions affected the ability of the independent qualified reserves evaluator to report without reservation; and
(c)	reviewed the reserves data with management and the independent qualified reserves evaluator.

The Reserves, Operations and Environmental, Health and Safety Committee of the board of directors has reviewed the Company’s procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with management. The board of directors has, on the recommendation of the Reserves, Operations and Environmental, Health and Safety Committee, approved

(a) the content and filing with securities regulatory authorities of Form 51-101F1 containing reserves data and other oil and gas information;

(b)	the filing of Form 51-101F2 which is the report of the independent qualified reserves evaluator on the reserves data; and
(c)	the content and filing of this report.

Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material. However, any variations should be consistent with the fact that reserves are categorized according to the probability of their recovery.

(signed) “James S. Kinnear”

James S. Kinnear

Chairman, President and Chief Executive Officer

Pengrowth Corporation

(signed) “William G. Christensen”

William G. Christensen

Vice President, Strategic Planning and Reservoir Exploitation

Pengrowth Corporation

(signed) “Kirby L. Hedrick”

Kirby L. Hedrick

Director

Pengrowth Corporation

(signed) “D. Michael G. Stewart”

D. Michael G. Stewart

Director

Pengrowth Corporation

September 15, 2008

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APPENDIX C

Audit Committee Terms of Reference

TERMS OF REFERENCE
AUDIT COMMITTEE

PENGROWTH CORPORATION
PENGROWTH ENERGY TRUST

Objectives

The Audit Committee is appointed by the board of directors (the “Board”) of Pengrowth Corporation (the “Corporation”) to assist the Board in fulfilling its oversight responsibilities. The Corporation is the administrator of Pengrowth Energy Trust (the “Trust”), an unincorporated energy investment trust settled pursuant to the terms of an amended and restated trust indenture originally dated December 2, 1988 and amended and restated June 11, 2007 (the “Trust Indenture”). The Trust and the Corporation, together with any subsidiaries or affiliates of the Trust, are collectively referred to as “Pengrowth”.

The Audit Committee’s primary duties and responsibilities are to:

• monitor the performance of Pengrowth’s internal audit function and the integrity of Pengrowth’s financial reporting process and systems of internal controls regarding finance, accounting, and legal compliance;

• assist Board oversight of: (i) the integrity of Pengrowth’s financial statements; (ii) Pengrowth’s compliance with legal and regulatory requirements; and (iii) the performance of Pengrowth’s internal audit function and independent auditors;

• monitor the independence, qualification and performance of Pengrowth’s external auditors; and

• provide an avenue of communication among the external auditors, the internal auditors, management and the Board.

The Audit Committee will continuously review and modify its terms of reference with regards to, and to reflect changes in, the business environment, industry standards on matters of corporate governance, additional standards which the Audit Committee believes may be applicable to Pengrowth’s business, the location of Pengrowth’s business and its unitholders and the application of laws and policies.

Composition

Audit Committee members must meet the requirements of applicable securities laws and each of the stock exchanges on which the units of the Trust trade. The Audit Committee will be comprised of three or more directors as determined by the Board. Each member of the Audit Committee shall be “independent” and “financially literate”, as those terms are defined in Multilateral Instrument 52-110Audit Committees(“MI 52-110”) of the Canadian Securities Administrators (as set out in Schedule “A” hereto), Rule 10A-3 promulgated under theSecurities Exchange Act of 1934(as set out in Schedule “B” hereto), and Rule 303A.02 of the New York Stock Exchange (as set out in Schedule “C” hereto), as applicable, and as “financially literate” is interpreted by the Board in its business judgement. In addition, at least one member of the Audit Committee must have accounting or related financial management expertise as defined by paragraph (8) of general instruction B to Form 40-F and as interpreted by the Board in its business judgement.

Audit Committee members shall be appointed annually by the Board. The Chair of the Audit Committee shall be appointed by the Board. If an Audit Committee Chair is not designated or present, the members of the Audit Committee may designate a Chair by majority vote of the Audit Committee membership.

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Meetings and Minutes

The Audit Committee shall meet at least four times annually, or more frequently if determined necessary to carry out its responsibilities.

A meeting may be called by the Chairman of the Audit Committee, the Chief Executive Officer of the Corporation or any member of the Audit Committee. A notice of time and place of every meeting of the Audit Committee shall be given in writing to each member of the Audit Committee at least two business days prior to the time fixed for such meeting, unless waived by all members entitled to attend. Attendance of a member of the Audit Committee at a meeting shall constitute waiver of notice of the meeting except where a member attends a meeting for the express purpose of objecting to the transaction of any business on the grounds that the meeting was not lawfully called.

A quorum for meetings of the Audit Committee shall require a majority of its members present in person or by telephone. If the Chairman of the Audit Committee is not present at any meeting of the Audit Committee, one of the other members of the Audit Committee present at the meeting will be chosen to preside by a majority of the members of the Audit Committee present at that meeting.

The President and Chief Executive Officer of the Corporation shall be available to advise the Audit Committee, shall receive notice of meetings and may attend meetings of the Audit Committee at the invitation of the Chair. Other management representatives, as well as Pengrowth’s internal and external auditors, shall be invited to attend as necessary. Notwithstanding the foregoing, the Chair of the Audit Committee shall holdin camerasessions, without management present, at every meeting of the Committee.

Decisions of the Audit Committee shall be determined by a majority of the votes cast.

The Audit Committee shall appoint a member of the Audit Committee or other officer of Pengrowth to act as secretary at each meeting for the purpose of recording the minutes of each meeting.

The Audit Committee shall provide the Board with a summary of all meetings together with a copy of the minutes from such meetings. Where minutes have not yet been prepared, the Chair shall provide the Board with oral reports on the activities of the Audit Committee. All information reviewed and discussed by the Audit Committee at any meeting shall be referred to in the minutes and made available for examination by the Board upon request to the Chair.

Scope, Duties and Responsibilities

Mandatory Duties

Review Procedures

Pursuant to the requirements of MI 52-110 and other applicable laws, the Audit Committee will:

1.

Review and reassess the adequacy of the Audit Committee’s Terms of Reference at least annually, submit the Terms of Reference to the Board for approval and have the document published at least every three years in accordance with the regulations of the United States’ Securities and Exchange Commission.

2.

Prior to filing or public distribution, review, discuss with management and the internal and external auditors and recommend to the Board for approval, Pengrowth’s audited annual financial statements, annual earnings press releases, annual information form, all statements including the related management’s discussion and analysis required in prospectuses and other offering memoranda, financial statements required by regulatory authorities, all prospectuses and all documents which may

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be incorporated by reference into a prospectus, including without limitation, the annual proxy circular. Approve, on behalf of the Board, Pengrowth’s interim financial statements and related management’s discussion and analysis and interim earnings press releases. This review should include discussions with management, the internal auditors and the external auditors of significant issues regarding accounting principles, practices and judgements. Discuss any significant changes to Pengrowth’s accounting principles and any items required to be communicated by the external auditors in accordance with Assurance and Related Services Guideline #11 (AuG-11).

3. Ensure that adequate procedures are in place for the review of Pengrowth’s public disclosure of financial information extracted or derived from Pengrowth’s financial statements, other than the public disclosure referred to in paragraph 2 above and periodically assess the adequacy of those procedures.

4. Be responsible for reviewing the disclosure contained in Pengrowth’s annual information form as required by Form 52-110F1 Audit Committee Information Required in an AIF, attached to MI 52-110. If proxies are solicited for the election or directors of the Corporation, the Audit Committee shall be responsible for ensuring that Pengrowth’s information circular includes a cross-reference to the sections in Pengrowth’s annual information form that contain the information required by Form 52-110F1.

External Auditors

1.	The Audit Committee shall advise the external auditors of their accountability to the Audit Committee and the Board as representatives of the unitholders of the Trust to whom the external auditors are ultimately responsible. The external auditors shall report directly to the Audit Committee. The Audit Committee is directly responsible for overseeing the work of the external auditors, shall review at least annually the independence and performance of the external auditors and shall annually recommend to the Board the appointment of the external auditors or approve any discharge of auditors when circumstances warrant. The Audit Committee shall, on an annual basis, obtain and review a report by the external auditor describing: (i) the external auditor’s internal quality-control procedures; (ii) any material issues raised by the most recent internal quality-control review, or peer review, of the external auditors, or by any inquiry or investigation by governmental or professional authorities, within the preceding five years, respecting one or more independent audits carried out by the external auditors, and any steps taken to deal with any such issues; and (iii) all relationships between the independent auditor and Pengrowth.
2.	Approve the fees and other compensation to be paid to the external auditors.
3.	Pre-approve all services to be provided to Pengrowth or its subsidiary entities by Pengrowth’s external auditors and all related terms of engagement.

Other Audit Committee Responsibilities

4.	Establish procedures for: (i) the receipt, retention and treatment of complaints received by Pengrowth regarding accounting, internal accounting controls, or auditing matters; and (ii) the confidential and anonymous submission by employees of Pengrowth of concerns regarding questionable accounting or auditing matters.
5.	Review and approve Pengrowth’s hiring policies regarding partners, employees and former partners and employees of the present and former external auditors of Pengrowth.

Discretionary Duties

The Audit Committee’s responsibilities may, at the Audit Committee’s discretion, also include the following:

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Review Procedures

1.	In consultation with management, the internal auditors and the external auditors, consider the integrity of Pengrowth’s financial reporting processes and controls and the performance of Pengrowth’s internal financial accounting staff; discuss significant financial risk exposures and the steps management has taken to monitor, control and report such exposures; and review significant findings prepared by the internal or external auditors together with management’s responses.
2.	Review with financial management, the internal auditors and the external auditors Pengrowth’s policies relating to risk management and risk assessment.
3.	Meet separately with each of management, the internal auditors and the external auditors to discuss difficulties or concerns, specifically: (i) any difficulties encountered in the course of the audit work, including any restrictions on the scope of activities or access to requested information, and any significant disagreements with management; (ii) any changes required in the planned scope of the audit; and (iii) the responsibilities, budget, and staffing of the internal audit function, and report to the Board on such meetings.
4.	Conduct an annual performance evaluation of the Audit Committee.

Internal Auditors

1.	Review the annual audit plans of the internal auditors.
2.	Review the significant findings prepared by the internal auditors and recommendations issued by any external party relating to internal audit issues, together with management’s response.
3.	Review the adequacy of the resources of the internal auditors to ensure the objectivity and independence of the internal audit function.
4.	Consult with management on management’s appointment, replacement, reassignment or dismissal of the internal auditors.
5.	Ensure that the internal auditors have access to the Lead Director, the Chair of the Board and the Chief Executive Officer.

External Auditors

1.	On an annual basis, the Audit Committee should review and discuss with the external auditors all significant relationships they have with Pengrowth that could impair the auditors’ independence.
2.	The Audit Committee shall review the external auditors audit plan – discuss scope, staffing, locations, and reliance upon management and general audit approach.
3.	Consider the external auditors’ judgments about the quality and appropriateness of Pengrowth’s accounting principles as applied in its financial reporting.
4.	Be responsible for the resolution of disagreements between management and the external auditors regarding financial performance.
5.	Ensure compliance by the external auditors with the requirements set forth in National Instrument 52-108Auditor Oversight.

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6.

Ensure that the external auditors are participants in good standing with the Canadian Public Accountability Board (“CPAB”) and participate in the oversight programs established by the CPAB from time to time and that the external auditors have complied with any restrictions or sanctions imposed by the CPAB as of the date of the applicable auditor’s report relating to Pengrowth’s annual audited financial statements.

7.

Monitor compliance with the lead auditor rotation requirements of Regulation S-X.

Other Audit Committee Responsibilities

1.	On at least an annual basis, review with Pengrowth’s counsel any legal matters that could have a significant impact on the organization’s financial statements, Pengrowth’s compliance with applicable laws and regulations, and inquiries received from regulators or governmental agencies.
2.	Annually prepare a report to unitholders as required by the United States’ Securities and Exchange Commission; the report should be included in Pengrowth’s annual proxy statement.
3.	Ensure the preparation and filing of each annual certificate in Form 52-109F1 and each interim certificate in Form 52-109F2 to be signed by each of the Chief Executive Officer and Chief Financial Officer of the Corporation in accordance with the requirements set forth under Multilateral Instrument 52-109Certification of Disclosure in Issuers’ Annual and Interim Filings, as amended from time to time (“MI 52-109”).
4.	In respect of annual filings only, the Audit Committee is responsible for ensuring that management evaluates the effectiveness of Pengrowth’s disclosure controls and procedures as of the end of the period covered by the annual filings and has caused Pengrowth to disclose in the annual management’s discussion and analysis its conclusions about the effectiveness of the disclosure controls and procedures as of the end of the period covered by the annual filings based on such evaluation. The terms “annual filings,” “interim filings,” “disclosure controls and procedures” and “internal control over financial reporting” shall have the meanings set forth under MI 52-109.
5.	Be responsible for monitoring any changes in Pengrowth’s internal control over financial reporting and for ensuring that any change that occurred during Pengrowth’s most recent interim period that has materially affected, or is reasonably likely to materially affect, Pengrowth’s internal control over financial reporting is disclosed in Pengrowth’s most recent annual or interim management’s discussion and analysis.
6.	Review all exceptions to established policies, procedures and internal controls of Pengrowth, which have been approved by any two officers of the Corporation.
7.	Perform any other activities consistent with this Charter, the Trust Indenture, the Corporation’s by-laws, and other governing law as the Audit Committee or the Board deems necessary or appropriate.
8.	Maintain minutes of meetings and periodically report to the Board on significant results of the foregoing activities.

Communication,Authority to Engage Advisors and Expenses

The Audit Committee shall have direct access to such officers and employees of Pengrowth, to Pengrowth’s internal and external auditors and to any other consultants or advisors, as well as to such information respecting Pengrowth it considers necessary to perform its duties and responsibilities.

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Any employee may bring before the Audit Committee, on a confidential basis, any concerns relating to matters over which the Audit Committee has oversight responsibilities.

The Audit Committee has the authority to engage the external auditors, independent counsel and other advisors as it determines necessary to carry out its duties and to set the compensation for any auditors, counsel and other advisors, such engagement to be at Pengrowth’s expense. Pengrowth shall be responsible for all other expenses of the Audit Committee that are deemed necessary or appropriate by the Audit Committee in order to carry out its duties.

Adopted by the Board of the Corporation, as administrator of the Trust, on March 3, 2008.

A-1

Schedule “A”

Excerpt from Multilateral Instrument 52-110

Standard of “Independence”

1. An audit committee member is independent if he or she has no direct or indirect material relationship with Pengrowth.

2. For the purposes of paragraph 1, a “material relationship” is a relationship which could, in the view of the Board, be reasonably expected to interfere with the exercise of a member’s independent judgment.

3. Despite paragraph 2, the following individuals are considered to have a material relationship with Pengrowth:

(a)	an individual who is, or has been within the last three years, an employee or executive officer of Pengrowth;
(b)	an individual whose immediate family member is, or has been within the last three years, an executive officer of Pengrowth;
(c)	an individual who:

(i)	is a partner of a firm that is Pengrowth’s internal or external auditor,
(ii)	is an employee of that firm, or
(iii)	was within the last three years a partner or employee of that firm and personally worked on Pengrowth’s audit within that time;

(d) an individual whose spouse, minor child or stepchild, or child or stepchild who shares a home with the individual:

(i)	is a partner of a firm that is Pengrowth’s internal or external auditor,
(ii)	is an employee of that firm and participates in its audit, assurance or tax compliance (but not tax planning) practice, or
(iii)	was within the last three years a partner or employee of that firm and personally worked on Pengrowth’s audit within that time;

(e)	an individual who, or whose immediate family member, is or has been within the last three years, an executive officer of an entity if any of Pengrowth’s current executive officers serves or served at that same time on the entity’s compensation committee; and
(f)	an individual who received, or whose immediate family member who is employed as an executive officer of Pengrowth received, more than $75,000 in direct compensation from the issuer during any 12 month period within the last three years.

4. Despite paragraph 3, an individual will not be considered to have a material relationship with Pengrowth solely because he or she had a relationship identified in paragraph 3 if that relationship ended before March 30, 2004.

A-2

5. For the purposes of paragraphs 3(c) and 3(d), a partner does not include a fixed income partner whose interest in the firm that is the internal or external auditor is limited to the receipt of fixed compensation (including deferred compensation) for prior service with that firm if the compensation is not contingent in any way on continued service.

6. For the purposes of paragraph 3(f), direct compensation does not include

(a)	remuneration for acting as a member of the Board or any Board committee of Pengrowth, and
(b)	the receipt of fixed amounts of compensation under a retirement plan (including deferred compensation) for prior service with Pengrowth if the compensation is not contingent in any way on continued service.

7. Despite paragraph 3, an individual will not be considered to have a material relationship with Pengrowth solely because the individual or his or her immediate family member

(a)	has previously acted as an interim chief executive officer of Pengrowth, or
(b)	acts, or has previously acted, as a chair or vice-chair of the Board or of any Board committee of Pengrowth on a part-time basis.

8. Despite any determination made under paragraphs 1 through 7, an individual who

(a)	accepts, directly or indirectly, any consulting, advisory or other compensatory fee from Pengrowth, other than as remuneration for acting in his or her capacity as a member of the Board or any Board committee, or as a part-time chair or vice-chair of the Board or any Board committee; or
(b)	is an affiliated entity of Pengrowth or any of its subsidiary entities, is considered to have a material relationship with Pengrowth.

9. For the purposes of paragraph 8, the indirect acceptance by an individual of any consulting, advisory or other compensatory fee includes acceptance of a fee by

(a)

an individual’s spouse, minor child or stepchild, or a child or stepchild who shares the individual’s home; or

(b)

an entity in which such individual is a partner, member, an officer such as a managing director occupying a comparable position or executive officer, or occupies a similar position (except limited partners, non-managing members and those occupying similar positions who, in each case, have no active role in providing services to the entity) and which provides accounting, consulting, legal, investment banking or financial advisory services to Pengrowth.

10. For the purposes of paragraph 8, compensatory fees do not include the receipt of fixed amounts of compensation under a retirement plan (including deferred compensation) for prior service with Pengrowth if the compensation is not contingent in any way on continued service.

Standard of “Financial Literacy”

An individual is financially literate if he or she has the ability to read and understand a set of financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to

A-3

the breadth and complexity of the issues that can reasonably be expected to be raised by Pengrowth’s financial statements.

B-1

Schedule “B”

Excerpts from Rule 10A-3 of the Securities and Exchange Act of 1934

Standard of “Independence”

b.	Required standards.
1.	Independence.

i.

Each member of the audit committee must be a member of the board of directors of the listed issuer, and must otherwise be independent; provided that, where a listed issuer is one of two dual holding companies, those companies may designate one audit committee for both companies so long as each member of the audit committee is a member of the board of directors of at least one of such dual holding companies.

ii.

Independence requirements for non-investment company issuers.In order to be considered to be independent for purposes of this paragraph (b)(1), a member of an audit committee of a listed issuer that is not an investment company may not, other than in his or her capacity as a member of the audit committee, the board of directors, or any other board committee:

A.

Accept directly or indirectly any consulting, advisory, or other compensatory fee from the issuer or any subsidiary thereof, provided that, unless the rules of the national securities exchange or national securities association provide otherwise, compensatory fees do not include the receipt of fixed amounts of compensation under a retirement plan (including deferred compensation) for prior service with the listed issuer (provided that such compensation is not contingent in any way on continued service); or

B.

Be an affiliated person of the issuer or any subsidiary thereof.

e. Definitions. Unless the context otherwise requires, all terms used in this section have the same meaning as in the Act. In addition, unless the context otherwise requires, the following definitions apply for purposes of this section:

1.

i. The termaffiliateof, or a personaffiliatedwith, a specified person, means a person that directly, or indirectly through one or more intermediaries, controls, or is controlled by, or is under common control with, the person specified.

          ii.

A. A person will be deemed not to be in control of a specified person for purposes of this section if the person:

1. Is not the beneficial owner, directly or indirectly, of more than 10% of any class of voting equity securities of the specified person; and (2) Is not an executive officer of the specified person.

B. Paragraph (e)(1)(ii)(A) of this section only creates a safe harbor position that a person does not control a specified person. The existence of the safe harbor does not create a presumption in any way that a person exceeding the ownership requirement

B-2

in paragraph (e)(1)(ii)(A)(1) of this section controls or is otherwise an affiliate of a specified person.

iii. The following will be deemed to be affiliates:

A.	An executive officer of an affiliate;
B.	A director who also is an employee of an affiliate;
C.	A general partner of an affiliate; and
D.	A managing member of an affiliate.

iv. For purposes of paragraph (e)(1)(i) of this section, dual holding companies will not be deemed to be affiliates of or persons affiliated with each other by virtue of their dual holding company arrangements with each other, including where directors of one dual holding company are also directors of the other dual holding company, or where directors of one or both dual holding companies are also directors of the businesses jointly controlled, directly or indirectly, by the dual holding companies (and, in each case, receive only ordinary-course compensation for serving as a member of the board of directors, audit committee or any other board committee of the dual holding companies or any entity that is jointly controlled, directly or indirectly, by the dual holding companies).

4.

The term control (including the terms controlling, controlled by and under common control with) means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a person, whether through the ownership of voting securities, by contract, or otherwise.

8.

The term indirect acceptance by a member of an audit committee of any consulting, advisory or other compensatory fee includes acceptance of such a fee by a spouse, a minor child or stepchild or a child or stepchild sharing a home with the member or by an entity in which such member is a partner, member, an officer such as a managing director occupying a comparable position or executive officer, or occupies a similar position (except limited partners, non-managing members and those occupying similar positions who, in each case, have no active role in providing services to the entity) and which provides accounting, consulting, legal, investment banking or financial advisory services to the issuer or any subsidiary of the issuer.

C-1

Schedule “C”

Excerpts from Rule 303A.00 of the New York Stock Exchange

303A.02 “Independence” Tests

The NYSE Listed Company Manual contains the following provisions regarding the independence requirements of members of the audit committee:

(a)	No director qualifies as “independent” unless the board of directors affirmatively determines that the director has no material relationship with the listed company (either directly or as a partner, shareholder or officer of an organization that has a relationship with the company). Companies must identify which directors are independent and disclose the basis for that determination.
(b)	In addition, a director is not independent if:

(i)	The director is, or has been within the last three years, an employee of the listed company, or an immediate family member is, or has been within the last three years, an executive officer, of the listed company.
(ii)	The director has received, or has an immediate family member who has received, during any twelve-month period within the last three years, more than $100,000 in direct compensation from the listed company, other than director and committee fees and pension or other forms of deferred compensation for prior service (provided such compensation is not contingent in any way on continued service).
(iii)	(A) The director or an immediate family member is a current partner of a firm that is the company’s internal or external auditor; (B) the director is a current employee of such a firm; (C) the director has an immediate family member who is a current employee of such a firm and who participates in the firm’s audit, assurance or tax compliance (but not tax planning) practice; or (D) the director or an immediate family member was within the last three years (but is no longer) a partner or employee of such a firm and personally worked on the listed company’s audit within that time.
(iv)	The director or an immediate family member is, or has been within the last three years, employed as an executive officer of another company where any of the listed company’s present executive officers at the same time serves or served on that company’s compensation committee.
(v)	The director is a current employee, or an immediate family member is a current executive officer, of a company that has made payments to, or received payments from, the listed company for property or services in an amount which, in any of the last three fiscal years, exceeds the greater of $1 million, or 2% of such other company’s consolidated gross revenues.

General Commentary to Section 303A.02(b):

An “immediate family member” includes a person’s spouse, parents, children, siblings, mothers and fathers-in-law, sons and daughters-in-law, brothers and sisters-in-law, and anyone (other than domestic employees) who shares such person’s home. When applying the look-back provisions in Section 303A.02(b), listed companies

C-2

need not consider individuals who are no longer immediate family members as a result of legal separation or divorce, or those who have died or become incapacitated.

For purposes of Section 303A, the term “executive officer” has the same meaning specified for the term “officer” in Rule 16a-1(f) under the Securities Exchange Act of 1934 as follows:

The term “officer” shall mean an issuer’s president, principal financial officer, principal accounting officer (or, if there is no such accounting officer, the controller), any vice-president of the issuer in charge of a principal business unit, division or function (such as sales, administration or finance), any other officer who performs a policy-making function, or any other person who performs similar policy-making functions for the issuer. Officers of the issuer’s parent(s) or subsidiaries shall be deemed officers of the issuer if they perform such policy-making functions for the issuer. In addition, when the issuer is a limited partnership, officers or employees of the general partner(s) who perform policy-making functions for the limited partnership are deemed officers of the limited partnership. When the issuer is a trust, officers or employees of the trustee(s) who perform policy-making functions for the trust are deemed officers of the trust.

EXHIBIT 1

CONSENT OF GLJ PETROLEUM CONSULTANTS LTD.

We hereby consent to the reference to us in this Amendment No. 1 to the Annual Report on Form 40-F of Pengrowth Energy Trust and all other references to my name included or incorporated by reference in: (i) Pengrowth Energy Trust’s Amendment No. 1 to the Annual Report on Form 40-F for the year ended December 31, 2007 and (ii) the Registration Statement on Form F-3 (File No. 333-143810) and the Registration Statement on Form F-10 (File No. 333-146928), filed with the United States Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended, or the Securities Act of 1933, as amended as applicable.

Date: September 15, 2008
Calgary, Alberta /s/  GLJ Petroleum Consultants Ltd.   GLJ Petroleum Consultants Ltd.

EXHIBIT 2

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED

PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

     In connection with Amendment No. 1 to the Annual Report of Pengrowth Energy Trust (the “Company”) on Form 40-F for the fiscal year ended December 31, 2007, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, James S. Kinnear, Chairman, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

1.	The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
2.	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated: September 15, 2008 /s/  James S. Kinnear   James S. Kinnear
Chairman, President and
Chief Executive Officer

EXHIBIT 3

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

     In connection with Amendment No. 1 to the Annual Report of Pengrowth Energy Trust (the “Company”) on Form 40-F for the fiscal year ended December 31, 2007, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Christopher G. Webster, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

1.	The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
2.	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated: September 15, 2008 /s/  Christopher G. Webster   Christopher G. Webster
Chief Financial Officer

EXHIBIT 4

CERTIFICATION PURSUANT TO RULE 13a-14 OR 15d-14 OF THE
SECURITIES EXCHANGE ACT OF 1934, AS ADOPTED PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, James S. Kinnear, certify that:

1.	I have reviewed this Amendment No. 1 to the annual report on Form 40-F of Pengrowth Energy Trust;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;
4.	The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c)	Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)	Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

5. The issuer’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

Dated: September 15, 2008 /s/  James S. Kinnear   James S. Kinnear
Chairman, President and
Chief Executive Officer

EXHIBIT 5

CERTIFICATION PURSUANT TO RULE 13a-14 OR 15d-14 OF THE SECURITIES
EXCHANGE ACT OF 1934, AS ADOPTED PURSUANT TO SECTION 302 OF THE

SARBANES-OXLEY ACT OF 2002

I, Christopher G. Webster, certify that:

1.	I have reviewed this Amendment No. 1 to the annual report on Form 40-F of Pengrowth Energy Trust;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;
4.	The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c)	Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)	Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

5. The issuer’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

Dated: September 15, 2008 /s/  Christopher G. Webster   Christopher G. Webster
Chief Financial Officer